20121011Lafferty DI.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-12-08
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) DIRECT TESTIMONY
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) ROBERT J. LAFFERTY
)

FOR AVISTA CORPORATION

(ELECTRIC ONLY)

Lafferty, Di 1
Avista Corporation
I. INTRODUCTION 1
Q. Please state your name, employer and business 2
address. 3
A. My name is Robert J. Lafferty. I am employed as 4
the Director of Power Supply at Avista Corporation, located 5
at 1411 East Mission Avenue, Spokane, Washington. 6
Q. Would you briefly describe your educational and 7
professional background? 8
A. Yes. I received a Bachelor of Arts degree in 9
Business Administration and a Bachelor of Science degree in 10
Electrical Engineering from Washington State University, 11
both in 1974. I began working as a distribution engineer 12
for Avista in 1974 and held several different engineering 13
positions with the Company. In 1979, I passed the 14
Professional Engineering License examination in the state 15
of Washington. I have held management positions in 16
engineering, marketing, demand-side-management and energy 17
resources. I began work in the Energy Resources Department 18
in March 1996, and have held various positions involving 19
the planning, acquisition and optimization of energy 20
resources. I became the Director of Power Supply in March 21
2008, where my primary responsibilities involve management 22
Lafferty, Di 2
Avista Corporation
and oversight of the short- and long-term planning and 1
acquisition of power resources for the Company. 2
Q. What is the scope of your testimony in this 3
proceeding? 4
A. My testimony provides an overview of Avista’s 5
resource planning and power supply operations. This 6
includes summaries of the Company’s generation resources, 7
the current and future load and resource position, and 8
future resource plans, including the power purchase 9
agreement with Palouse Wind, LLC. As part of an overview 10
of the Company’s risk management policy, I will provide an 11
update on the Company’s hedging practices. I will address 12
hydroelectric and thermal project upgrades, followed by an 13
update on recent developments regarding hydro licensing. 14
A table of contents for my testimony is as follows: 15
Description Page 16
I. Introduction 1 17
II. Resource Planning and Power Operations 3 18
III. Palouse Wind Power Purchase Agreement Acquisition 12 19
IV Generation Capital Projects 22 20
V. Hydro Relicensing 35 21
22
Q. Are you sponsoring any exhibits? 23
A. Yes. Exhibit No. 4, Schedule 1 includes Avista’s 24
2011 Electric Integrated Resource Plan and Appendices, 25
Schedule 2 provides a forecast of Company load and resource 26
Lafferty, Di 3
Avista Corporation
positions from 2013 through 2032. Confidential Schedule 3 1
includes Avista’s Energy Resources Risk Policy. Schedule 4 2
is a Map showing the location of the Palouse Wind Project. 3
Schedule 5 contains Avista’s 2009 Electric Integrated 4
Resource Plan and Appendices. Confidential Schedule 6C 5
includes presentations to the Avista Board concerning the 6
Palouse Wind project. Confidential Schedule 7C is the 2011 7
Request for Proposal Process and Results, and Confidential 8
Schedule 8C is the Palouse Wind Power Purchase Agreement. 9
10
II. RESOURCE PLANNING AND POWER OPERATIONS 11
Q. Would you please provide a brief overview of 12
Avista’s owned-generating resources? 13
A. Yes. Avista’s resource portfolio consists of 14
hydroelectric generation projects, base-load coal and 15
natural gas-fired thermal generation facilities, wood-waste 16
fired generation, natural gas-fired peaking generation, 17
long-term contracts, including wind, and Mid-Columbia 18
hydroelectric generation, and market power purchases and 19
exchanges. Avista-owned generation facilities have a total 20
capability of 1,777 MW, which includes 56% hydroelectric 21
and 44% thermal resources. 22
Lafferty, Di 4
Avista Corporation
Illustration No. 1 below summarizes the present net 1
capability of Avista’s owned-generation resources: 2
3
Illustration No. 1: Avista’s Owned-Generation 4
Avista-Owned Generation
Hydroelectric
Generation
MW Thermal
Generation
MW Natural Gas
Peaking
Generation
MW
Noxon Rapids 557 Colstrip
Units 3 & 4
222 Northeast CT 56
Cabinet Gorge 255 Coyote
Springs 2
278 Kettle Falls
CT
7
Post Falls 18 Kettle Falls 50 Boulder Park 24
Upper Falls 10 Rathdrum CT 149
Monroe Street 15
Nine Mile 18
Long Lake 83
Little Falls 35
Total
Hydroelectric
991 Total Base-
Load Thermal
550 Total Peaking 236
Total Owned
Generation
1,777 MW
5
Q. Would you please provide a brief overview of 6
Avista’s major generation contracts? 7
A. Yes. Avista’s contracted-for generation resource 8
portfolio consists of Mid-Columbia hydroelectric, PURPA, a 9
tolling agreement for a natural gas-fired generator, and 10
contracts with wind generation facilities. 11
The Company currently has long-term contractual rights 12
for 165 MW from Mid-Columbia hydroelectric projects in 13
2012, owned and operated by the Public Utility Districts of 14
Lafferty, Di 5
Avista Corporation
Chelan, Douglas and Grant counties. Details about the Mid-1
Columbia hydroelectric contracts are located in 2
Illustration No. 2 and other contracts are shown in 3
Illustration No. 3. Avista also has a long-term power 4
purchase agreement (PPA) in place entitling the Company to 5
dispatch, purchase fuel for and receive the power output 6
from the 275 MW Lancaster combined-cycle combustion turbine 7
project located in Rathdrum, Idaho. In 2011, the Company 8
executed a 105 MW power purchase agreement to purchase the 9
output and all environmental attributes from the Palouse 10
Wind, LLC wind generation project, which is under 11
construction and expected to begin generation in late 2012. 12
Details about the Palouse Wind PPA are discussed in Section 13
III of my testimony. 14
Illustration No. 2: Mid-Columbia Capacity Contracts 15
Counter Party –
Hydroelectric
Project
Start
Date
End
Date
Estimated
Capacity
(MW)
Annual
Energy
(aMW)
Grant PUD – Priest
Rapids
12/2001 12/2052 34 16
Grant PUD – Wanapum 12/2001 12/2052 37 18
Chelan PUD – Rocky
Reach
11/2011 06/2012 57 32
Chelan PUD – Rocky
Reach
7/2011 12/2014 38 21
Chelan PUD – Rock
Island
7/2011 12/2015 19 11
Douglas PUD - Wells 2/1965 8/2018 29 15
Total 165 86
16
Lafferty, Di 6
Avista Corporation
Illustration No. 3: Energy Contracts 1
Contract Contract
Type
End
Date
Winter
Capacity
(MW)
Summer
Capacity
(MW)
2012
Annual
Energy
(aMW)
Clearwater PURPA 6/2013 75 75 52
Douglas Settlement Purchase 9/2018 2 3 3
Lancaster Purchase 10/2026 290 249 222
Palouse Wind Purchase 12/2042 0 0 42
Small Power PURPA Varies 2 1 2
Stateline Purchase 3/2014 0 0 9
Stimson Lumber Purchase 11/2016 4 5 4
Upriver (net load) Purchase 12/2011 8 -1 6
Spokane Waste to
Energy
Purchase 12/2016 16 16 15
WNP-3 Purchase 6/2019 82 0 42
Total 479 348 397
2
Q. Would you please provide a summary of Avista's 3
power supply operations and acquisition of new resources? 4
A. Yes. Avista uses a combination of owned and 5
contracted-for resources to serve its load requirements. 6
The Power Supply Department is responsible for dispatch 7
decisions related to those resources for which the Company 8
has dispatch rights. The Department monitors and routinely 9
studies capacity and energy resource needs. Short- and 10
medium-term wholesale transactions are used to economically 11
balance resources with load requirements. Longer-term 12
resource decisions such as the acquisition of new 13
generation resources, upgrades to existing resources, 14
demand-side management (DSM), and long-term contract 15
Lafferty, Di 7
Avista Corporation
purchases are generally guided by the Integrated Resource 1
Plan (IRP) and will typically include a Request for 2
Proposals (RFP) and/or other market due diligence process. 3
Q. Please summarize the current load and resource 4
position for the Company. 5
A. Avista’s 2011 electric Integrated Resource Plan 6
(IRP) shows forecasted annual energy deficits beginning in 7
2019, and sustained annual capacity deficits beginning in 8
20201. These capacity and energy load/resource positions 9
are shown on pages 2-27 and 2-29, respectively of Exhibit 10
4, Schedule 1. Exhibit 4, Schedule 2 shows our most recent 11
load and resource projection. Avista’s current projection 12
shows an annual energy deficit beginning in 2019 of about 9 13
aMW, and increasing to a 467 aMW deficit in 2032. The 14
Company’s January capacity resource position, based on an 15
18-hour peak event (6 hours per day and over 3 days), is 16
currently projected to be surplus through 2022. Sustained 17
annual capacity deficiencies, based on a January peak, 18
begin at 76 MW in 2022 and increase to a 656 MW deficit in 19
2032. The Company’s August capacity resource position, 20
based on an 18-hour peak event, is currently projected to 21

1 The Company has a 150 MW capacity exchange agreement with Portland General Electric that ends in
December 2016 which results in short-term annual capacity deficits in 2015 and 2016. Sustained annual
capacity deficits begin in 2020.
Lafferty, Di 8
Avista Corporation
be surplus through 2018. Sustained annual capacity 1
deficiencies, based on an August peak, begin at 43 MW in 2
2019 and increase to a 669 MW deficit in 2032. 3
Q. How does the Company plan to meet future energy 4
and capacity needs beginning in 2020? 5
A. The Company will be guided by the 2011 Preferred 6
Resource Strategy. The current Preferred Resource Strategy 7
is described in the 2011 Electric IRP, which is attached as 8
Exhibit 4, Schedule 1. The IRP provides details about 9
resource needs, specific resource costs, resource operating 10
characteristics, and the scenarios used for evaluating the 11
mix of resources for the Preferred Resource Strategy. 12
The Company’s 2011 Electric IRP was submitted to the 13
Commission on August 26, 2011, following the completion of 14
a public process involving six Technical Advisory Committee 15
meetings from May 27, 2010 through June 23, 2011. The 16
Commission acknowledged the 2011 Electric IRP on January 17
23, 2012 in Case No. AVU-E-11-04. The IRP represents the 18
preferred plan at a point in time, however, the Company 19
continues evaluating resource options to meet future load 20
requirements, including, but not limited to, medium-term 21
market purchases, participation in hydroelectric capacity 22
auctions, generation ownership, hydroelectric upgrades, 23
Lafferty, Di 9
Avista Corporation
renewable resources, distribution efficiencies, 1
conservation measures, long-term contracts, and generation 2
lease or tolling arrangements in between IRPs. As stated 3
earlier, longer-term resource decisions are generally made 4
in conjunction with the Company's IRP and RFP processes, 5
although the Company may acquire some resources outside of 6
formal RFP processes. 7
Avista’s 2011 Preferred Resource Strategy includes 28 8
MWs of distribution efficiencies, 419 MWs of cumulative 9
energy efficiency, 4 MWs of upgrades to existing thermal 10
plants, 752 MWs of natural gas fired plants (212 MWs of 11
simple cycle and 540 MWs of combined-cycle combustion 12
turbine (CCCT)), and 240 MWs of nameplate wind located in 13
the Pacific Northwest. The timing of these resources as 14
published in the 2011 IRP is in Illustration No. 4 below. 15
16
Illustration No. 4: 2011 Electric IRP Preferred Resource 17
Strategy 18
Resource Type By the End of
Year
Nameplate
(MW)
Energy
(aMW)
Northwest Wind 2012 120 35
SCCT 2018 83 75
Thermal Upgrades 2019 4 3
Northwest Wind 2019-2020 120 35
SCCT 2020 83 75
CCCT 2023 270 237
CCCT 2026 270 237
SCCT 2029 46 42
Total 996 739
Lafferty, Di 10
Avista Corporation

Efficiency
Improvements
By the End of
Year
Peak
Reduction
(MW)
Energy
(aMW)
Distribution
Efficiencies
Energy Efficiency
Total Efficiency
1
Q. Can you provide a high-level summary of Avista’s 2
risk management program for energy resources? 3
A. Yes. Avista Utilities uses several techniques to 4
manage the risks associated with serving load and managing 5
Company-owned and controlled resources. The Energy 6
Resources Risk Policy provides general guidance to manage 7
the Company’s energy risk exposure relating to electric 8
power and natural gas resources over the long-term (more 9
than 41 months), the short-term (monthly and quarterly 10
periods up to approximately 41 months), and the immediate 11
term (present month). 12
The Energy Resources Risk Policy is not a specific 13
procurement plan for buying or selling power or natural gas 14
at any particular time, but is a guideline used by 15
management when making procurement decisions for electric 16
power and natural gas fuel for generation. Several 17
factors, including the variability associated with loads, 18
hydroelectric generation, and electric power and natural 19
Lafferty, Di 11
Avista Corporation
gas prices, are considered in the decision-making process 1
regarding procurement of electric power and natural gas for 2
generation. 3
The Company aims to strategically develop or acquire 4
long-term energy resources as suggested by the Company’s 5
Integrated Resource Plan acquisition targets, while taking 6
advantage of competitive opportunities to satisfy electric 7
resource supply needs in the long-term period. On the 8
other end of the time spectrum, electric power and fuel 9
transactions in the immediate term are driven by a 10
combination of factors that incorporate both economics and 11
operations, including near-term market conditions (price 12
and liquidity), generation economics, project license 13
requirements, load and generation variability, reliability 14
considerations, and other near-term operational factors. 15
For the short-term timeframe, which falls between the 16
long-term and immediate term periods, the Company’s Energy 17
Resources Risk Policy guides its approach to hedging 18
financially open forward positions. A financially open 19
forward period position may be the result of either a short 20
position situation, for which the Company has not yet 21
purchased the fixed price fuel to generate, or 22
alternatively purchased fixed price electric power from the 23
Lafferty, Di 12
Avista Corporation
market, to meet projected average load for the forward 1
period or a long position, for which the Company has 2
generation above its expected average load needs and has 3
not yet made a fixed price sale of that surplus to the 4
market in order to balance resources and loads. 5
The Company employs an Electric Hedging Plan to guide 6
power supply position management in the short-term period. 7
The Risk Policy Electric Hedging Plan is essentially a 8
price diversification approach employing a layering 9
strategy for forward purchases and sales of either natural 10
gas fuel for generation or electric power in order to 11
approach a generally balanced position against expected 12
load as forward periods draw nearer. 13
14
III. PALOUSE WIND POWER PURCHASE AGREEMENT ACQUISITION 15
Q. Please explain the Palouse Wind Power Purchase 16
Agreement? 17
A. The Palouse Wind Power Purchase Agreement 18
(Palouse Wind PPA) is a 30-year agreement to purchase all 19
of the generation output and all environmental benefits 20
associated with the Palouse Wind, LLC wind power project. 21
The agreement also includes a purchase option after year 22
ten. Avista’s 2009 Integrated Resource Plan (IRP) 23
Lafferty, Di 13
Avista Corporation
indicated an approximate need for 50 aMW of qualifying 1
renewable energy credits prior to 2016 in order to meet 2
Washington’s renewable portfolio standard (RPS). In early 3
2011, the 2011 IRP was well into development and identified 4
a slightly lower need level of 42 aMW of qualifying 5
renewable energy credits. In February 2011, Avista decided 6
to issue a request for proposals (RFP) that would meet the 7
Company’s 2016 need for qualifying renewable energy credits 8
prior to the December 31, 2012 expiration of federal and 9
state tax incentives and other benefits, and also take 10
advantage of the low equipment and construction costs that 11
appeared to be available at the time. The Palouse Wind 12
Project provides a 30-year long-term energy resource for 13
our electric retail customers, and is located inside our 14
utility service area. 15
Q. Please briefly describe the Palouse Wind Project. 16
A. The Palouse Wind Project consists of 58 Vestas 17
1.8 MW wind turbines that are located between Oakesdale, 18
Washington and State Route 195 and with a total capacity of 19
approximately 105 MWs. The project will be directly 20
connected to the Avista electric system and is expected to 21
begin commercial operation towards the end of 2012. 22
Lafferty, Di 14
Avista Corporation
Exhibit 4, Schedule 4 contains a map showing the location 1
of the project. 2
Q. Can you provide some background regarding why the 3
Company initiated an RFP for renewable resources in 2011. 4
A. Yes. The Company had a need for qualified 5
renewable energy beginning in 2016. Avista had continued 6
to monitor renewable resource market conditions, 7
particularly with respect to projects bid into its 2009 8
renewable resource RFP after the Company decided not to 9
select a resource out of that process. In late 2010 and 10
early 2011, Avista was made aware of a significant drop in 11
prospective project costs associated with construction of 12
new wind generation facilities that were still in position 13
to be constructed, and also take advantage of available 14
near-term tax incentives for projects brought on-line prior 15
to December 31, 2012. The material drop in project cost, 16
and the availability of significant known tax advantages 17
for renewable resource projects constructed prior to 18
December 31, 2012, were among the factors considered in the 19
Company’s decision to issue a new request for proposals 20
(RFP) for up to 35 aMW of renewable energy in February 21
2011. The 2011 renewable resource RFP sought qualifying 22
projects or project output for the 2012 – 2032 time period. 23
Lafferty, Di 15
Avista Corporation
Avista stated in the RFP that Avista would not submit a 1
self-build option. Analysis indicated that the combination 2
of the significant drop in project cost and the substantial 3
tax incentives available for renewable projects completed 4
by December 31, 2012 yielded long-term benefits for 5
customers compared to waiting until tax incentives, 6
attractive project pricing, and particular attractive wind 7
project sites may no longer be available to Avista. 8
Q. At the time of the 2011 RFP, please explain how 9
the Company determined that a new resource was necessary. 10
A. The need for the type and size of resource 11
provided by the Palouse Wind PPA was demonstrated in the 12
2009 Integrated Resource Planning process. (See Exhibit 4, 13
Schedule 5) The need was also confirmed in the 2011 IRP, 14
which was nearing completion when the Palouse Wind PPA was 15
executed. (See Exhibit 4, Schedule 1) The Company’s 2009 16
IRP, developed in conjunction with the Technical Advisory 17
Committee, showed that Avista’s first annual energy needs 18
would occur in 2018 and sustained capacity need in 2019. 19
The first projected annual REC need of 48.1 aMW identified 20
in the 2009 IRP occurred in 2016. Illustration No. 6 shows 21
Avista’s projected energy needs, capacity needs, and REC 22
needs presented in the 2009 IRP. 23
Lafferty, Di 16
Avista Corporation
Illustration No. 6: 2009 IRP Load, Resource, and REC 1
Tabulations 2
Net
Position
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Energy
(aMW)
309 185 123 110 93 59 38 31 (27) (35)
Capacity
(MW)
293 124 53 31 0 (45) (74) 45 11 (46)
REC Need
(aMW)
19.0 19.9 0.3 2.2 2.0 1.7 (48.1) (49.1) (50.3) (51.6)
3
Q. How did the Company determine the amount and type 4
of resource needed? 5
A. The Company’s energy, capacity and REC needs were 6
used as inputs to the development of the Preferred Resource 7
Strategy (PRS). The PRS is developed using a proprietary 8
linear programming model called PRiSM. The PRiSM model 9
helps select the PRS and uses: 10
1. load deficits (energy and capacity); 11
2. RPS requirements; 12
3. Avista’s existing portfolio’s costs (loads and 13
resources) and operating margins (resources); 14
4. Fixed operating costs, return on capital, 15
interest and taxes for each resource option; 16
5. Generation levels for existing resources and new 17
resource options; and 18
Lafferty, Di 17
Avista Corporation
6. Carbon emissions levels for existing resources 1
and new resource options. 2
Additional details about the development of the PRS and the 3
PRiSM model can be found in Chapter 8 of the 2009 IRP 4
(Exhibit 4, Schedule 5). The 2011 IRP used a similar 5
methodology and an updated version of the PRiSM model to 6
develop the 2011 PRS can be found in Exhibit 4, Schedule 1. 7
Q. Is this resource consistent with the 2009 8
Preferred Resource Strategy? 9
A. Yes. The 2009 PRS indicated a need for 48.0 aMW 10
of renewable energy in 2012 represented by 150 MW of 11
nameplate wind capacity. At the time of the 2011 RFP, work 12
was also well underway in the 2011 IRP. The PRS in the 13
Company’s 2011 IRP reaffirmed the need for qualifying 14
renewable resources in 2012 with requirements for 35.0 aMW 15
of qualifying renewable energy obtained through 120 MW of 16
nameplate wind capacity located in the Northwest. A 17
somewhat lower need for renewable energy in the 2011 IRP 18
was indicated based on a lower load forecast as compared to 19
the 2009 IRP and a change in planning margin criteria. A 20
higher expected capacity factor reduced further the 21
equivalent nameplate wind capacity required. 22
Lafferty, Di 18
Avista Corporation
Q. Were there other circumstances that influenced 1
the timing of the 2011 renewable resource RFP? 2
A. Following the termination of the 2009 RFP 3
process, the Company continued to receive project and cost 4
updates from some of the RFP bid developers and from other 5
projects. In early 2011, indications were that wind 6
turbine prices and project construction costs were 7
declining significantly. Avista made the decision to move 8
forward with an RFP to take advantage of the substantially 9
reduced equipment and construction costs prior to the 10
December 31, 2012 expiration of federal and state tax 11
incentives and other benefits. 12
Q. How did Avista evaluate and consider alternatives 13
to the Palouse Wind PPA? 14
A. The Company issued an RFP in February 2011, for 15
35 aMW of renewable energy to be online by the end of 2012. 16
(See Confidential Exhibit 4, Schedule 7C). The Company 17
indicated in the RFP that a self-build option would not be 18
included in the RFP process. The fast-track nature of the 19
2011 RFP did not allow for sufficient time for the Company 20
to secure equipment and construction bids for a project at 21
the Company-owned Reardan site that would fit into the RFP 22
Lafferty, Di 19
Avista Corporation
timeline and meet the December 31, 2012 federal tax credit 1
deadline. 2
On March 7, 2011, the Company received eleven 3
proposals totaling 774 MW in response to the RFP. The 4
proposals included 769 MW of wind and 5 MW of landfill gas. 5
The Company evaluated potential projects both 6
quantitatively and qualitatively against one another based 7
on predetermined criteria that had been vetted with the 8
Idaho and Washington Commission Staffs. Analysis 9
demonstrated that the highest ranked bid was the Palouse 10
Wind Project. The Palouse Wind proposal was for an 11
approximately 100 MW project located near Avista’s 12
Transmission System (30 miles south of Spokane, Washington) 13
and with an expected 39.5 percent capacity factor 14
(estimated to be about 38.4 aMW to 39 aMW depending upon 15
final turbine selection and configuration). The project 16
committed to reach commercial operation by the end of 2012 17
to qualify for federal tax benefits. 18
The RFP evaluation process included two screening 19
levels which resulted in a short list of four bidders. 20
After completion of due diligence of the short-listed 21
projects, the Palouse Wind Project was the highest overall 22
ranked resource. 23
Lafferty, Di 20
Avista Corporation
Q. How was transmission considered in this decision? 1
A. The Palouse Wind Project will be directly 2
interconnected to Avista’s system, so no third-party 3
transmission is required for this project to serve our 4
customers. At the time of the RFP, Palouse Wind had made 5
an interconnection request, and received project scope and 6
cost information from Avista transmission. Subsequently, 7
Palouse Wind signed a contract for the construction of 8
Avista transmission required for interconnection. The 9
evaluation process included the transmission 10
interconnection cost in the case of projects with proposed 11
direct interconnection with the Avista transmission system 12
or transmission and losses for projects proposed to 13
interconnect to third party transmission systems and 14
wheeling power to the Avista system. 15
Q. What documentation for the analysis and decision-16
making process has the Company provided regarding the 17
decision to enter into a contract for the Palouse Wind 18
Project? 19
A. The documentation provided concerning the 20
analysis and decision-making process regarding the decision 21
to execute a contract for the Palouse Wind Project are 22
included in the following: Exhibit 4, Schedule 1, includes 23
Lafferty, Di 21
Avista Corporation
Avista’s 2011 Electric Integrated Resource Plan and 1
Appendices; Exhibit 4, Schedule 4, is a map of the location 2
of the Palouse Wind Project; Exhibit 4, Schedule 5, is 3
Avista’s 2009 Electric Integrated Resource Plan and 4
Appendices; Confidential Exhibit 4, Schedule 6C, provides 5
the Palouse Wind Board documentation; Confidential Exhibit 6
4, Schedule 7C, provides details about the 2011 Renewables 7
Request for Proposal process and results; and Confidential 8
Exhibit 4, Schedule 8C, contains the Palouse Wind Power 9
Purchase Agreement. 10
Q. Does the Company believe that the Palouse Wind 11
PPA was a prudent acquisition? 12
A. Yes. My testimony and exhibits demonstrate the 13
long-term need for the Palouse Wind PPA and provide 14
specific supportive details regarding the Company’s 15
analysis. The Palouse Wind PPA is consistent with the 16
Preferred Resource Strategy in the Company’s 2011 Electric 17
IRP, which is discussed earlier in my testimony. The Board 18
of Directors agreed with the recommendation to issue the 19
RFP for 35 aMW of renewable energy in 2011, and 20
subsequently approved the recommendation to negotiate a PPA 21
with Palouse Wind, LLC under terms and conditions 22
consistent with their bid proposal. The Company has 23
Lafferty, Di 22
Avista Corporation
provided and explained all of the analytical work completed 1
for this acquisition. 2
3
IV. GENERATION CAPITAL PROJECTS 4
Q. Please describe the upgrade projects for the 5
Noxon Rapids generating units. 6
A. The Company recently completed a multi-year 7
program to upgrade the Noxon Rapids generating units from 8
1950’s era technology. The upgrades improved reliability 9
and increased efficiency, by adding 30 MW of additional 10
capacity and approximately 6 aMW of energy to the Noxon 11
Rapids project. Illustration No. 7 summarizes the upgrade 12
schedule, additional capacity and efficiency gains by unit. 13
14
Illustration No. 7: Noxon Rapids Upgrades 15
The Noxon Unit #1 work consisted of the replacement of 16
the stator core, rewinding the stator, installing a new 17
turbine and performing a complete mechanical overhaul. 18
This upgrade increased the Unit’s energy efficiency by 19
4.16%, and increased the unit rating by 7.5 MW. The 20
Noxon Rapids
Unit #
Schedule of
Completion
Additional
Capacity
Efficiency
Improvement
1 April 2009 7.5 MW 4.16%
3 April 2010 7.5 MW 4.15%
2 May 2011 7.5 MW 2.42%
4 May 2012 7.5 MW 1.49%
Lafferty, Di 23
Avista Corporation
upgrade also fixed several reliability concerns for the 1
Unit including mechanical vibration and stator age. This 2
work was completed in 2009. The costs and additional 3
generation of this project were approved for recovery in 4
Case No. AVU-E-09-01. 5
The Noxon Unit #3 upgrade, completed in May 2010, 6
increased energy efficiency by 4.15%, and improved the unit 7
rating by 7.5 MW. The costs and additional generation for 8
Unit #3 were approved for recovery in Case No. AVU-E-10-012. 9
The Noxon Unit #2 upgrade, completed in May 2011, 10
included a new turbine and complete mechanical overhaul. 11
This upgrade increased the efficiency of Unit #2 by 2.42% 12
and increased the unit rating by 7.5 MW. The costs and 13
additional generation for Unit #2 were approved for 14
recovery in Case No. AVU-E-11-012. 15
The Noxon Unit #4 upgrade was completed in May 2012. 16
The Unit #4 upgrade will cost approximately $8.3 million 17
(system). The increased generating capability from these 18
units is reflected in Mr. Kalich’s AURORAXMP modeling of pro 19
forma power supply costs for the test period. 20

2 The last general rate cases (Docket Nos. AVU-E-10-01 and AVU-E-11-01)
were resolved through a “black-box” settlement, the costs and
additional generation represents the amounts included in the original
filing.
Lafferty, Di 24
Avista Corporation
The upgrade work at Noxon Unit #4, which is the final 1
project in the Noxon upgrades, involves the installation of 2
a new turbine, a complete mechanical overhaul, and GSU 3
(Generation Step Up) upgrades. The project started in 4
August 2011 and was completed in May 2012. The Unit #4 5
upgrade is projected to increase efficiency by 1.49 percent 6
and increased the unit capacity rating by 7.5 MW. The 7
costs and additional generation for Unit #4 were included 8
in the Company’s 2011 general rate case (AVU-E-11-01)3. 9
Q. Would you please provide a brief description of 10
the capital projects at Coyote Springs 2? 11
A. Yes. There are four main capital projects 12
completed in 2012 at Coyote Springs 2 (CS2) which total 13
$9,130,000 (system). The first project involved the 14
installation of a hydrogen generator. The electrical 15
generators for both the Gas Turbine and the Steam Turbine 16
are cooled by hydrogen gas. Even though this is a closed 17
system, some hydrogen gas escapes the system and make-up 18
gas must be added so the generator operates properly. An 19
evaluation was performed and it was determined that it 20
would be cost-effective to install a hydrogen gas generator 21
at the plant to create the necessary make-up gas for 22

3 Id.
Lafferty, Di 25
Avista Corporation
generator cooling purposes, instead of purchasing hydrogen 1
gas. 2
The second capital project at Coyote Springs 2 3
replaced the Steam Turbine Generator Exciter. The existing 4
excitation system was provided as original equipment from 5
Alstom, who no longer supports this system. The only 6
service providers available to provide assistance are 7
located in Europe. This project replaced the Alstom unit 8
with a GE unit that is compatible with the other excitation 9
system in the plant, which minimize spare parts 10
requirements and capitalizes on staff expertise. 11
The third capital project is the Gas Turbine 12
Compressor Upgrade. The original GE 7EA turbine compressor 13
series installed at CS2 exhibited an embedded risk due to 14
failure of a section of the compressor blades. This 15
project included the installation of a set of GE supplied 16
compressor blades to address this concern. All three of 17
these capital projects at CS2 were in service by July of 18
2012. 19
The last CS2 capital project is the major overhaul on 20
the steam and gas turbines performed by GE under the long 21
term service agreement (LTSA). This major overhaul was an 22
hours-of-operation based maintenance performed on the steam 23
Lafferty, Di 26
Avista Corporation
turbine at CS2. In addition, there were a few upgrades 1
performed that were outlined by the OEM in Service 2
Bulletins. This part of the capital projects at CS2 was 3
$5,100,000, and the project was completed in June of 2012. 4
Q. Would you please provide a brief description of 5
the other generation-related capital projects that are 6
planned for in 2012 and 2013? 7
A. Yes. As shown in Illustration No. 8, the total 8
2012 and 2013 generation projects to be completed, as 9
discussed by Mr. DeFelice, total $40.1 million and $26.7 10
million, respectively on a system basis. The 2012 Noxon 11
Unit #4 upgrade project discussed above is $8.3 million of 12
this total and the capital projects at Coyote Springs 2 are 13
$9.1 million. In addition, there are 11 other generation 14
capital projects totaling $49.3 million as discussed 15
further below. 16
Lafferty, Di 27
Avista Corporation
1
2
Thermal – Colstrip Capital Additions: $13,793,000 3
($3,154,000 in 2012 and $10,639,000 in 2013) 4
Capital work projects at Colstrip includes bushing and 5
blower replacement, rewind spare rotor, prototype scrubber 6
polishing system to improve particulate removal, raise the 7
ash storage pond dam walls, materials for waterwall 8
replacement, materials for final superheat replacement, and 9
miscellaneous small projects. 10
11
Thermal – Rathdrum CT: $917,000 in 2013 12
In 2007, the Mark V controller on Rathdrum Unit 2 failed, 13
taking the unit out of service for several months. A new 14
Mark VI controller was installed in its place. This 15
project replaces the old Mark V controller in Unit 1 with a 16
Mark VI controller to match Unit 2. The Mark V technology 17
in Unit 1 is at the end of its life, is minimally supported 18
by the manufacturer, and is a better solution for our 19
operations. 20
21
Hydro – Base Hydro Capital Project: $2,240,000 ($1,440,000 22
in 2012 and $800,000 in 2013) 23
24
Project Name
2012
Capital
Costs
(000's)
2013
Captial
Costs
(000's)
Total
(000's)
Noxon Rapids Unit #4 Upgrade 8,300.00$ -$ 8,300$
Coyote Springsw 2 Capital Projects 4,030 - 4,030
Coyote Springs 2 LTSA 5,100 - 5,100
Colstrip 3,154 10,639 13,793
Rathdrum CT - 917 917
Base Hydro 1,440 800 2,240
Regulating Hydro Program 2,081 2,928 5,009
Kettle Falls Capital Projects 4,245 960 5,205
Little Falls Powerhouse Redevelopment 600 3,939 4,539
Post Falls Intake Gate Replacement 4,688 - 4,688
Nin Mile Redevelopment - 2,602 2,602
Clark Fork Implementation PM&E Agreement 3,339 3,453 6,792
Spokane River Implementation (PM&E)2,805 240 3,045
Other Small Capital Projects 321 247 568
Total 40,103 26,725 66,828
Illustration No. 8: Generation Capital Projects Summary
Lafferty, Di 28
Avista Corporation
Generation Control Center Remodel: The present 1
generation control center utilizes technology that is 2
more than 15 years old to display, control, and 3
monitor all of Avista’s generation facilities. This 4
includes controlling seven of the generating plants 5
directly, while closely monitoring the six other 6
plants. The new control room will provide for more 7
efficient movement of operators for control of the 8
plant, lay down space for drawings to assist with 9
operation, local storage of manuals and other data, 10
and an updated and more efficient HVAC system. This 11
project was completed in July of 2012 at a cost of 12
$330,000. 13
14
Upper Falls HED Multi-Functional Landing: Over time, 15
the development of Riverfront Park and businesses 16
along the Spokane River have reduced accessibility to 17
the river for maintenance work for our Upper Falls 18
Facilities. This includes the dam safety barrier, 19
spillgates for Upper Falls (commonly referred to as 20
the Control Works), and the emergency generator 21
located near the spillgates for backup power purposes. 22
This project is to construct a permanent landing near 23
the Control Works that will allow barges and equipment 24
to be set in the water to maintain these key 25
facilities. The Multi-Functional Landing will provide 26
permanent access for maintenance activities associated 27
with the Control Works Dam and appurtenant facilities. 28
When not being used by Avista, it is a feature 29
available to park users to view the river. This 30
project was completed in June and July 2012 at a cost 31
of $310,000. 32
33
Various Small Projects: $800,000 in 2012 and 2013. 34
35
Hydro – Regulating Hydro Program Capital Projects: 36
$5,009,000 ($2,081,000 in 2012 and $2,928,000 in 2013) 37
38
Install Rack and Forebay Monitoring at Long Lake HED: 39
This work is to install monitoring systems allowing 40
operators to monitor forebay, tailwater, total 41
dissolved gas, and dissolved oxygen levels. All of 42
these systems involve installation of upstream or 43
downstream instruments in common locations to monitor 44
the water levels and quality. This project involves 45
work required by the FERC license and to enhance dam 46
Lafferty, Di 29
Avista Corporation
safety. This project is expected to be completed in 1
December of 2012 at a cost of $805,000. 2
3
Sewage Disposal System at Cabinet Gorge HED: The 4
existing sewage disposal system at Cabinet Gorge is 5
not able to maintain the effluent within permitted 6
levels and needs to be replaced with a system that 7
will comply with all permits. This projected should 8
be completed in November of 2012 at a cost of 9
$700,000. 10
11
Replace Powerhouse Lighting at Long Lake HED: The 12
current lighting system at the Long Lake powerhouse 13
consists of 1,000 watt incandescent lamps, which are 14
no longer commercially available and provide 15
relatively poor quality lighting. This project will 16
improve work lighting and put a more efficient 17
lighting system in the powerhouse. The project should 18
be completed in April 2013 at a cost of $228,000. 19
20
Replace Station Air Compressors at Cabinet Gorge HED: 21
The existing three station air compressors at Cabinet 22
Gorge are all original equipment. The air compressors 23
have been overhauled and re-bored several times, but 24
the bore wall thickness has been thinned to a point 25
where another overhaul is not recommended. Due to the 26
fragile condition of these compressors, blow down 27
capabilities at Cabinet Gorge have been curtailed, 28
reducing the amount of spinning reserve we can provide 29
to serve our needs. This project is expected to be 30
completed in June of 2013 at a cost of $900,000. 31
32
Unit 5 Exciter Replacement at Noxon Rapids HED: The 33
existing excitation system was installed in 1977 when 34
the unit was put into service. This GE analog 35
excitation system with Power System Stabilizer (PSS) 36
is 35 years old and parts/labor expertise is becoming 37
very expensive and difficult to acquire. There have 38
been on-going issues with the exciter, most recently 39
with the exciter step-down transformer. There has 40
been no major damage to the unit associated with the 41
issues to this point. This project is to replace the 42
existing GE static excitation system with a new bus-43
fed excitation system and an excitation control 44
upgrade that meets NERC and operational expectations. 45
Lafferty, Di 30
Avista Corporation
This project is expected to be completed in November 1
of 2013 at a cost of $150,000. 2
3
Noxon Rapids Living Facility Additions: With the 4
ongoing work at Noxon Rapids and in the Clark Fork 5
area to serve both the construction work at the plants 6
and in support of the environmental office, additional 7
living and meeting space is being planned for the 8
Noxon Living Facility to support this ongoing work. 9
The cost for the part of this project expected for 10
completion in February 2013 is $800,000 and the cost 11
for the part expected to be completed in November 2013 12
is $600,000. 13
14
Other Small Projects: $826,000 ($576,000 in 2012, 15
$250,000 in 2013) 16
17
Thermal – Kettle Falls Capital Projects: $5,205,000 18
($4,245,000 in 2012, $960,000 in 2013) 19
20
Replace Boiler Controls: The existing boiler control 21
system (Distributed Control System or DCS) is part of 22
the original plant equipment. Over the past decade, 23
we have been replacing different parts of this 24
original system and the turbine controls represent the 25
last stage. The original control equipment is no 26
longer supported by the supplier, third-party 27
suppliers have limited controls on hand, and the 28
operator interface system being used is not compatible 29
with this older control system. A PLC system is being 30
designed and deployed. As part of this effort, we are 31
replacing the present operator interface with a new 32
platform that will allow expansion of systems in the 33
future. This project will retain plant reliability 34
while reducing the chances of an extended forced 35
outage due to a DCS component failure. This project 36
was completed in July of 2012 at a cost of $654,000. 37
38
Replace Monitor Control Centers: The present Monitor 39
Control Centers are original equipment. They are 40
still functioning, but we have been experiencing some 41
problems that have used up spare parts. The original 42
manufacturer no longer exists and compatible units 43
that would allow for continued operation of this old 44
gear is no longer available. This project will 45
replace the obsolete equipment to maintain plant 46
Lafferty, Di 31
Avista Corporation
reliability. This project is expected to be completed 1
in October of 2012 at a cost of $571,000. 2
3
Install New Water Supply System: Kettle Falls 4
receives its water from the City of Kettle Falls 5
through an agreement that dates back to the 6
construction of the plant in the early 1980’s. That 7
agreement expires in 2012 and future water rates will 8
be higher. This effort is to secure necessary water 9
rights and a long-term water supply for the plant that 10
is controlled by the Company. A new well, sufficient 11
to provide for plant needs, was developed in 2011. 12
This capital work is for the installation of the water 13
supply piping and distribution system to the existing 14
Kettle Falls plant from the new well. The project 15
involves installing nearly 1,000 feet of water supply 16
line and distribution manifold at the plant. In 2011, 17
water rights were acquired and submitted to the 18
Washington Department of Ecology. The Department of 19
Ecology is investigating those water rights to assure 20
they are unencumbered. This ruling is expected to 21
come in 2012 at which time those would be transferred 22
to Avista. The issuance of the water rights is 23
expected to be completed in September 2012 at a total 24
cost of $1,075,000 and the new water supply system is 25
expected to be completed in December 2012 at a total 26
cost of $549,000. 27
28
Purchase D10TQ Caterpillar Tractor: This project 29
involves the replacement of the D10 Fuel Handler at 30
Kettle Falls Generating Station. The existing unit is 31
from 1991 and is in poor mechanical condition. These 32
large bulldozers (fuel handlers) are essential to the 33
operation of the plant. One day of lost production 34
due to inability to load fuel costs $13,337 in 35
comparison to buying power on the open market. Fuel 36
savings of $35,000 per year are expected and a new 37
machine will have much lower emissions. The existing 38
unit should be replaced in December of 2012 at a cost 39
of $1,396,000. 40
41
Truck Dumper Dust Containment Building: Hog fuel 42
trucks can create dust plumes during unloading. These 43
plumes have been identified by local air authorities 44
as a concern that will need to be addressed. Attempts 45
to abate the dust by installing hoods and other 46
Lafferty, Di 32
Avista Corporation
deflection elements have improved the dust situation, 1
but there are still concerns about the overall 2
particulate emissions associated with this process. 3
This project includes construction of a building 4
around the unloading area to contain the particulates. 5
This project is expected to be completed in November 6
of 2013 at a cost of $680,000. 7
8
Replace Grate Drive System: The current grate drive 9
system at Kettle Falls utilizes a hydraulically 10
operated ratchet system to move the traveling grate. 11
The ratcheting action causes the connecting links to 12
wear out. This capital project will replace the 13
hydraulic ratchet with a variable drive system to 14
provide constant tension on the grate to prevent the 15
cyclic wear on the grate system. This project is 16
expected to be completed in July of 2013 at a cost of 17
$280,000. 18
19
Hydro – Little Falls Powerhouse Redevelopment Capital 20
Projects – $4,539,000 ($600,000 in 2012, $3,939,000 in 21
2013) 22
23
Bridge Crane Modernization: The 50-ton Niles crane at 24
Little Falls HED is 100 years old and powered off of 25
the 250 volt DC system. This power system is supplied 26
by the rotational exciters. When the rotational 27
exciters are replaced, the ability to generate the 250 28
volt DC supply will be lost, and the crane will be 29
unusable. This project is to replace all the DC 30
motors with AC motors, and replace all DC controls 31
with modern AC controls. This project is expected to 32
be completed in November 2012 at a total cost of 33
$600,000. 34
35
Replace 4kV Switchgear: We have experienced several 36
major failures of the generator breakers within the 37
past five years. Attempts to recondition this old 38
equipment have been unsuccessful and we still 39
experience major failures. This has created a 40
hazardous area for operations personnel when the 41
equipment is energized. This work will replace all of 42
the existing switchgear with new units, removing this 43
concern and hazard. This project is expected to be 44
completed in February of 2013, at a cost of 45
$1,636,000. 46
Lafferty, Di 33
Avista Corporation
1
Replace Excitation System: The existing excitation 2
equipment is 60 years old. The amplidyne technology 3
is no longer supported by the manufacturer and very 4
few people in the country have the expertise to fix or 5
maintain this system. In the mid-1980’s, a Bailey 6
digital controller was fitted to this equipment to 7
keep these systems minimally operable. These systems 8
have failed several times in the past four years 9
causing major generator damage that has been 10
reparable. This project is to replace the amplidyne 11
and rotating exciter systems with new bus fed systems. 12
This project is expected to be completed in February 13
of 2013 at a cost of $1,535,000. 14
15
Install Warehouse: Over the next 10 to 12 years, major 16
rehabilitation work is being planned for the Long Lake 17
and the Little Falls plants (Little Falls is six miles 18
from Long Lake). Storage space for major equipment, 19
minor materials, and a construction staging area needs 20
to be built to facilitate these projects. This 21
warehouse will fill this need. Work includes erecting 22
a new warehouse in the Long Lake operator’s village 23
and installation of the 30-ton gantry crane from the 24
Little Falls powerhouse into this new warehouse. This 25
project is expected to be completed in April 2013 at a 26
cost of $768,000. 27
28
Hydro – Post Falls Intake Gate Replacement Capital Project: 29
$4,688,000 in 2012 30
Due to the deteriorated condition of the Post Falls HED 31
intake gates and associated hoist mechanisms, Avista has 32
committed to FERC to replace all six head gates and 33
hoisting equipment by the end of 2012. This project will 34
replace the existing wooden timbered head gates with new 35
steel gates and to modify the structure to include a hoist 36
system. Provisions for the gates will be made to pull the 37
gates out for easy maintenance purposes. This work also 38
includes installation of new controls and appropriate 39
emergency power systems. This project is expected to be 40
completed in December of 2012 at a cost of $4,688,000. 41
42
Hydro – Nine Mile Redevelopment: $2,602,000 in 2013 43
During a regular maintenance outage, cracks were found in 44
several buckets of two of the four turbine runners on Unit 45
4. After investigation, it was determined the blades had 46
Lafferty, Di 34
Avista Corporation
cracked due to fatigue. The runners were weld repaired and 1
the unit temporarily placed back into service. The repair 2
is expected to be temporary and new replacement runners 3
were ordered from the Original Equipment Manufacturer. The 4
project also includes planning and engineering costs for a 5
unit overhaul when the new replacement runners will be 6
installed. The Nine Mile Redevelopment Project is expected 7
to be completed in March of 2013 at a total cost of 8
$2,602,000. 9
10
Hydro – Clark Fork River Implementation PM&E: $6,792,000 11
($3,339,000 in 2012 and $3,453,000 in 2013) 12
The Clark Fork Implementation PM&E agreement capital 13
expenditures include recreation site improvements, design 14
and construction of fish passage, total dissolved gas 15
abatement faculties, and acquisition of property rights for 16
habitat restoration. We are currently pursuing the 17
acquisition of two separate conservation easements to 18
protect riparian habitat on the Bull River in Montana. 19
Numerous ongoing recreation site improvements include the 20
replacement of boat ramps, docks, and restrooms; upgrading 21
electrical and septic systems; and trail development and 22
improvements. Habitat enhancement projects include 23
improvement and maintenance of existing wetlands on the 24
Noxon Rapids reservoir, tributary habitat enhancements, 25
such as culvert replacement, stream bed reconstruction and 26
riparian re-vegetation and protection to improve passage, 27
spawning and rearing for native salmonids. 28
29
Hydro – Spokane River Implementation PM&E: $3,045,000 30
($2,805,000 in 2012 and $240,000 in 2013) 31
The Spokane River Project capital projects fulfill FERC’s 32
license requirements related to wetlands, water quality, 33
recreation, and land use improvements that will lead to 34
improvements located at Nine Mile, and Lake Spokane (the 35
Long Lake Dam reservoir). The water quality improvements 36
and wetland acquisition and/or enhancements are mandatory 37
conditions included in the License as part of the 38
Washington and Idaho 401 Water Quality Certifications, 39
whereas the recreation and land use projects are FERC’s 40
License requirements. This year we will continue modeling 41
a number of potential total dissolved gas remedies for Long 42
Lake Dam, and monitoring low dissolved oxygen (DO) in the 43
tailrace below the dam to determine if the aeration 44
equipment we installed last year will sufficiently meet 45
the State’s water quality standards. We are also 46
Lafferty, Di 35
Avista Corporation
installing additional aeration equipment in the Long Lake 1
Powerhouse to further improve DO in the tailrace. We 2
completed the channel modifications at Upper Falls last 3
fall, which were approved by the Washington Department of 4
Ecology. We will work to complete the required Nine Mile 5
and Lake Spokane recreation projects during this year’s 6
construction season. 7
8
Other Small Capital Projects: $568,000 ($321,000 in 2012 9
and $247,000 in 2013) 10
11
12
V. HYDRO RELICENSING 13
Q. Would you please provide an update on work being 14
done under the existing FERC operating license for the 15
Company’s Clark Fork River generation projects? 16
A. Yes. Avista received a new 45-year FERC 17
operating license for its Cabinet Gorge and Noxon Rapids 18
hydroelectric generating facilities on the Clark Fork River 19
on March 1, 2001. The Company has continued to work with 20
the 27 Clark Fork Settlement Agreement signatories to meet 21
the goals, terms, and conditions of the Protection, 22
Mitigation and Enhancement (PM&E) measures under the 23
license. The implementation program, in coordination with 24
the Management Committee which oversees the collaborative 25
effort, has resulted in the protection of approximately 26
2,694 acres of bull trout, wetlands, uplands, and riparian 27
habitat. More than 37 individual stream habitat 28
restoration projects have occurred on 23 different 29
Lafferty, Di 36
Avista Corporation
tributaries within our project area. Avista has collected 1
data on nearly 15,000 individual bull trout within the 2
project area. The upstream fish passage program, using 3
electrofishing, trapping and hook-and-line capture efforts, 4
has reestablished bull trout connectivity between Lake Pend 5
Oreille and the Clark Fork River tributaries above Cabinet 6
Gorge and Noxon Rapids Dams through the upstream transport 7
of 350 adult bull trout, with over 160 of these radio 8
tagged and their movements studied. Avista has worked with 9
the U.S. Fish and Wildlife Service to develop and test two 10
experimental fish passage facilities. Avista, in 11
consultation with key state and federal agencies, is 12
currently developing designs for both a permanent upstream 13
adult fishway for Cabinet Gorge and Noxon Rapids. Design 14
is completed on a permanent tributary trap for Graves Creek 15
(an important bull trout spawning tributary) with 16
construction scheduled for mid to late 2012. 17
Recreation facility improvements have been made to 18
over 23 sites along the reservoirs. Avista also owns and 19
manages over 100 miles of shoreline that includes 3,500 20
acres of property to meet FERC requirements to meet our 21
natural resource goals while allowing for public use of 22
these lands where appropriate. 23
Lafferty, Di 37
Avista Corporation
Finally, tribal members continue to monitor known 1
cultural and historic resources located within the project 2
boundary to ensure that these sites are appropriately 3
protected. 4
Q. Would you please provide an update on the current 5
status of managing total dissolved gas issues at Cabinet 6
Gorge dam? 7
A. Yes. How best to deal with total dissolved gas 8
(TDG) levels occurring during spill periods at Cabinet 9
Gorge Dam was unresolved when the current Clark Fork 10
license was received. The license provided time to study 11
the actual biological impacts of dissolved gas and to 12
subsequently develop a dissolved gas mitigation plan. 13
Stakeholders, through the Management Committee, ultimately 14
concluded that dissolved gas levels should be mitigated, in 15
accordance with federal and state laws. A plan to reduce 16
dissolved gas levels was developed with all stakeholders, 17
including the Idaho Department of Environmental Quality. 18
The original plan called for the modification of two 19
existing diversion tunnels, which could redirect stream 20
flows exceeding turbine capacity away from the spillway. 21
The 2006 Preliminary Design Development Report for the 22
Cabinet Gorge Bypass Tunnels Project indicated that the 23
Lafferty, Di 38
Avista Corporation
preferred tunnel configuration did not meet the 1
performance, cost and schedule criteria established in the 2
approved Gas Supersaturation Control Plan (GSCP). This led 3
the Gas Supersaturation Subcommittee to determine that the 4
Cabinet Gorge Bypass Tunnels Project was not a viable 5
alternative to meet the GSCP. The subcommittee then 6
developed an addendum to the original GSCP to evaluate 7
alternative approaches to the Tunnel Project. 8
In September 2009, the Management Committee agreed 9
with the proposed addendum, which replaces the Tunnel 10
Project with a series of smaller TDG reduction efforts, 11
combined with mitigation efforts during the time design and 12
construction of abatement solutions take place. FERC 13
approved the GSCP addendum in February 2010 and in April 14
2010 the Gas Supersaturation Subcommittee (a subcommittee 15
of the MC) chose five TDG abatement alternatives for 16
feasibility studies. Feasibility studies and design 17
continue on two of the alternatives. Final design and 18
initiation of construction of the spillway crest 19
modification prototype is anticipated to be completed in 20
late 2012. 21
Lafferty, Di 39
Avista Corporation
Q. Would you please give a brief update on the 1
status of the work being done under the new Spokane River 2
Hydroelectric Project’s license? 3
A. Yes. The Company received a new 50-year license 4
for the Spokane River Project on June 18, 2009. The 5
License incorporated key agreements with the Department of 6
Interior and other key parties in both Idaho and 7
Washington. Implementation of the new license began 8
immediately, with the development of over 40 work plans 9
prepared, reviewed and approved, as required, by the Idaho 10
Department of Environmental Quality, Washington Department 11
of Ecology, the U.S. Department of Interior, and FERC. The 12
work plans pertain not only to license requirements, but 13
also to meeting requirements under Clean Water Act 401 14
certifications by both Idaho and Washington and of other 15
mandatory conditions issued by the U.S. Department of 16
Interior. 17
In 2011, Avista continued implementing a water 18
quality, fisheries, recreation, cultural, wetland, aquatic 19
weed management, aesthetic, operational and related 20
conditions (PM&E measures) across all five hydro 21
developments. The majority of the PM&E measures are on-22
going in nature, however a number are one-time 23
Lafferty, Di 40
Avista Corporation
improvements, such as the Upper Falls aesthetic spill 1
project located in downtown Spokane. Over 340 acres of 2
wetland mitigation properties were acquired in 2011 on 3
Upper Hangman Creek in Idaho for the Coeur d’Alene Tribe 4
through the Coeur d’Alene Reservation Trust Resources 5
Restoration Fund that Avista established in 2009. We will 6
now begin developing restoration plans for the properties. 7
Last year, we also developed wetland mitigation plans 8
for our property along the St. Joe River and began 9
restoring the wetlands in 2012 and will continue to be 10
ongoing. During 2012 we continued work with the various 11
local, state, and federal agencies to complete the required 12
recreation projects in Idaho, and will develop up to ten 13
boat-in-only campsites on Lake Spokane, as well as other 14
numerous improvements at boat launches, overlooks and 15
interpretive areas on Lake Spokane and Nine Mile. We are 16
currently assessing potential wetland mitigation properties 17
in the Lake Spokane and Nine Mile areas in order to fulfill 18
the required conditions. In 2012 and going forward, we 19
will continue to implement approved work plans that have 20
been approved by FERC. 21
A number of the approved work plans require the 22
Company to conduct extensive studies to determine 23
Lafferty, Di 41
Avista Corporation
appropriate measures to mitigate resource impacts. The 1
more significant studies and mitigation measures include 2
those for total dissolved gas (TDG) downstream of Long Lake 3
Dam, which we began modeling in 2011 and will continue in 4
2012, and dissolved oxygen in the tailrace below Long Lake 5
Dam and in Lake Spokane, the reservoir created by the Long 6
Lake Dam. Initial estimates for measures to address TDG 7
range between $7.0 and $17.0 million, and between $2.5 and 8
$8.0 million to address dissolved oxygen in Lake Spokane. 9
These estimates will be further refined as the relevant 10
evaluations and studies are completed. 11
Q. Does this conclude your pre-filed direct 12
testimony? 13
A. Yes it does. 14

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-12-08
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 4
AND NATURAL GAS CUSTOMERS IN THE )
STATE OF IDAHO ) ROBERT J. LAFFERTY
)

FOR AVISTA CORPORATION

(ELECTRIC ONLY)
2011 Electric
Integrated
Resource Plan
August 31, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1 of 1069

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 2 of 1069
TABLE OF CONTENTS
Executive Summary i
Introduction and Stakeholder Involvement 1-1
Loads and Resources 2-1
Energy Efficiency 3-1
Policy Considerations 4-1
Transmission & Distribution 5-1
Generation Resource Options 6-1
Market Analysis 7-1
Preferred Resource Strategy 8-1
Action Items 9-1

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 3 of 1069
Safe Harbor Statement

This document contains forward-looking statements. Such statements are
subject to a variety of risks, uncertainties and other factors, most of which are
beyond the Company’s control, and many of which could have a significant
impact on the Company’s operations, results of operations and financial
condition, and could cause actual results to differ materially from those
anticipated.

For a further discussion of these factors and other important factors, please refer
to the Company’s reports filed with the Securities and Exchange Commission.
The forward-looking statements contained in this document speak only as of the
date hereof. The Company undertakes no obligation to update any forward-
looking statement or statements to reflect events or circumstances that occur
after the date on which such statement is made or to reflect the occurrence of
unanticipated events. New factors emerge from time to time, and it is not
possible for management to predict all of such factors, nor can it assess the
impact of each such factor on the Company’s business or the extent to which any
such factor, or combination of factors, may cause actual results to differ
materially from those contained in any forward-looking statement.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 4 of 1069
i
Table of Figures

Figure 1: Load-Resource Balance—Winter 18 Hour Capacity .............................. ii
Figure 2: Load-Resource Balance—Summer 18 Hour Capacity ........................... ii
Figure 3: Load-Resource Balance—Energy ........................................................ iii
Figure 4: Efficient Frontier .................................................................................... iv
Figure 5: Average Mid-Columbia Electricity Price Forecast .................................. v
Figure 6: Henry Hub Natural Gas Price Forecast ................................................. vi
Figure 7: Cumulative Conservation Acquisitions ................................................. vii
Figure 8: 2011 Preferred Resource Strategy (Annual Average Energy) ............. viii
Figure 9: Projected Price of Greenhouse Gas Emissions ..................................... x
Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
...................................................................................................................... xi
Figure 2.1: Avista’s Service Territory and Generation Resources ..................... 2-2
Figure 2.2: Population Percent Change for Spokane and Kootenai Counties .... 2-3
Figure 2.3: Total Population for Spokane and Kootenai Counties ..................... 2-3
Figure 2.4: House Starts Total Private (SAAR) .................................................. 2-4
Figure 2.5: Percent Change to Employment ...................................................... 2-5
Figure 2.6: Non-Farm Employment .................................................................... 2-5
Figure 2.7: Avista Customer Forecast ................................................................ 2-6
Figure 2.8: Household Size Index ...................................................................... 2-9
Figure 2.9: Electricity Usage per Customer ..................................................... 2-10
Figure 2.10: Avista’s Retail Sales Forecast ..................................................... 2-11
Figure 2.11: Annual Net Native Load ............................................................... 2-12
Figure 2.12: Winter and Summer Peak Demand ............................................. 2-13
Figure 2.13: Electricity Load Forecast Scenario .............................................. 2-14
Figure 2.14: Winter 18-Hour Capacity Load and Resources ............................ 2-21
Figure 2.15: Summer 18-Hour Capacity Load and Resources ........................ 2-22
Figure 2.16: Annual Average Energy Load and Resources ............................. 2-23
Figure 3.1: Historical and Forecast Conservation Acquisition ............................ 3-2
Figure 3.2: Analysis Approach Overview ........................................................... 3-4
Figure 3.3: Cumulative Conservation Potentials, Selected Years ...................... 3-8
Figure 3.4: Incremental Annual Achievable Energy Efficiency (MWh) vs. Avoided
Cost .......................................................................................................... 3-10
Figure 3.5: Energy Savings, Achievable Potential Case by Avoided Costs
Scenario ................................................................................................... 3-14
Figure 3.6: Supply Curves of the Evaluated Conservation Measures ............. 3-15
Figure 3.7: Cost of Existing & Future Conservation ......................................... 3-17
Figure 3.8: Cost of Conservation per Customer per I-937 ............................... 3-17
Figure 4.1: Annual Greenhouse Gas ............................................................... 4-12
Figure 4.2: Price of Greenhouse Gas Credits in each Carbon Policy .............. 4-14
Figure 5.1: Avista Transmission Map ................................................................. 5-2
Figure 6.1: New Resource Levelized Costs ..................................................... 6-11
Figure 6.2: Historical and Planned Hydro Upgrades ........................................ 6-13
Figure 6.3: Long Lake Second Powerhouse Concept Drawing ........................ 6-14
Figure 7.1: NERC Interconnection Map ............................................................. 7-2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 5 of 1069
ii
Figure 7.2: 20-Year Annual Average Western Interconnect Energy .................. 7-3
Figure 7.3: New Resource Added (Nameplate Capacity) .................................. 7-5
Figure 7.4: Henry Hub Natural Gas Price Forecast............................................ 7-6
Figure 7.5: Shale Gas Production Forecast ....................................................... 7-8
Figure 7.6: Northwest Expected Energy .......................................................... 7-10
Figure 7.7: Regional Wind Expected Capacity Factors .................................... 7-11
Figure 7.8: Price of Greenhouse Gas Credits in each Carbon Policy .............. 7-12
Figure 7.9: Distribution of Annual Average Carbon Prices for 2020 ................. 7-14
Figure 7.10: Historical AECO Natural Gas Prices ............................................ 7-15
Figure 7.11: Stanfield Annual Average Natural Gas Price Distribution ............ 7-16
Figure 7.12: Stanfield Natural Gas Distributions .............................................. 7-16
Figure 7.13: Wind Model Output for the Northwest Region .............................. 7-21
Figure 7.14: 2010 Actual Wind Output BPA Balancing Authority ..................... 7-21
Figure 7.15: Mid-Columbia Electric Price Forecast Range .............................. 7-23
Figure 7.16: Western States Greenhouse Gas Emissions ............................... 7-25
Figure 7.17: Base Case Western Interconnect Resource Mix ......................... 7-26
Figure 7.18: Mid-Columbia Prices Comparison with and without Carbon
Legislation................................................................................................. 7-27
Figure 7.19: Western U.S. Carbon Emissions Comparison ............................. 7-28
Figure 7.20: Unconstrained Carbon Scenario Resource Dispatch ................... 7-28
Figure 7.21: Average Annual Mid-Columbia Electric Prices for Alternative
Greenhouse Gas Policies ......................................................................... 7-29
Figure 7.22: Nominal Levelized Mid-Columbia Electric Prices for Alternative
Greenhouse Gas Policies ......................................................................... 7-30
Figure 7.23: Annual Greenhouse Gas Emissions for Alternative Greenhouse Gas
Policies ..................................................................................................... 7-30
Figure 7.24: Average Annual Mid-Columbia Price Comparison of Greenhouse
Gas Policies .............................................................................................. 7-32
Figure 7.25: Expected Greenhouse Gas Emissions Comparison .................... 7-32
Figure 7.26: Natural Gas Price Scenario’s Greenhouse Gas Emission Prices 7-34
Figure 7.27: Natural Gas Price Scenario’s Mid-Columbia Price Forecasts ...... 7-34
Figure 7.28: Wind Sensitivity Mid-Columbia Price Changes ............................ 7-35
Figure 7.29: Wind Sensitivity Negative Pricing ................................................ 7-36
Figure 7.30: Change to Resource Revenues ................................................... 7-37
Figure 8.1: Resource Acquisition History ........................................................... 8-2
Figure 8.2: Conceptual Efficient Frontier Curve ................................................. 8-4
Figure 8.3: Physical Resource Positions (Includes Conservation) ..................... 8-6
Figure 8.4: REC Requirements vs. Qualifying RECs for Washington State RPS 8-
7
Figure 8.5: Energy Efficiency Annual Expected Acquisition ............................... 8-9
Figure 8.6: Annual Average Load and Resource Balance ............................... 8-11
Figure 8.7: Winter Peak Load and Resource Balance ..................................... 8-12
Figure 8.8: Summer Peak Load and Resource Balance .................................. 8-12
Figure 8.9: Avista Owned and Controlled Resource’s Greenhouse Gas
Emissions ................................................................................................. 8-14
Figure 8.10: Expected Case Efficient Frontier ................................................. 8-15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 6 of 1069
iii
Figure 8.11: Power Supply Expense Range .................................................... 8-21
Figure 8.12: Real Power Supply Expected Rate Growth Index $/MWh (2012 =
100) .......................................................................................................... 8-22
Figure 8.13: Power Supply Cost Sensitivities .................................................. 8-23
Figure 8.14: Greenhouse Gas Related Power Supply Expense ...................... 8-24
Figure 8.15: Efficient Frontier Comparison ...................................................... 8-25
Figure 8.16: Efficient Frontier Comparison ...................................................... 8-26
Figure 8.17: Efficient Frontier Comparison with Tail Var90 .............................. 8-27
Figure 8.18: Load Growth Scenario’s Cost/Risk Comparison .......................... 8-36
Figure 8.19: Load Growth Scenario’s Cost/Risk Comparison .......................... 8-37

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 7 of 1069
iv
Table of Tables

Table 1: The 2011 Preferred Resource Strategy ................................................ viii
Table 2: The 2009 Preferred Resource Strategy ................................................. ix
Table 1.3 Washington IRP Rules and Requirements ......................................... 1-6
Table 2.1: Global Insight National Long Range Forecast Assumptions ............. 2-4
Table 2.2: Company-Owned Hydro Resources ............................................... 2-16
Table 2.3: Company-Owned Thermal Resources ............................................ 2-18
Table 2.4: Mid-Columbia Capacity and Energy Contracts ............................... 2-19
Table 2.5: Large Contractual Rights and Obligations ....................................... 2-20
Table 2.6: Washington State RPS Detail (aMW) ............................................. 2-26
Table 2.7: Winter 18-Hour Capacity Position (MW) ......................................... 2-27
Table 2.8: Summer 18-Hour Capacity Position (MW) ...................................... 2-28
Table 2.9: Average Annual Energy Position (aMW) ......................................... 2-29
Table 3.1: Energy Forecasts and Cumulative Savings (Across All Sectors for
Selected Years) .......................................................................................... 3-7
Table 3.2: Incremental Annual Achievable Potential Energy Efficiency (aMW) . 3-9
Table 3.3: Cumulative Achievable Savings from Conversion to Natural Gas ... 3-10
Table 3.4: Cumulative Achievable Savings from Conversion to Natural Gas by
State (MWh) .............................................................................................. 3-11
Table 3.5: Varying Growth Scenario Descriptions............................................ 3-13
Table 3.6: Varying Growth Scenario Results (MWh) ........................................ 3-13
Table 3.7: Achievable Potential with Varying Avoided Costs .......................... 3-15
Table 4.1: Modeled Greenhouse Gas Policies ................................................. 4-12
Table 5.1: New Resource Integration Costs ...................................................... 5-9
Table 5.2: Distribution Loss Energy Savings (MWh) ........................................ 5-12
Table 6.1: CCCT (Air Cooled) Levelized Costs .................................................. 6-4
Table 6.2: Simple Cycle Plant Cost and Operational Characteristics................. 6-4
Table 6.3: Simple Cycle Plant Levelized Costs per MWh .................................. 6-5
Table 6.4: Northwest Wind Project Levelized Costs per MWh ........................... 6-6
Table 6.5: Solar Nominal Levelized Cost ($/MWh) ............................................ 6-7
Table 6.6: Coal Capital Costs (2012$) ............................................................... 6-8
Table 6.7: Coal Project Levelized Cost per MWh............................................... 6-8
Table 6.8: Other Resource Options Levelized Costs ....................................... 6-10
Table 6.9: Other Resource Options Levelized Costs ($/MWh) ........................ 6-10
Table 6.10: New Resource Levelized Costs Considered in PRS Analysis ....... 6-12
Table 6.11: New Resource Levelized Costs Not Considered in PRS Analysis 6-12
Table 6.12: Hydro Upgrade Potential ............................................................... 6-13
Table 6.13: Rathdrum CT Upgrade Options ($/MWh) ...................................... 6-16
Table 6.14: Coyote Springs 2 Upgrade Options ($/MWh) ................................ 6-17
Table 7.1: AURORAXMP Zones........................................................................... 7-2
Table 7.2: Western Interconnect Transmission Upgrades Included in Analysis . 7-4
Table 7.3: Natural Gas Price Basin Differentials from Henry Hub ...................... 7-7
Table 7.4: Monthly Price Differentials for Stanfield ............................................ 7-7
Table 7.5: Monthly Price Differentials for Stanfield .......................................... 7-12
Table 7.6: January through June Area Correlations......................................... 7-17
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 8 of 1069
v
Table 7.7: July through December Area Correlations ...................................... 7-18
Table 7.8: Area Load Coefficient of Determination (Std Dev/Mean) ................ 7-18
Table 7.9: Area Load Coefficient of Determination (Std Dev/Mean) ................ 7-19
Table 7.10: Expected Capacity factor by Region ............................................. 7-20
Table 7.11: Annual Average Mid-Columbia Electric Prices ($/MWh) ............... 7-24
Table 7.12: Impacts of Greenhouse Gas Mitigation Policies in the West ......... 7-33
Table 8.1: 2011 Preferred Resource Strategy ................................................... 8-8
Table 8.2: 2009 Preferred Resource Strategy ................................................... 8-8
Table 8.3: Avista Medium-Term Winter Capacity Tabulation ........................... 8-13
Table 8.4: Avista Medium-Term Summer Capacity Tabulation ........................ 8-13
Table 8.5: Nominal Levelized Avoided Costs ($/MWh) .................................... 8-17
Table 8.6: Preferred Resource Strategy Avoided Cost ($/MWh)...................... 8-18
Table 8.7: Updated Annual Avoided Costs ($/MWh)........................................ 8-19
Table 8.8: PRS Rate Base Additions from Capital Expenditures ..................... 8-20
Table 8.9: Preferred Portfolio Cost and Risk Comparison (Millions $) ............. 8-25
Table 8.10: Preferred Resource Strategy ........................................................ 8-27
Table 8.11: Least Cost Portfolio ....................................................................... 8-28
Table 8.12: Least Risk Portfolio ....................................................................... 8-28
Table 8.13: 50/50 Cost and Risk Midpoint Portfolio ......................................... 8-29
Table 8.14: 75/25 Cost Risk Portfolio ............................................................... 8-29
Table 8.15: 25/75 Cost Risk Portfolio ............................................................... 8-30
Table 8.16: PRS without Apprentice Credits .................................................... 8-30
Table 8.17: 2009 IRP Portfolio ......................................................................... 8-31
Table 8.18: PRS without Wind Portfolio ........................................................... 8-31
Table 8.19: CCCT with Solar after 2015 Portfolio ............................................ 8-32
Table 8.20: National Renewable Energy Standard .......................................... 8-32
Table 8.21: PRS without Conservation ............................................................ 8-33
Table 8.22: PRS Conservation Avoided Costs 25% Lower .............................. 8-33
Table 8.23: PRS Conservation Avoided Costs 25% Higher ............................. 8-34
Table 8.24: PRS Conservation Avoided Costs 50% Higher ............................. 8-34
Table 8.25: Low Load Growth Resource Strategy ........................................... 8-36
Table 8.26: High Load Growth Resource Strategy........................................... 8-37
Table 8.27: Summary of Resource Portfolios .................................................. 8-38
Table 8.28: Winter 18-Hour Capacity Position (MW) Net of Conservation with
New Resources ........................................................................................ 8-39
Table 8.29: Summer 18-Hour Capacity Position (MW) Net of Conservation with
New Resources ........................................................................................ 8-40
Table 8.30: Average Annual Energy Position (aMW) With New Resources .... 8-41
Table 8.31: Washington State RPS Detail with New Resources (aMW) .......... 8-42

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 9 of 1069
2011 Electric IRP Introduction

Avista has a long tradition of innovation as a provider of clean, renewable energy. The
2011 Integrated Resource Plan (IRP) continues the tradition by looking into the future
energy needs of our customers. The IRP analyzes and outlines a strategy to meet
projected demand and renewable portfolio standards through energy efficiency and a
careful mix of new renewable and traditional energy resources.

Plant upgrades and conservation measures are an integral part of Avista’s 2011 IRP
resource strategy. Avista expects to add increasing amounts of new renewables to its
generation portfolio in the coming years. Renewables represent viable energy sources
that diversify our resource mix and reduce the need for fossil fuels.

The challenge of integrating renewable resources such as wind and solar is that they
are intermittent resources, meaning the wind does not always blow and the sun does
not always shine. Customers expect high reliability; therefore, utilities will still need
energy from natural gas and hydropower to keep the lights on. This presents a
challenge to resource planners, who must consider reliability as well as rate and
environmental impacts.

Avista’s electricity sales growth is expected to be 1.6 percent over the next two
decades. The Company projects it will have sufficient resources to meet this growth
through 2018.

Each IRP is a thoroughly researched and data-driven document to guide responsible
resource planning for the Company. The IRP is updated every two years and looks 20
years into the future. This plan is developed by Avista’s professional energy analysts
using sophisticated modeling tools and input from interested community stakeholders.

The plan’s Preferred Resource Strategy (PRS) section covers the Company’s projected
resource acquisitions over the next 20 years.

Some highlights of the PRS include:
A newly signed contract for the Palouse Wind project located near Spokane,
Washington will fulfill Avista’s RPS obligations through 2019.
An additional 42 aMW of wind or qualified renewable energy credits are required
by 2020.
Energy efficiency reduces load growth by 48 percent. Aggressive energy
efficiency measures are expected to save 310 aMW of cumulative energy over
the next 20 years.
756 MW of clean-burning natural gas-fired generation facilities are required
between 2018 and 2031.
Avista’s grid modernization and distribution feeder upgrade programs are
projected to reduce load by about five aMW by 2013.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 10 of 1069
Transmission upgrades will be needed to carry the output from new generation.
Avista will continue to participate in regional efforts to expand the region’s
transmission system.

This document is mostly technical in nature. The IRP has an Executive Summary and
chapter highlights at the beginning of each section to help guide the reader. Avista
expects to begin developing the 2013 IRP in early 2012. Stakeholder involvement is
encouraged and interested parties may contact John Lyons at 509-495-8515 or
[e-mail] for more information on participating in the IRP process.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 11 of 1069
Executive Summary
Avista Corp 2011 Electric IRP i
Executive Summary
Avista’s 2011 Integrated Resource Plan (IRP) guides its strategy over the next two
years and indicates the overall direction of resource procurements for the remainder of
a 20-year planning horizon. It provides a snapshot of the Company’s resources and
loads and guidance for future resource acquisitions. The resultant Preferred Resource
Strategy (PRS) is a mix of wind generation, energy efficiency, upgrades at existing
generation and distribution facilities, and new gas-fired generation.
The PRS balances cost, reliability, rate volatility, and renewable resource requirements.
Avista’s management and the Technical Advisory Committee (TAC) stakeholders play a
central role in guiding the development of the PRS and the IRP as a whole by providing
significant input on modeling and planning assumptions, and the general direction of the
planning process. TAC members include customers, commission staff, the Northwest
Power and Conservation Counsel, consumer advocates, academics, utility peers,
government agencies, and interested internal parties.
Resource Needs
Plant upgrades and conservation measures are an integral part of Avista’s 2011 IRP
resource strategy, but they are ultimately inadequate to meet all expected future load
growth. Absent new resource additions or new conservation measures, annual energy
deficits begin in 2020, with loads and a planning margin exceeding resource capability
by 49 aMW. Energy deficits rise to 218 aMW in 2026 and 475 aMW in 2031. Absent
new resource additions or new conservation measures, the Company will be short 98
MW of summer capacity in 2019.1 In 2026 and 2031, capacity deficits rise to 352 MW
and 774 MW, respectively. Winter capacity deficits begin at 42 MW in 2020 and
increase to 401 MW in 2026 and 883 MW in 2031.2

Increasing deficits are a result of forecasted 1.6 percent energy and capacity load
growth through 2031. The expiration of long-term purchase and sale contracts on a net
basis also increases deficiencies. Figures 1 through 3 provide graphical representations
of projected load and resource balances before the addition of PRS resources. The
vertical bars in the figures show Avista’s resource mix including hydroelectric, baseload
thermal resources (such as Colstrip and Coyote Springs 2), peaking thermals (such as
Northeast and Rathdrum), and net market transactions (includes long-term purchases
and sales plus our expected short-term market transactions). The lower lines in the
figures represent the load forecast and the upper lines include the load forecast plus a
planning margin and operating reserves. The load forecast uses sustained 18-hour
peaks.3 The forecasted needs would be higher absent energy efficiency acquisitions. A
more thorough discussion of loads and resources position is in Chapter 2.
1 This position assumes Avista relies on its share of regional power surpluses through 2021 as identified
by the Northwest Power and Conservation Council and documented further in Chapter 2. 2 Ibid. 3 The 18-hour sustained peak metric assumes six peak hours for three days in a row.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 12 of 1069
Executive Summary
Avista Corp 2011 Electric IRP ii
Figure 1: Load-Resource Balance—Winter 18 Hour Capacity

Figure 2: Load-Resource Balance—Summer 18 Hour Capacity

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Firm Contracts Avista Share of Excess NW Capacity
Peaking Thermals Baseload Thermals
Hydro Load Forecast
Load + Reserves + Planning Margin
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Firm Contracts Avista Share of Excess NW Capacity
Peaking Thermals Baseload Thermals
Hydro Load Forecast
Load + Reserves + Planning Margin
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 13 of 1069
Executive Summary
Avista Corp 2011 Electric IRP iii
Figure 3: Load-Resource Balance—Energy

Modeling and Results
Avista uses a multiple-step approach to develop its Preferred Resource Strategy. It
begins by identifying and quantifying potential new generation resources to serve
projected demand needs across the West. A Western Interconnect-wide study explains
the impact of regional markets on the Northwest electricity marketplace. Avista then
maps its existing resources to the present transmission grid configuration in a model
simulating hourly operations for the Western Interconnect from 2012 to 2031.
The model adds cost-effective new resources and transmission to meet growing loads.
Monte Carlo-style analysis varies hydroelectric generation, wind generation, load,
forced outages, greenhouse gas emission cost estimates, and natural gas price data
over 500 iterations of potential future market conditions. The simulation estimates Mid-
Columbia electricity markets, and the iterations collectively form the IRP Expected
Case.
Each new resource and energy efficiency option is valued against the Expected Case
Mid-Columbia electricity market to identify its future value to the Company, as well as its
inherent risk measured as year-to-year cost volatility. These values, and their
associated capital and fixed operation and maintenance (O&M) costs, form the input
into Avista’s Preferred Resource Strategy Linear Programming Model (PRiSM). PRiSM
assists the Company by developing optimal mixes of new resources at each point on an
efficient frontier.4 The PRS provides a “least reasonable cost” portfolio that
simultaneously minimizes future costs and risks given legislatively mandated or
expected future environmental constraints. An efficient frontier helps determine the
4 See Chapter 8 for a detailed discussion of the efficient frontier concept.
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Net Market Transactions Peaking Thermals
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Load Forecast Load + Contingency
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 14 of 1069
Executive Summary
Avista Corp 2011 Electric IRP iv
tradeoffs between risk and cost. The approach is similar to finding an optimal mix of risk
and return when developing a personal investment portfolio. As expected returns
increase, so do risks. Reducing risk reduces overall returns. Identifying the PRS is
similar to an investor’s dilemma. There is a trade-off between power supply costs and
power supply cost variability. Figure 4 presents the change in cost and risk from the
PRS on the Efficient Frontier. Lower power cost variability comes from investment in
more expensive, but less risky, resources. The PRS selection is the location on the
efficient frontier where the increased cost justified the reduction in risk.

Figure 4: Efficient Frontier

The IRP includes several scenarios that help identify tipping points where the PRS
could change under alternative conditions to the Expected Case. Chapter 8 includes
scenarios for load growth, capital costs, higher energy efficiency acquisitions, and
greenhouse gas policies.

Electricity and Natural Gas Market Forecasts
Figure 5 shows the 2011 IRP electricity price forecast in the Expected Case, including
the modeled range of prices over the 500 Monte Carlo iterations described previously.
The forecasted levelized average Mid-Columbia market price is $70.50 per MWh in
nominal dollars over the next 20 years; the off-peak price is $63.94 per MWh and the
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$450 $500 $550 $600 $650 $700
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20 yr levelized annual power supply rev. req.
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PRS
Market
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 15 of 1069
Executive Summary
Avista Corp 2011 Electric IRP v
on-peak price is $75.42 per MWh. These prices include the market impacts of
greenhouse gas mitigation beginning in 2015.5

Figure 5: Average Mid-Columbia Electricity Price Forecast

Electricity and natural gas prices are highly correlated because natural gas fuels
marginal generation resources in the northwest during most of the year. Figure 6
presents nominal levelized Expected Case natural gas prices at Henry Hub, as well as
the range of forecasts from the 500 Monte Carlo iterations performed for the case. The
average is $6.70 per decatherm over the next 20 years. See Chapter 7 for more detail
on the Company’s natural gas price forecast.

5 The forecast assumes a western region reduction of 14 percent by 2032.
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 16 of 1069
Executive Summary
Avista Corp 2011 Electric IRP vi
Figure 6: Henry Hub Natural Gas Price Forecast

Energy Efficiency Acquisition
Avista commissioned a 20-year Conservation Potential Assessment in 2010. The study
analyzed over 4,300 equipment and measure options for residential, commercial, and
industrial applications. Data from this study formed the basis of the IRP conservation
potential evaluations. Figure 7 shows how energy efficiency decreases Avista’s energy
requirements by 120.2 aMW, or approximately ten percent.6 By 2031, energy efficiency
reduces load by 310 aMW (288 aMW net after measure life expectancy adjustments).
More detail about Avista’s energy efficiency programs is contained in Chapter 3.

6 The Company has acquired 156.3 aMW of conservation since 1978; however, the assumed 18-year
average life of the conservation portfolio means that some of the measures have reached the end of their
useful lives and are no longer reducing loads. The 18-year assumed life of measures accounts for the
difference between the Gross and Net lines in Figure 7.
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 17 of 1069
Executive Summary
Avista Corp 2011 Electric IRP vii
Figure 7: Cumulative Conservation Acquisitions

Preferred Resource Strategy
The PRS includes careful consideration by Avista’s management and the Technical
Advisory Committee of the information gathered and analyzed in the IRP process. It
meets future load growth with efficiency upgrades at existing generation and distribution
facilities, conservation, wind, and simple- and combined-cycle natural gas-fired
combustion turbines. Figure 8 displays the resource mix for the 2011 Preferred
Resource Strategy layered on top of Avista’s current resources.

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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 18 of 1069
Executive Summary
Avista Corp 2011 Electric IRP viii
Figure 8: 2011 Preferred Resource Strategy (Annual Average Energy)

The PRS has changed only modestly from the 2009 IRP. The PRS resources of both
the 2009 and 2011 IRPs, on a nameplate capacity basis, are in Tables 1 and 2 below.

Table 1: The 2011 Preferred Resource Strategy

Resource By the
End of
Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 120 35
SCCT 2018 83 75
Existing Thermal Resource Upgrades 2019 4 3
NW Wind 2019-2020 120 35
SCCT 2020 83 75
CCCT 2023 270 237
CCCT 2026 270 237
SCCT 2029 46 42
Total 996 739
Efficiency Improvements By the
End of
Year
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2012-2031 28 13
Energy Efficiency 2012-2031 419 310
Total 447 323

-
500
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1,500
2,000
2,500
3,000
3,500
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New Simple Cycle CC
New Combined Cycle CC
Distribution Efficiency
Other
New Wind
Existing Resources
Load w/o DSM + Cont.
Load w DSM + Cont.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 19 of 1069
Executive Summary
Avista Corp 2011 Electric IRP ix
Table 2: The 2009 Preferred Resource Strategy

Resource By the
End of
Year
Nameplate
(MW)
Energy
(aMW)
Northwest Wind 2012 150 48
Little Falls Unit Upgrades 2013-2016 3 1
Northwest Wind 2019 150 50
Combined-Cycle Combustion Turbine 2019 250 225
Upper Falls 2020 2 1
Northwest Wind 2022 50 17
Combined-Cycle Combustion Turbine 2024 250 225
Combined-Cycle Combustion Turbine 2027 250 225
Total 1,105 792
Efficiency Improvements By the
End of
Year
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2010-2015 5 3
Energy Efficiency 2010-2029 339 226
Total 344 229

The present value of the investment required to support the 2011 PRS is just over $0.84
billion; the nominal total capital expense is $1.7 billion over the IRP timeframe. Avista
also forecasts spending $1.4 billion over the IRP timeframe on conservation
acquisitions.
Greenhouse Gas Emissions
As with all Avista IRPs since 2007, the costs of greenhouse gas policies are included in
the Expected Case for this IRP. Since the 2009 IRP, less certainty exists around the
direction of future of greenhouse gas policies. To address this uncertainty, the 2011 IRP
considers four policies. Each represents a different policy alternative beginning in 2015.
The policies are: 1) a regional cap and trade regime, 2) a national cap and trade regime,
3) a national carbon tax, and 4) the absence of any greenhouse gas policy. The impacts
of greenhouse gas policies on the Expected Case are the result of a weighted average
of these policies as included in the stochastic analysis of the IRP. Figure 9 presents
emissions cost assumptions on a per-short ton basis.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 20 of 1069
Executive Summary
Avista Corp 2011 Electric IRP x
Figure 9: Projected Price of Greenhouse Gas Emissions

Figure 10 shows projected greenhouse gas emissions for existing and new Avista
generation assets.7 The grey area of Figure 10 represents incremental greenhouse gas
emissions where there is no national or regional greenhouse gas policy.8
7 Figure 10 does not include emissions from market or contract purchases. It also does not reduce
Company emissions commensurate with market or contract sales. 8 Existing Avista resources, and those selected to meet load growth, under a scenario without a
greenhouse gas policy likely would generate higher emissions due primarily to increased operation at
Colstrip.
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National Climate Policy
Delayed National Climate Policy
National GHG Tax
No GHG Reductions
Expected Case
Regional GHG Policy
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 21 of 1069
Executive Summary
Avista Corp 2011 Electric IRP xi
Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions

Action Items
The Company’s 2011 Action Plan outlines activities and studies between now and the
2013 Integrated Resource Plan. It includes input from Commission Staff, the Company’s
management team, and the Technical Advisory Committee. Action Item categories
include resource additions and analysis, demand side management, environmental
policy, modeling and forecasting enhancements, and transmission planning. Chapter 9
contains 2011 IRP Action Items.
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GHG Reduction due to Legislation
New Resources
Existing Resources
Tons per MWh of Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 22 of 1069

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 23 of 1069
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP 1-1
1. Introduction and Stakeholder Involvement
Avista Utilities submits a biennial Integrated Resource Plan (IRP) to the Idaho and
Washington public utility commissions.1 The 2011 IRP is Avista’s twelfth plan. It
identifies and describes a Preferred Resource Strategy (PRS) for meeting load growth
while balancing cost and risk measures with environmental mandates.
The Company is statutorily obligated to provide reliable electricity service to its
customers at rates, terms, and conditions that are just, reasonable, and sufficient.
Avista assesses different resource acquisition strategies and business plans to acquire
resources to meet resource adequacy requirements and optimize the value of its current
resource portfolio. We use the IRP as a resource evaluation tool rather than a plan for
acquiring a particular set of assets. The 2011 IRP continues refining our resource
acquisition efforts.
IRP Process
The 2011 IRP is developed and written with the aid of a public process. Avista actively
seeks input for its IRPs from a variety of constituents through the Technical Advisory
Committee (TAC). The TAC list of 75 individuals includes Commission Staff from Idaho
and Washington, customers, academics, government agencies, consultants, utilities,
and other interested parties who accepted an invitation to join, or had asked to be
involved in, the planning process.
The Company sponsored six TAC meetings for the 2011 IRP. The first meeting was on
May 27, 2010, and the last was on June 23, 2011. TAC meetings covered different
aspects of the 2011 IRP planning activities and solicited contributions to, and
assessments of, modeling assumptions, modeling processes, and results. Table 1.1
contains a list of TAC meeting dates and the agenda items covered in each meeting.

1 Washington IRP requirements are contained in WAC 480-100-238 Integrated Resource Planning. Idaho
IRP requirements are outlined in Case No. U-1500-165 Order No. 22299, Case No. GNR-E-93-1, Order
No. 24729, and Case No. GNR-E-93-3, Order No. 25260.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 24 of 1069
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP 1-2
Table 1.1: TAC Meeting Dates and Agenda Items

Meeting Date Agenda Items
TAC 1 – May 27, 2010 Work Plan
Load & Resource Balance Update
Resource Planning Environment
2011 IRP Topic Discussions – Analytical
Process Changes, Hydro Modeling,
Resource Adequacy, Loss of Load
Probability, Energy Efficiency and Scoping
the 2011 Plan
TAC 2 – September 8 and 9,
2010
Lancaster Plant Tour
Upper Falls and Monroe Street Tour
Resource Assumptions
Reliability Planning
Sustainability Report
Combined Heat and Power Generation
Energy Efficiency
TAC 3 – December 2, 2010 Transmission Costs and Issues
Potential Hydro Upgrades
Potential Thermal Upgrades
Load Forecast
Stochastic Modeling
TAC 4 – February 3, 2011 Natural Gas Price Forecast
Electric Price Forecast
Resource Requirements Projections
Portfolio and Market Scenario Planning
TAC 5 – April 12, 2011 Conservation Avoided Cost Methodology
Conservation
Smart Grid
Draft Preferred Resource Strategy
Portfolio Alternatives & Scenarios
TAC 6 – June 23, 2011 High Wind Market Analysis
Preferred Resource Strategy and Scenario
Analysis
IRP Action Items
IRP Section Highlights

Agendas and presentations from the TAC meetings are in Appendix A and on Avista’s
website at http://www.avistautilities.com/inside/resources/irp/electric. Past IRPs and
TAC presentations are also here.

Avista wishes to acknowledge the contributions of a number of external TAC
participants in Table 1.2.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 25 of 1069
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP 1-3
Table 1.2: External Technical Advisory Committee Participants

Participant Organization
Robin Toth Greater Spokane Inc.
Dave Van Hersett Resource Development Associates
John Dacquisto Gonzaga University
Deborah Reynolds Washington Utilities and Transportation Commission
Steve Johnson Washington Utilities and Transportation Commission
David Nightingale Washington Utilities and Transportation Commission
Rick Applegate Washington Utilities and Transportation Commission
Nancy Hirsch Northwest Energy Coalition
Kirsten Wilson Washington State General Administration
Rick Sterling Idaho Public Utilities Commission
Tom Noll Idaho Power
Ken Corum Northwest Power and Conservation Council
Keith Knitter Grant County Public Utilities District
Becky King Chelan County Public Utilities District
Villamour Gamponia Puget Sound Energy
Kevin Rasler Inland Empire Paper
Mike Connolley Idaho Forest Group
Rob Haneline McKinstry

Issue Specific Public Involvement Activities
In addition to the TAC meetings, Avista sponsors and participates in several other
collaborative processes involving a range of public interests.
External Energy Efficiency (“Triple E”) Board
The Triple E Board, formed in 1995, provides stakeholders and public groups biannual
opportunities to discuss Avista’s energy efficiency efforts. The Triple E Board grew out
of the DSM Issues group. This predecessor group was influential in developing the
country’s first conservation distribution surcharge in 1995.
FERC Hydro Relicensing – Clark Fork River Projects
Over 50 stakeholder groups participated in the Clark Fork hydro-relicensing process
beginning in 1993. This led to the first all-party settlement filed with a FERC relicensing
application, and eventual issuance of a 45-year FERC operating license in February
2003. The nationally recognized Living License concept was a result of this process.
This collaborative process continues in the implementation phase of the Living License,
with stakeholders participating in various protection, mitigation, and enhancement
efforts at the projects.
Low Income Rate Assistance Program (LIRAP)
LIRAP is coordinated with four community action agencies in Avista’s Washington
service territory. The program began in 2001 and reviews administrative issues and
needs on a quarterly basis.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 26 of 1069
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP 1-4
Regional Planning
The Pacific Northwest’s generation and transmission system is operated in a
coordinated fashion. Avista participates in the efforts of many organization’s planning
processes. Information from this participation supplements Avista’s IRP process. Some
of the organizations that Avista participates in are:
Western Electricity Coordinating Council
Northwest Power and Conservation Council
Northwest Power Pool
Pacific Northwest Utilities Conference Committee
ColumbiaGrid
Northwest Transmission Assessment Committee
North American Electric Reliability Council
Future Public Involvement
As explained above, Avista actively solicits input from interested parties to enhance its
IRP process. We continue to expand TAC membership and diversity, and maintain the
TAC meetings as an open public process.
2011 IRP Outline
The 2011 IRP consists of nine chapters plus an executive summary and this
introduction. A series of technical appendices supplement this report.
Executive Summary
This chapter summarizes the overall results and highlights of the key results of the 2011
IRP.
Chapter 1: Introduction and Stakeholder Involvement
This chapter introduces the IRP and details public participation and involvement in the
integrated resource planning process.
Chapter 2: Loads and Resources
The first half of this chapter covers Avista’s load forecast and related local economic
forecasts. The last half describes the Company’s owned generating resources, major
contractual rights and obligations, capacity, energy and renewable energy credit
tabulations, and reserve obligations.
Chapter 3: Energy Efficiency
This chapter discusses Avista’s energy efficiency programs. It provides an overview of
the conservation potential assessment and summarizes the energy efficiency modeling
results for the 2011 IRP.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 27 of 1069
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP 1-5
Chapter 4: Policy Considerations
This chapter focuses on some of the major policy issues for resource planning, such as
state and federal greenhouse gas policies and environmental regulations.
Chapter 5: Transmission & Distribution
This chapter discusses Avista’s distribution and transmission systems, as well as
regional transmission planning issues. The chapter includes detail on transmission cost
studies used in the IRP modeling, including a summary of our 10-year Transmission
Plan. The chapter includes a discussion of Avista’s distribution efficiency and grid
modernization projects.
Chapter 6: Generation Resource Options
This chapter covers the costs and operating characteristics of the generation resource
options modeled for the 2011 IRP.
Chapter 7: Market Analysis
This chapter details Avista’s modeling and analysis of the various wholesale markets
applicable to the 2011 IRP.
Chapter 8: Preferred Resource Strategy
This chapter details Avista’s 2011 Preferred Resource Strategy (PRS) and explains how
the PRS could change in response to scenarios differing from the Expected Case.
Chapter 9: Action Items
This chapter provides an overview of the progress made on Action Items from the 2009
IRP. It details new Action Items to start and/or complete between the issuance of the
2011 IRP and prior to the 2013 IRP.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 28 of 1069
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP 1-6
Regulatory Requirements
The IRP process for Washington has several requirements documented in Washington
Administrative Code (WAC). Table 1.3 summarizes where within the IRP the applicable
WACs are addressed.

Table 1.1 Washington IRP Rules and Requirements

Rule and Requirement Plan Citation
WAC 480-100-238(4) – Work
plan filed no later than 12 months
before next IRP due date. Work
plan outlines content of IRP.
Work plan outlines method for
assessing potential resources.
Work plan submitted to the UTC on August 31,
2010; see Appendix B for a copy of the Work Plan.
WAC 480-100-238(5) – Work
plan outlines timing and extent of
public participation.
Appendix B
WAC 480-100-238(2)(a) – Plan
describes mix of energy supply
resources.
Chapter 6- Generation Resource Options
WAC 480-100-238(2)(a) – Plan
describes conservation supply.
Chapter 3- Energy Efficiency
WAC 480-100-238(2)(a) – Plan
addresses supply in terms of
current and future needs of utility
ratepayers.
Chapter 2- Loads & Resources
WAC 480-100-238(2)(b) – Plan
uses lowest reasonable cost
(LRC) analysis to select mix of
resources.
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers resource
costs.
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers market-
volatility risks.
Chapter 4- Policy Considerations
Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy
WAC 480-100-238 (2)(b) – LRC
analysis considers demand side
uncertainties.
Chapter 3- Energy Efficiency
WAC 480-100-238(2)(b) – LRC
analysis considers resource
dispatchability.
Chapter 6- Generation Resource Options
Chapter 7- Market Analysis
WAC 480-100-238(2)(b) – LRC
analysis considers resource
effect on system operation.
Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 29 of 1069
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP 1-7
WAC 480-100-238(2)(b) – LRC
analysis considers risks imposed
on ratepayers.
Chapter 4- Policy Considerations
Chapter 6- Generation Resource Options
Chapter 7- Market Analysis
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers public policies
regarding resource preference
adopted by Washington state or
federal government.
Chapter 2- Loads & Resources
Chapter 4- Policy Considerations
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers cost of risks
associated with environmental
effects including emissions of
carbon dioxide.
Chapter 4- Policy Considerations
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(c) – Plan
defines conservation as any
reduction in electric power
consumption that results from
increases in the efficiency of
energy use, production, or
distribution.
Chapter 3- Energy Efficiency
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan
includes a range of forecasts of
future demand.
Chapter 2- Loads & Resources
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan
develops forecasts using
methods that examine the effect
of economic forces on the
consumption of electricity.
Chapter 2- Loads & Resources
Chapter 5- Transmission & Distribution
Chapter 8- Preferred Resource Strategy
WAC 480-100-238-(3)(a) – Plan
develops forecasts using
methods that address changes in
the number, type and efficiency of
end-uses.
Chapter 2- Loads & Resources
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution

WAC 480-100-238(3)(b) – Plan
includes an assessment of
commercially available
conservation, including load
management.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution

WAC 480-100-238(3)(b) – Plan
includes an assessment of
currently employed and new
policies and programs needed to
obtain the conservation
improvements.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 30 of 1069
Chapter 1- Introduction and Stakeholder Involvement
Avista Corp 2011 Electric IRP 1-8
WAC 480-100-238(3)(c) – Plan
includes an assessment of a wide
range of conventional and
commercially available
nonconventional generating
technologies.
Chapter 6- Generator Resource Options
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(d) – Plan
includes an assessment of
transmission system capability
and reliability (as allowed by
current law).
Chapter 5- Transmission & Distribution

WAC 480-100-238(3)(e) – Plan
includes a comparative
evaluation of energy supply
resources (including transmission
and distribution) and
improvements in conservation
using LRC.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution

WAC-480-100-238(3)(f) –
Demand forecasts and resource
evaluations are integrated into
the long range plan for resource
acquisition.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
Chapter 6- Generator Resource Options
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(g) – Plan
includes a two-year action plan
that implements the long range
plan.
Chapter 9- Action Items
WAC 480-100-238(3)(h) – Plan
includes a progress report on the
implementation of the previously
filed plan.
Chapter 9- Action Items
WAC 480-100-238(5) – Plan
includes description of
consultation with commission
staff. (Description not required)
Chapter 1- Introduction and Stakeholder
Involvement
WAC 480-100-238(5) – Plan
includes description of work plan.
(Description not required)
Appendix B
WAC 480-107-015(3) – Proposed
request for proposals for new
capacity needed within three
years of the IRP.
Chapter 8- Preferred Resource Strategy

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 31 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-1
2. Loads & Resources

Introduction & Highlights
An explanation and quantification of Avista’s loads and resources are integral to the
Integrated Resource Plan (IRP). The first half of this chapter summarizes customer and
load forecasts, including forecast ranges, load growth scenarios, and an overview of
enhancements to forecasting models and processes. The second half of the chapter
covers Avista’s current resource mix, including descriptions of owned and operated
generation, as well as long-term power purchase contracts.

Economic Conditions in Avista’s Service Territory
Avista serves electricity customers in most of the urban and suburban areas of 24
counties of eastern Washington and northern Idaho. The service territory is
geographically and economically diverse. Figure 2.1 shows the Company’s electricity
and natural gas service territories.

The Inland Northwest has transformed over the past 25 years, from a natural resource-
based manufacturing economy to a diversified light manufacturing and services
economy. The United States Forest Service manages a significant portion of the
mountainous areas of the region. Reduced timber harvests on federal lands have
closed many local sawmills. Two pulp and paper plants served by Avista manage large
forest holdings and face stiff domestic and international competition for their products.

Avista’s service territory experienced periods of significant unemployment during the
two national recessions of the 1980s. The 1991/92 national recession mostly bypassed
Avista’s service territory, but the 2001 recession greatly affected the area. The IRP
Expected Case projects the present recession to end in 2011. The employment data
reflects the effects of economic recession and expansion. Avista tracks employment
data for the three principal counties in its electricity service territory: Bonner, Kootenai
and Spokane.

Section Highlights
Historic conservation acquisitions are included in the load forecast; higher
acquisition levels anticipated in the IRP reduce the load forecast further.
Annual electricity sales growth from 2012 to 2031 averages 1.6 percent.
Expected energy deficits begin in 2020, growing to 475 aMW by 2031.
Expected capacity deficits begin in 2019, growing to 883 MW by 2031.
Current conservation programs push the need for resources out by two years
for energy and six years for capacity.
Renewable portfolio requirements drive near-term resource needs.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 32 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-2
Figure 2.1: Avista’s Service Territory and Generation Resources

Population is generally more stable than employment during times of economic change;
however, it can contract during severe economic downturns as people leave in search
of employment opportunities. Over the past 25 years, the region experienced a net
population loss only in 1987. Figure 2.2 details historic and projected annual population
changes in Kootenai and Spokane counties. Figure 2.3 shows total population.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 33 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-3
Figure 2.2: Population Percent Change for Spokane and Kootenai Counties

Figure 2.3: Total Population for Spokane and Kootenai Counties
People, Jobs and Customers
The October 2010 IRP forecast relies on an August 2010 national and September 2010
county-level forecasts. The data focus on two counties–Spokane County in Washington,
and Kootenai County in Idaho–that comprise more than 80 percent of our service area
0%
1%
2%
3%
4%
5%
6%
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
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9
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1
1
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20
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5
pe
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c
h
a
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Kootenai County
Spokane County
0
100
200
300
400
500
600
700
800
900
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
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20
0
7
20
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20
1
1
20
1
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3
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20
3
3
20
3
5
th
o
u
s
a
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d
s
Kootenai County
Spokane County
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 34 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-4
economy. Avista purchases the employment and population forecasts from Global
Insight, Inc., an internationally recognized economic forecasting consulting firm.

The Third Technical Advisory Committee included sections on the load forecast and its
underlying assumptions. Table 2.1 presents the key forecast assumptions presented at
that meeting.

Table 2.1: Global Insight National Long Range Forecast Assumptions

Assumption Average Assumption Average
Gross Domestic Product 2.7% Housing Starts (millions) 1.58/year
Consumer Price Index 1.9% Job Growth 1.0%/year
Imported Crude 2000$ $70 Worker Productivity 2.0%
Federal Funds Rate 4.75% Consumer Sentiment 90
Unemployment Rate 5.0%

In 2010, as part of a revision in materials provided under contract to Avista, Global
Insight began producing housing start forecasts consistent with the population and
employment forecasts, as shown in Figure 2.4.

Figure 2.4: House Starts Total Private (SAAR)
Employment growth often drives population growth. Figure 2.5 shows historical
employment trends from 1995, and forecast growth through 2035. Overall non-farm
wage and salary employment over the past 15 years averaged 2.9 percent for Kootenai
County and 1.0 percent for Spokane County.

0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
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20
1
5
20
1
7
20
1
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20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
Spokane County
Kootenai County
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 35 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-5
Figure 2.5: Percent Change to Employment

Figure 2.6 provides additional non-farm employment data. Over the forecast period,
non-farm employment growth is 1.5 percent and 0.9 percent for Spokane and Kootenai
counties, respectively. Employment growth is approximately 3,000 new jobs per year.

Figure 2.6: Non-Farm Employment

-8%
-6%
-4%
-2%
0%
2%
4%
6%
8%
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
Kootenai County
Spokane County
-8%
-6%
-4%
-2%
0%
2%
4%
6%
8%
19
9
5
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
Kootenai County
Spokane County
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 36 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-6
Customer growth projections follow baseline economic forecasts. Employment statistics
have the greatest probability of near term change as the region emerges from the
recession in 2011. Avista tracks four key customer classes: residential, commercial,
industrial, and street lighting. A linear regression using housing starts as the
independent variable is the basis for the residential customer forecasts. Commercial
forecasts rely on a linear regression of residential growth. Industrial customer growth
follows employment growth. Street lighting customer growth is trended with population
growth.

Avista forecasts sales by rate schedule. Overall customer forecasts are a compilation of
the various rate schedules. For example, the residential class forecast is comprised of
separate forecasts prepared for rate schedules 1, 12, 22, and 32 for Washington and
Idaho. See Figure 2.7 for annual customer growth levels by rate class.

Figure 2.7: Avista Customer Forecast

On average during calendar 2010, Avista served 356,567 retail customers: 315,275
residential, 39,488 commercial, 1,375 industrial and 449 street lighting. This is a 15
percent increase from 309,871 retail customers in 2000. In 2010, 33.4 percent of
residential customers, 42.0 percent of commercial customers, 34.6 percent of industrial
customers, and 27.7 percent of street lighting customers were located in Idaho; the
balance was located in Washington. The 2035 forecast predicts 474,316 retail
customers: 419,739 residential, 52,172 commercial, 1,635 industrial and 770 street
lighting. The 25-year compound growth rate averages 1.1 percent, down from 1.7
percent in the 2009 IRP and consistent with a lower population forecast.

250,000
300,000
350,000
400,000
450,000
500,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
Street Lights Industrial
Commercial Residential
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 37 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-7
Weather Forecasts
The Expected Case electricity sales forecast uses 30-year monthly temperature
averages recorded at the Spokane International Airport weather station through 2009.
Several other weather stations are located in Avista’s service territory, but their data are
available for a much shorter duration and high correlations exist between the Spokane
International Airport and these weather stations.

Sales forecasts are prepared using monthly data, as more granular load information is
not available. Heating degree-days measure cold weather load sensitivity; cooling
degree-days measure hot weather load sensitivity.

The load forecast includes projection of climate change impact. Ample evidence of
cooling and warming trends exists in the historical record. The recent trend is a warming
climate compared to the 30-year average. Avista relies on the University of Washington
―Climate Change Scenarios‖ 2008 study converted to heating and cooling degree-days.1
This study provides warming to 87.2 percent of the present 30-year average. Cooling
degree-days are 144.3 percent.

Price Elasticity
Price elasticity is an important consideration in any electricity demand forecast. It
measures the ratio between the demand for electricity and a change in its price. A
consumer who is sensitive to price change has a relatively elastic demand profile. A
customer who is unresponsive to price changes has a relatively inelastic demand
profile. During the 2000-2001 Western Energy Crisis customers displayed increasing
price sensitivity and reduced overall usage in response to relatively large changes in the
price of electricity.

Cross elasticity of demand, or cross-price elasticity, measures the relationship between
the quantities of electricity demanded and to the quantity of potential electricity
substitutes (e.g., propane or natural gas for heat) when the price of electricity increases
relative to the price of the substitute product. A positive cross elasticity coefficient
indicates cross-price elasticity between electricity and the substitute. A negative cross
elasticity coefficient indicates the absence of cross-price elasticity, and that considered
product is not a substitute for electricity but is instead complementary to it. In other
words, an increase in the price of electricity increases the use of the complementary
good, and a decrease in the price of electricity decreases the use of the complementary
good.

The principal application of cross elasticity impact in the IRP is its substitutability by
natural gas in some applications, including water and space heating. The correlation
between retail electricity prices and the commodity cost of natural gas has increased in
recent years as the industry has become more reliant on gas-fired generation to meet
load growth. This increased positive correlation has reduced the net effect of cross price
elasticity between retail natural gas and electricity prices.

1 http://cses.washington.edu/cig/fpt/ccscenarios.shtml.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 38 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-8
Income elasticity measures the relationship between a change in consumer income and
the change in consumer demand for electricity. As incomes rise, the ability of a
consumer to pay for more electricity increases. The ability to afford electricity-
consuming appliances also increases. Simply stated, as incomes rise consumers are
more likely to purchase more electricity-consuming equipment, live in larger dwellings
that use more electricity, and use the electrical equipment they have more often. Two of
the most cited present examples of income elasticity are the increased proliferation of
mobile electronic devices and high definition televisions.

The IRP estimates price elasticity by customer class for use in our electricity and natural
gas demand forecasts. The price elasticity statistics used in the 2011 IRP are negative
0.15 for residential and negative 0.10 for commercial customers. Natural gas and
electricity cross-price elasticity is positive at 0.05. Income elasticity is positive 0.75,
meaning electricity is more affordable as incomes rise.

The baseline forecast used in the Expected Case assumes that rising incomes offset
rising electricity and natural gas prices. Thus, there is no net expected impact on
electricity consumption other than that caused by climate change and energy efficiency
programs.

Retail Price Forecast
The retail sales forecast assumes retail prices increase at an average annual rate of
eight percent from 2010 to 2018, followed by increases at the rate of general economic
inflation thereafter. Carbon legislation and renewable energy targets are responsible for
approximately one-fourth of the rate rise.2

Conservation
It is difficult to separate the interrelated impacts of rising electricity and natural gas
prices, rising incomes, and conservation programs on the load forecast. Avista collects
data on total demand, and derives from this data consumption change impacts. Avista
has encouraged its customers to conserve electricity by offering conservation programs
to its customers since 1978. Electricity usage impacts of these programs affect historical
data; therefore, we conclude that the forecast already contains the impacts of existing
conservation levels (7.5 aMW per year of new acquisition). As the 2011 IRP forecasts
increased levels of conservation acquisition relative to history, the increased quantities
reduce retail loads below Expected Case forecast levels.

Use per Customer Projections
A database of monthly electricity sales and customer numbers by rate schedule forms
the basis of the usage per customer forecasts by rate schedule, customer class, and
state from 1997 to 2010. Historical data is weather-normalized to remove the impact of

2 This result assumes that the legislation does not mitigate the impacts of GHG legislation by issuing free
utility allocations. Avista develops its load forecast independently of the IRP process. The load forecast
mitigation assumption therefore differs from the Expected Case in the IRP where carbon mitigation
legislation provides significant offsets and thereby limits the overall rate impact of carbon legislation.
Avista does not expect this assumption difference to affect significantly the IRP results.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 39 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-9
heating and cooling degree-day deviations from expected normal values, as discussed
above. Retail electricity price increases reduce electricity usage per customer.

The 2011 IRP includes a forecast of electric vehicles in the Expected Case based on
projections made by the Northwest Power and Conservation Council in its Sixth Power
Plan. The electric fleet is a combination of plug-in hybrids and electric-only passenger
vehicles.

The residential usage per customer forecast trends flat over the long term. This result is
the combination of reductions from embedded conservation, warming temperatures,
price elasticity effects, and increases from electricity vehicle use. The forecast of
household size decreases over time, as shown in Figure 2.8.

Figure 2.8: Household Size Index
Residential customers tend to be homogeneous relative to size of their dwellings.
Commercial customers, on the other hand, are heterogeneous, ranging from small
customers with varying electricity intensity per square foot of floor space to big box
retailers with generally high intensities. The addition of new large commercial
customers, including additions to largest universities and hospitals, can greatly skew
average use per average customer statistics. Usage forecasts for the residential and
commercial sectors are contained in Figure 2.9.

Estimates for residential usage per customer across all schedules are relatively smooth.
Commercial usage per customer increases for several years due to additional existing
and new buildings housing very large customers, including Washington State University
and Sacred Heart Medical Center. Expected additions for very large customers are
included in the forecast through 2015; no additions are included after 2015. Avista
includes only publicly announced long lead-time buildings in its load forecast.

94%
95%
96%
97%
98%
99%
100%
101%
102%
103%
104%
1995 2000 2005 2010 2015 2020 2025 2030 2035
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 40 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-10
Figure 2.9: Electricity Usage per Customer

Retail Electricity Sales Forecast
Major economic changes between 1997 and 2010 affected the region, not the least of
which was a marked increase in wholesale and retail electricity prices. The energy crisis
of 2000-01 included widespread and permanent conservation efforts by our customers.
Several large industrial facilities closed permanently during the 2001-02 economic
recession. In 2004, rising retail electricity rates further reinforced conservation efforts.
Recently, the economy has experienced a significant recession from which it is slowly
emerging. The recession reduced loads below what they otherwise would be.

Retail electricity consumption rose from 8.2 million MWh in 2000 to 8.9 million MWh in
2010. This 0.75 percent annual average increase was net of the combined impacts of
higher prices and resultant decreases in electricity demand from the Energy Crisis and
economic recessions. Loads recover due to stabilizing electricity prices and recovery
from the present recession. Forecasted average annual increase in retail sales over the
2010 to 2035 period is 1.6 percent.

The sales forecast takes a ―bottom up‖ approach, summing individual customer class
forecasts of customers and usage per customer to produce a retail sales forecast.
Individual forecasts for our largest industrial customers (Schedule 25) include planned
or announced production increases or decreases. Lumber and wood products industries
have slowed down from very high production levels, consistent with the decline in
housing starts at the national level caused by the present economic recession. Lumber
and wood products sector load forecasts account for decreased production levels.
70,000
75,000
80,000
85,000
90,000
95,000
10,000
10,500
11,000
11,500
12,000
12,500
13,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
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20
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20
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(
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(
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)
Residential
Commercial
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 41 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-11
Anticipated sales to aerospace and aeronautical equipment suppliers have increased,
and local plants have announced plans to hire more workers and increase their output.

The forecast for 2035 is 13.11 billion kWh, representing a 1.6 percent compounded
increase in retail sales. See Figure 2.10 for Avista’s retail sales forecast.

Figure 2.10: Avista’s Retail Sales Forecast

Load Forecast
Retail sales provide the data used to project load. Retail sales translate into average
megawatt hours using a regression model ensuring monthly load shapes conform to
history. The load forecast is a retail sales forecast combined with line losses across
incurred in the delivery of electricity across the Avista transmission and distribution
system.

Figure 2.11 presents annual net native load growth. Note the significant drop in the
2000-2001 Western Energy Crisis, and smaller declines in the 2009-10 recession
period. Loads from 1997 to 2010 are not weather normalized. Annual growth is
expected to be 1.7 percent compounded over the next twenty and twenty-five years, the
same growth rate as the 2009 IRP but from a lower base of 2010 instead of 2008.

0
2
4
6
8
10
12
14
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
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7
20
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20
1
1
20
1
3
20
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Street Lights Industrial
Commercial Residential
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 42 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-12
Figure 2.11: Annual Net Native Load
Peak Demand Forecast
The peak demand forecast represent expected peaks for each year of the IRP
timeframe, not extreme weather peak demands.3 The demand forecast is the product of
an 11-year regression of actual peak demand and native load. Winter and summer peak
demand forecasts are in Figure 2.12.4 Peak loads grow at 1.2 percent compounded
between 2010 and 2020 (219 MW), 1.5 percent over the 20-year IRP period (571 MW),
and 1.55 percent over the 25-year forecast (796 MW).

3 The expected peak demand has a 50 percent chance of exceedance in any year. Historical years
present actual peak demands by year. 4 Ibid.
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
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20
2
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 43 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-13
Figure 2.12: Winter and Summer Peak Demand
Extreme weather events influence historical peak load data. The comparatively low
1999 peak demand figure was the result of a warmer-than-average winter peak day; the
peak in 2006 was the result of a below-average winter peak day. The 1999 and 2006
peak demand values illustrate why relying on compound growth rates and forecasted
expected peak demand is an oversimplification, and why the Company plans to own or
control enough generation assets and contracts to meet peak demand during extreme
weather events.

Avista has witnessed significant summer load growth in recent years primarily due to
rising air conditioning penetration in its service territory. However, Avista expects to
remain a winter-peaking utility in the near future. It is possible, and we have seen it
occur as recently as 2001, where very mild winter temperatures combined with
extremely hot summer temperatures in a given calendar year results in our summer
peak load exceeding our winter demand level.

The Company produced high and low load forecasts to test the IRPs Preferred
Resource Strategy. These forecasts are very difficult to create because many factors
influence the outcome, and because Avista is unable to obtain alternative economic
forecasts at the county level from Global Insight. In past IRPs Avista used ranges from
the Northwest Power and Conservation Council’s Sixth Power Plan as a guide. This IRP
relies on consultation with internal and external advisors and uses a growth multiplier on
the Expected Case forecast of 1.5 for the high case and 0.5 for the low case.

1,000
1,200
1,400
1,600
1,800
2,000
2,200
2,400
2,600
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
me
g
a
w
a
t
t
s
Summer
Winter
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 44 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-14
The Expected Case load growth is 1.6 percent. The high growth case scenario is 2.33
percent and the low growth case scenario is 0.93 percent as shown in Figure 2.13. The
Company believes these high and low growth ranges are consistent with the Sixth
Power Plan’s medium high and medium low ranges.

Figure 2.13: Electricity Load Forecast Scenario
Avista Resources and Contracts
Avista relies on a diverse portfolio of generating assets to meet customer loads,
including owning and operating eight hydroelectricity projects located on the Spokane
and Clark Fork Rivers. Its thermal assets include partial ownership of two coal-fired
units in Montana, five natural gas-fired projects, and a biomass plant located near Kettle
Falls, Washington.

Spokane River Hydroelectric Projects
Avista owns and operates six hydroelectric projects on the Spokane River. These
projects received a new 50-year FERC operating license in June 2009. The following
section describes the Spokane River projects and provides the maximum on-peak
capacity and nameplate capacity ratings for each plant. The maximum on-peak capacity
of a generating unit is the total amount of electricity a plant can safely generate. This is
often higher than the nameplate rating for hydroelectric projects. The nameplate, or
installed capacity, is the capacity of a plant as rated by the manufacturer. All six of the
hydroelectric projects on the Spokane River connect to Avista’s transmission system.

1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
av
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m
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t
t
s
High
Low
Expected Case
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 45 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-15
Post Falls
Post Falls is the upper most hydroelectricity facility on the Spokane River. It is located
near the Washington/Idaho border. The project began operating in 1906, and during
summer months maintains the elevation of Lake Coeur d’Alene. The project has six
units, with the last unit added in 1980. The project is capable of producing 18.0 MW and
has a 14.75 MW nameplate rating.

Upper Falls
The Upper Falls project began generating in 1922 in downtown Spokane, and now is
within the boundaries of Riverfront Park. This project is comprised of a single 10.0 MW
unit with a 10.26 MW maximum capacity rating.

Monroe Street
The Monroe Street facility was Avista’s first generation facility. It began serving
customers in 1890 near what is now Riverfront Park. Rebuilt in 1992, the single
generating unit has a 15.0 MW maximum capacity rating and a 14.8 MW nameplate
rating.

Nine Mile
A private developer built the Nine Mile project in 1908 near Nine Mile Falls, Washington,
nine miles northwest of Spokane. The Company purchased the project in 1925 from the
Spokane & Eastern Railway. Its four units have a 17.6 MW maximum capacity and a
26.4 MW nameplate rating.5 The facility received a rubber dam in 2010, replacing the
original flashboard system that maintained higher summer elevations.

The Nine Mile facility presently has major equipment outages. Unit 1 is out of service
and Unit 2 is limited to half load. Unit 4 failed in the spring of 2011. Avista is evaluating
options to restore the plant to full service. Restoration options include refurbishment of
the existing powerhouse, including new turbine runners, or a new powerhouse located
downstream from the existing powerhouse. A decision on the final configuration of Nine
Mile is not yet determined. The Company expects any new generation at the plant will
meet Washington State Energy Independence Act requirements.

Long Lake
The Long Lake project is located northwest of Spokane and maintains the Lake
Spokane reservoir, also known as Long Lake. The facility was the highest spillway dam
with the largest turbines in the world when completed in 1915. The plant received new
runners in the 1990s, adding 2.2 aMW of additional energy. The project’s four units
provide 88.0 MW of combined capacity and have an 81.6 MW nameplate rating.

Little Falls
The Little Falls project, completed in 1910 near Ford, Washington, is the furthest
downstream hydro facility on the Spokane River. A new runner upgrade in 2001
generates 0.6 aMW of renewable energy than the previous runner. The facility’s four
units generate 35.2 MW of on-peak capacity and have a 32.0 MW nameplate rating.

5 This is the de-rated capacity considering the outage of unit 1 and de-rate of unit 2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 46 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-16
Clark Fork River Hydroelectric Project
The Clark Fork River Project includes hydroelectric projects located near Clark Fork,
Idaho, and Noxon, Montana, 70 miles south of the Canadian border. The plants operate
under a FERC license through 2046. Both of the hydroelectric projects on the Clark
Fork River connect to Avista’s transmission system.

Cabinet Gorge
The Cabinet Gorge project started generating power in 1952 with two units. The plant
added two additional generators in the following year. The current maximum on-peak
capacity of the plant is 270.5 MW; it has a nameplate rating of 265.2 MW. Upgrades at
this project began with the replacement of the turbine for Unit 1 in 1994. Unit 3 received
an upgrade in 2001. Unit 2 received an upgrade in 2004. Unit 4 received a turbine
runner upgrade in 2007, increasing its generating capacity from 55 MW to 64 MW, and
adding 2.1 aMW of additional energy.

Noxon Rapids
The Noxon Rapids project includes four generators installed between 1959 and 1960,
and a fifth unit added in 1977. The project is in the middle of a major turbine upgrade,
with one unit receiving a new runner in each calendar year beginning in 2009. The
upgrades add 6.6 aMW of total energy and qualify under Washington State’s Energy
Independence Act renewable energy goals.

Total Hydroelectric Generation
In total, Avista’s hydroelectric plants have 1,065.4 MW of on-peak capacity. Table 2.2
summarizes the location and operational capacities of the Company’s hydroelectric
projects. This table includes the average annual energy output of each facility based on
the 70-year hydrologic record for the year ending 2012.

Table 2.2: Company-Owned Hydro Resources

Project Name
River
System Location
Nameplate
Capacity
(MW)
Maximum
Capability
(MW)
Expected
Energy
(aMW)
Monroe Street Spokane Spokane, WA 14.8 15.0 11.6
Post Falls Spokane Post Falls, ID 14.8 18.0 10.0
Nine Mile Spokane Nine Mile Falls, WA 26.0 17.5 12.5
Little Falls Spokane Ford, WA 32.0 35.2 22.1
Long Lake Spokane Ford, WA 81.6 89.0 53.4
Upper Falls Spokane Spokane, WA 10.0 10.2 7.5
Cabinet Gorge Clark Fork Clark Fork, ID 265.2 270.5 124.8
Noxon Rapids Clark Fork Noxon, MT 518.0 610.0 198.3
Total 962.4 1,065.4 440.2

Thermal Resources
Avista owns seven thermal assets located across the Northwest. Each thermal plant
operates through the 20-year duration of the 2011 IRP. The resources provide
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 47 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-17
dependable energy and capacity to serve base loads and provide peak load serving
capabilities. A summary of Avista thermal resources is in Table 2.3.

Colstrip
The Colstrip plant, located in Eastern Montana, consists of four multi-owner coal-fired
steam plants connected to the double circuit 500 kV BPA transmission line under a
long-term wheeling agreement. PPL Global operates the facilities on behalf of the
owners. Avista owns 15 percent of Units 3 and 4. Unit 3 began operating in 1984 and
Unit 4 was finished in 1986. The Company’s share of each Colstrip unit has a maximum
net capacity of 111.0 MW and a nameplate rating of 123.5 MW. In 2006 and 2007
completed capital projects improved efficiency, reliability, and generation capacity at the
plants. The upgrades include new high-pressure steam turbine rotors and digital (versus
the old analog) control systems.

Rathdrum
Rathdrum is a two-unit simple-cycle combustion turbine. This natural gas-fired plant is
located near Rathdrum, Idaho and connects to Avista’s transmission system. It entered
service in 1995 and has a maximum capacity of 178.0 MW in the winter and 126.0 MW
in the summer. The nameplate rating is 166.5 MW.

Northeast
The Northeast plant, located in northeast Spokane, is a two-unit aero-derivative simple-
cycle plant completed in 1978 and connects to Avista’s transmission system. The plant
is capable of burning natural gas or fuel oil, but current air permits prevent the use of
fuel oil. The combined maximum capacity of the units is 68.0 MW in the winter and 42.0
MW in the summer, with a nameplate rating of 61.2 MW. The plant is currently limited to
run no more than approximately 546 hours per year and provides reserve capacity to
protect against reliability concerns and extreme market aberrations.

Boulder Park
The Boulder Park project entered service in Spokane Valley in 2002 and connects to
Avista’s transmission system. The site uses six natural gas-fired internal combustion
reciprocating engines to produce a combined maximum capacity and nameplate rating
of 24.6 MW.

Coyote Springs 2
Coyote Springs 2 is a natural gas-fired combined cycle combustion turbine located near
Boardman, Oregon. This plant connects to BPA’s 500 kV transmission system under a
long-term transmission wheeling agreement. The plant began service in 2003. The
maximum capacity is 274 MW in the winter and 221 MW in the summer and the duct
burner provides the unit with an additional capacity of up to 28 MW. The plant’s
nameplate rating is 287.3 MW.

Kettle Falls and Kettle Falls Combustion Turbine
The Kettle Falls biomass facility entered service in 1983 near Kettle Falls, Washington
and is among the largest biomass plants in North America. The plant connects to
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 48 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-18
Avista’s 115 kV transmission system. The open-loop biomass steam plant uses waste
wood products from area mills and forest slash, but can also burn natural gas. A
combustion turbine (CT), added to the facility in 2002, burns natural gas and increases
overall plant efficiency by sending exhaust heat to the wood boiler.

The wood-fired portion of the plant has a maximum capacity of 50.0 MW and its
nameplate rating is 50.7 MW. The plant typically operates between 45 and 47 MW
because of fuel quality issues. The plant’s capacity increases to 57.0 MW when
operated in combined-cycle mode with the CT. The CT produces 8 MW of peaking
capability in the summer and 11 MW in the winter. The CT resource is limited in winter
when the gas pipeline is constrained; for IRP modeling, the plant does not run when
temperatures fall below zero and pipeline capacity serves local natural gas distribution.

Table 2.3: Company-Owned Thermal Resources

Project Name Location Fuel Type
Start
Date
Winter
Maximum
Capacity
(MW)
Summer
Maximum
Capacity
(MW)
Nameplate
Capacity
(MW)
Colstrip 3 (15%) Colstrip, MT Coal 1984 111.0 111.0 123.5
Colstrip 4 (15%) Colstrip, MT Coal 1986 111.0 111.0 123.5
Rathdrum Rathdrum, ID Gas 1995 178.0 126.0 166.5
Northeast Spokane, WA Gas 1978 68.0 42.0 61.2
Boulder Park Spokane, WA Gas 2002 24.6 24.6 24.6
Coyote Springs 2 Boardman, OR Gas 2003 302.0 249.0 287.3
Kettle Falls Kettle Falls, WA Wood/Gas 1983 47.0 47.0 46.0
Kettle Falls CT6 Kettle Falls, WA Gas 2002 11.0 8.0 7.5
Total 852.6 718.6 840.1

Power Purchase and Sale Contracts
The Company utilizes power supply purchase and sale arrangements of varying lengths
to meet some load requirements. This chapter describes the contracts in effect during
the scope of the 2011 IRP. Contracts provide many benefits including environmentally
low-impact and low-cost hydro and wind power. A 2012 annual summary of Avista large
contracts is in Table 2.5.

Mid-Columbia Hydroelectric Contracts
During the 1950s and 1960s, public utility districts (PUDs) in central Washington
developed hydroelectric projects on the Columbia River. Each plant was oversized
compared to the loads then served by the PUDs. Long-term contracts with public,
municipal, and investor-owned utilities throughout the Northwest assisted with project
financing, and ensured a market for generated surplus power. The contract terms
obligate the PUDs to deliver power to Avista’s points of interconnection with each utility.

6 Includes output of the gas turbine plus the benefit of its steam to the main unit’s boiler.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 49 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-19
Avista entered into long-term contracts for the output of four of these projects ―at cost.‖
Later, the Company competed in capacity auctions in 2009 through 2011 to purchase
new short-term contracts at market-based prices. The Mid-Columbia contracts provide
energy, capacity, and reserve capabilities; in 2012, contracts provide approximately 165
MW of capacity and 86 aMW of energy, see Table 2.4 for further details. Over the next
20 years the Douglas PUD (2018) and Chelan PUD (2015) contracts will expire. Avista
may extend these contracts or even gain additional capacity in auctions; however, we
have no assurance that we will be successful in extending our contract rights. Due to
this uncertainty, the IRP does not include these contracts in the resource mix beyond
their expiration dates.

Table 2.4: Mid-Columbia Capacity and Energy Contracts

Counter Party Project(s)
Percent
Share
(%)
Start
Date
End
Date
Estimated
Capacity
(MW)
Annual
Energy
(aMW)
Grant PUD Priest Rapids 3.7 12/2001 12/2052 34 16
Grant PUD Wanapum 3.7 12/2001 12/2052 37 18
Chelan PUD Rocky Reach 4.5 11/2011 06/2012 57 32
Chelan PUD Rocky Reach 3.0 07/2011 12/2014 38 21
Chelan PUD Rock Island 3.0 07/2011 12/2015 19 11
Douglas PUD Wells 3.3 02/1965 08/2018 29 15
2012 Total Contracted Capacity and Energy 165 86

Lancaster Power Purchase Agreement
Avista acquired the output rights to the Lancaster combined-cycle generating station,
located in Rathdrum, Idaho, as part of the sale of Avista Energy to Shell in 2007.
Lancaster (sometimes referred to in the industry as the Rathdrum Generating Station).
The plant connects to the BPA transmission system under a long-term wheeling
agreement. Avista is working with BPA to interconnect the plant with Avista’s
transmission system at the BPA Lancaster substation. Avista has the sole right to
dispatch the plant, and is responsible for providing fuel and energy and capacity
payments, under a tolling PPA with Energy Investors Funds expiring in October 2026.

Bonneville Power Administration – WNP-3 Settlement
Avista (then Washington Water Power) signed settlement agreements with BPA and
Energy Northwest (formerly the Washington Public Power Supply System or WPPSS)
on September 17, 1985, ending construction delay claims against both parties. The
settlement provides an energy exchange through June 30, 2019, with an agreement to
reimburse Avista for WPPSS – Washington Nuclear Plant No. 3 (WNP-3) preservation
costs and an irrevocable offer of WNP-3 capability under the Regional Power Act.

The energy exchange portion of the settlement contains two basic provisions. The first
provision provides approximately 42 aMW of energy to the Company from BPA through
2019, subject to a contract minimum of 5.8 million megawatt-hours. Avista is obligated
to pay BPA operating and maintenance costs associated with the energy exchange as
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 50 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-20
determined by a formula that ranges from $16 to $29 per megawatt-hour in 1987-year
constant dollars.

The second provision provides BPA approximately 32 aMW of return energy at a cost
equal to the actual operating cost of the Company’s highest-cost resource. A further
discussion of this obligation, and how Avista plans to account for it, is under the
Planning Margin heading of this chapter.

Table 2.5: Large Contractual Rights and Obligations

Contract Type End Date
Winter
Capacity
(MW)
Summer
Capacity
(MW)
2012 Est.
Annual
Energy (aMW)
Canadian Entitlement Sale n/a 8 8 5
Clearwater PURPA 06/2013 75 75 52
Douglas Settlement Purchase 09/2018 2 3 3
Lancaster Purchase 10/2026 290 249 222
Nichols Pumping Sale n/a 7 7 7
PGE Capacity Exchange Exchange 12/2016 150 150 0
Small Power PURPA varies 2 1 2
Stateline Purchase 03/2014 0 0 9
Stimson Lumber Purchase 09/2011 4 5 4
Upriver (net load) Purchase 12/2011 8 -1 6
WNP-3 Purchase 06/2019 82 0 42
Total 628 497 352

Reserve Margins
Planning reserves accommodate situations when loads exceed and/or resource outputs
are below expectations due to adverse weather, forced outages, poor water conditions,
or other contingencies. There are disagreements within the industry on reserve margin
levels utilities should carry. Many disagreements stem from system differences, such as
resource mix, system size, and transmission interconnections

Reserve margins, on average, increase customer rates when compared to resource
portfolios without reserves, because of the cost of carrying additional generating
capacity that is rarely used. Reserve resources have the physical capability to generate
electricity, but high operating costs limit their economic dispatch and revenues to offset
purchase costs.

Avista Planning Margin
Avista retains two planning margin targets—capacity and energy. Capacity planning is a
traditional metric ensuring that utilities can meet peak loads at times of system strain,
and cover variability inherent in their generation resources with unpredictable fuel
supplies, such as wind and hydro, and varying loads.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 51 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-21
Capacity Planning
Avista plans for peak load events using the regional standard of an 18-hour peak event
covering six hours each day for three consecutive days. Further, the IRP uses a
planning margin level approximating the Northwest Power and Conservation Council’s
targets of 23 percent in the winter and 24 percent in the summer. Avista first estimates
operating reserve requirements for on-system generation, load regulation, and wind
integration. It then adds a planning margin of 15 percent to summer peak load and 14
percent to winter peak load. Adjustments to the net position include market purchases
when surplus capacity exists in the Northwest, as represented by the green bars.7 The
planning margin equals 233 MW in 2012. Additional detail is in Appendix A. Figure 2.14
illustrates the winter peak position and Figure 2.15 shows the summer peak position.

Figure 2.14: Winter 18-Hour Capacity Load and Resources

7 Avista relied on work by the Northwest Power and Conservation Council in its Resource Adequacy
Forum exercises to determine the level of surplus summer energy and capacity. Reliance is limited to
Avista’s prorated share of regional load. See
http://www.nwcouncil.org/energy/resource/Adequacy%20Assessment%2070908.xls. NPCC surplus
estimates phase out over 10 years starting in 2013 by reducing its surplus by 10 percent, the 2014
surplus by 20 percent, the 2015 surplus by 30 percent, and so on. The phase out reflects Avista’s opinion
that outer-year surpluses might not be available for various reasons, including unanticipated load growth,
the retirement of existing resources, or transmission interconnections enabling the export of more
generation outside of the Northwest.
-200
300
800
1,300
1,800
2,300
2,800
3,300
3,800
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
Firm Contracts Avista Share of Excess NW Capacity
Peaking Thermals Baseload Thermals
Hydro Load Forecast
Load + Reserves + Planning Margin
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 52 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-22
Figure 2.15: Summer 18-Hour Capacity Load and Resources

Energy Planning
For energy planning, resources must be adequate to meet customer requirements even
where loads are high for extended periods or an outage limits the output of a resource.
Extreme weather conditions can change monthly energy obligations by up to 30
percent. Where generation capability is not adequate to meet these variations,
customers and the utility must rely on the volatile short-term electricity market. In
addition to load variability, a planning margin accounts for variations in hydroelectricity
generation.

As with capacity planning, there are differences in regional opinion on a proper method
for establishing resource planning margins. Many utilities in the Northwest base their
planning on the amount of energy available during the critical water period of 1936/37.8
The critical water year of 1936/37 is low on an annual basis, but it is not necessarily low
in every month. The IRP could target resource development to reach a 99 percent
confidence level on being able to deliver energy to its customers, and it would
significantly decrease the frequency of its market purchases. However, this strategy
requires investments in approximately 200 MW of generation in additional to the
margins included in Expected Case of the IRP. Such expenditure to support this high
level of reliability would put upward pressure on retail rates for a modest benefit. Avista
instead targets a 90 percent monthly energy planning margin confidence interval based
on load hydroelectricity variability. In other words, there is a 10 percent chance of
needing to purchase energy from the market in any given month over the IRP

8 The critical water year represents the lowest historical generation level in the streamflow record.
-200
300
800
1,300
1,800
2,300
2,800
3,300
3,800
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
Firm Contracts Avista Share of Excess NW Capacity
Peaking Thermals Baseload Thermals
Hydro Load Forecast
Load + Reserves + Planning Margin
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 53 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-23
timeframe, but on average, the utility would have the ability to meet all of its energy
requirements and be selling electricity into the marketplace.

Beyond load and hydroelectricity variability, Avista’s WNP-3 contract with BPA contains
supply risk. The contract includes a return energy provision in favor of BPA that can
equal 32 aMW annually. Under adverse market conditions BPA almost certainly would
exercise its rights. BPA last exercised its contract rights in 2001. To account for this
contract risk, the energy planning margin is increased by 32 aMW until the contract
expires in 2019. With the addition of WNP-3, load and hydroelectricity variability, the
total energy planning margin equals 228 aMW in 2012. Additional detail is contained in
Appendix A. See Figure 2.16 for the summary of the annual average energy load and
resource net position.

Figure 2.16: Annual Average Energy Load and Resources

Loss of Load Analysis
In the Northwest, loss-of-load analysis tools help address the issue of how much
planning margin is required. Typical results of these models are Loss of Load
Probability (LOLP), Loss of Load Hours (LOLH), and Loss of Load Expectation (LOLE)
measures. A reliable system has typically been defined as having no more than one
interruption event in twenty years, or 5 percent. These analyses can be helpful, but
usually have an inherent flaw due to the need to assume how much out-of-area
generation is available for the study. Avista developed a loss of load analysis model to
simulate reliability events due to poor hydro, forced outages, and extreme weather
conditions on its system, finding that forced outages are the main driver of reliability
events. Avista has robust transmission rights to the wholesale energy markets, but the
-200
300
800
1,300
1,800
2,300
2,800
3,300
3,800
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Net Market Transactions Peaking Thermals
Baseload Thermals Hydro
Load Forecast Load + Contingency
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 54 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-24
amount of generation actually available for purchase from third parties is difficult to
estimate in a model. To address this concern, a sophisticated regional model must
estimate required regional planning margins. Avista will continue to monitor and
contribute to such regional model development, with the intent of using the regional
model when it becomes available.

Washington State Renewable Portfolio Standard
In the November 2006 general election, Washington State voters approved Citizens
Initiative 937, now known as the Washington state Energy Independence Act. The
initiative requires utilities with more than 25,000 customers to source 3 percent of their
energy from qualified non-hydroelectric renewables by 2012, 9 percent by 2016, and 15
percent by 2020. Utilities also must acquire all cost effective conservation and energy
efficiency measures. Even though Avista does not require any new generation
resources to meet forecasted energy loads through 2019, this new law requires the
Company to acquire additional qualified renewable generation, or renewable energy
certificates (RECs), to meet the initiative’s renewable goals. Table 2.6 at the end of this
chapter details the forecast amount of RECs required to meet Washington state law,
and the amount of qualifying resources has already in the generation portfolio. The
sales forecast uses the current load forecast and does not include additional
conservation as detailed in the Preferred Resource Strategy chapter. It also illustrates
how the Company will maintain a REC reserve margin of approximately 10 aMW in
2016.

Resource Requirements
The resource requirements discussed in this section do not include additional energy
efficiency acquisitions beyond what is in the load forecast. The Preferred Resource
Strategy chapter discusses conservation beyond the assumptions contained in the load
forecast. The following tables present loads and resources to illustrate future resource
requirements.

During winter peak periods (Table 2.7), surplus capacity exists through 2019 after taking
into account market purchases.9 Without these purchases, a capacity deficit would exist
in 2012. Avista believes that the present market can meet these minor winter capacity
shortfalls and therefore will optimize its portfolio to postpone new resource investments
for winter capacity until 2020.

The summer peak projection (Table 2.8) has lower loads than in winter, but resource
capabilities are also lower due to lower hydroelectricity output and reduced capacity at
natural gas-fired resources due to decreased performance during high-temperature
events. The IRP shows persistent summer deficits throughout the 20-year timeframe,
but regional surpluses are adequate to fill in these gaps. Many near-term deficits are
from decreased hydroelectricity capacity during periods of planned maintenance and

9 Avista relied on work by the Northwest Power and Conservation Council in its Resource Adequacy
Forum exercises to determine the level of surplus summer energy and capacity. Reliance is limited to the
Company’s prorate share of regional load.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 55 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-25
upgrades. Taking into account regional surpluses, the load and resource balance is 54
MW short only in 2016. After 2016, when the Portland General Electricity capacity sale
contract expires, the next capacity need is in 2019 at 98 MW.

The traditional measure of resource need in the region is the annual average energy
position. The energy position is in Table 2.9. There is enough energy on an annual
average basis to meet customer requirements until 2020, when the utility is short 49
aMW. Avista will require 112 aMW of new energy by 2025, and 475 aMW in 2031.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 56 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-26
Table 2.6: Washington State RPS Detail (aMW)

On
-
l
i
n
e

Ye
a
r
Up
g
r
a
d
e

En
e
r
g
y
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
WA

S
t
a
t
e

R
e
t
a
i
l

S
a
l
e
s

F
o
r
e
c
a
s
t
62
8

63
0

63
6

64
6

65
4

66
3

67
1

67
8

68
7

69
3

70
1

70
8

71
4

72
1

73
0

73
8

74
6

75
4

76
3

77
2

78
2

79
3

RP
S

%
0%
3%
3%
3%
3%
9%
9%
9%
9%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
15
%
RE
Q
U
I
R
E
D

R
E
N
E
W
A
B
L
E

E
N
E
R
G
Y
19
19
19
20
59
60
61
61
10
4
10
5
10
6
10
7
10
8
10
9
11
0
11
1
11
2
11
4
11
5
11
7
Re
n
e
w
a
b
l
e

R
e
s
o
u
r
c
e
s
Pu
r
c
h
a
s
e
d

R
E
C
s
0
6
6
6
6
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Lo
n
g

L
a
k
e

3
19
9
9
2.
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
Lit
t
l
e

F
a
l
l
s

4
20
0
1
0.
6
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Ca
b
i
n
e
t

2
20
0
4
2.
9
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
Ca
b
i
n
e
t

3
20
0
1
4.
5
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
Ca
b
i
n
e
t

4
20
0
7
2.
0
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
No
x
o
n

1
20
0
9
2.
3
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
No
x
o
n

3
20
1
0
1.
9
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
2
No
x
o
n

2
20
1
1
1.
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
No
x
o
n

4
20
1
2
0.
9
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
Nin
e

M
i
l
e
20
1
2
3.
7
0
0
2
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
To
t
a
l

Q
u
a
l
i
f
y
i
n
g

R
e
s
o
u
r
c
e
s
17
23
26
28
28
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
NE
T

R
E
C

P
O
S
I
T
I
O
N
17
5
7
8
8
(3
7
)
(3
8
)
(3
9
)
(3
9
)
(8
2
)
(8
3
)
(8
4
)
(8
5
)
(8
6
)
(8
7
)
(8
8
)
(8
9
)
(9
0
)
(9
2
)
(9
3
)
(9
5
)
RE
C

B
a
n
k
Pr
e
v
i
o
u
s

Y
e
a
r

B
a
l
a
n
c
e
0
17
21
26
28
28
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
RE
C
'
s

R
e
q
u
i
r
e
d
0
(1
9
)
(1
9
)
(1
9
)
(2
0
)
(5
9
)
(6
0
)
(6
1
)
(6
1
)
(1
0
4
)
(1
0
5
)
(1
0
6
)
(1
0
7
)
(1
0
8
)
(1
0
9
)
(1
1
0
)
(1
1
1
)
(1
1
2
)
(1
1
4
)
(1
1
5
)
(1
1
7
)
RE
C
'
s

G
e
n
e
r
a
t
e
d
/
P
u
r
c
h
a
s
e
d
17
23
26
28
28
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
22
Ex
p
i
r
e
d
/
S
o
l
d

R
E
C
s
0
(2
)
(7
)
(8
)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
NE
T

R
E
C

B
A
N
K
17
21
26
28
28
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
RE
C

R
e
s
e
r
v
e

R
e
q
u
i
r
e
m
e
n
t

(
9
5
t
h

P
E
R
C
E
N
T
I
L
E
)
Lo
a
d
0
1
1
1
1
3
3
3
3
5
5
5
5
5
5
5
5
5
5
6
6
Ex
i
s
t
i
n
g

H
y
d
r
o

U
p
g
r
a
d
e
s
0
6
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
7
To
t
a
l

R
E
C

R
e
s
e
r
v
e

R
e
q
u
i
r
e
m
e
n
t
0
7
8
8
8
10
10
10
10
12
12
12
12
12
12
13
13
13
13
13
13
NE
T

R
E
C

P
O
S
I
T
I
O
N

17
14
21
26
28
(2
0
)
(4
8
)
(4
9
)
(5
0
)
(9
4
)
(9
5
)
(9
6
)
(9
7
)
(9
8
)
(9
9
)
(1
0
1
)
(1
0
2
)
(1
0
3
)
(1
0
5
)
(1
0
6
)
(1
0
8
)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 57 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-27
Table 2.7: Winter 18-Hour Capacity Position (MW)

20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
TO
T
A
L

L
O
A
D

O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e

L
o
a
d
-1
,
6
6
1
-1
,
6
8
8
-1
,
7
0
4
-1
,
7
1
8
-1
,
7
5
1
-1
,
7
8
4
-1
,
8
1
4
-1
,
8
3
9
-1
,
8
6
6
-1
,
8
9
2
-1
,
9
1
9
-1
,
9
4
6
-1
,
9
8
2
-2
,
0
2
0
-2
,
0
6
2
-2
,
0
9
4
-2
,
1
3
1
-2
,
1
6
8
-2
,
2
0
8
-2
,
2
4
9
Fir
m

P
o
w
e
r

S
a
l
e
s
-2
4
2
-2
4
2
-2
1
1
-1
5
8
-1
5
8
-8
-8
-7
-7
-7
-7
-7
-6
-6
-6
-6
-6
-6
-6
-6
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-1
,
9
0
3
-1
,
9
3
0
-1
,
9
1
5
-1
,
8
7
6
-1
,
9
0
9
-1
,
7
9
2
-1
,
8
2
2
-1
,
8
4
6
-1
,
8
7
3
-1
,
8
9
9
-1
,
9
2
5
-1
,
9
5
3
-1
,
9
8
8
-2
,
0
2
7
-2
,
0
6
8
-2
,
1
0
1
-2
,
1
3
7
-2
,
1
7
4
-2
,
2
1
4
-2
,
2
5
5
RE
S
O
U
R
C
E
S
Fir
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
17
5
17
5
17
5
17
5
17
5
17
5
17
4
17
3
90
90
90
90
90
90
90
90
90
90
90
90
Hy
d
r
o

R
e
s
o
u
r
c
e
s
88
0
95
5
96
5
85
4
85
4
86
5
86
1
88
9
88
1
88
9
88
9
88
1
88
9
88
9
88
1
88
9
88
9
88
1
88
9
88
9
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
89
5
60
6
60
6
60
6
60
6
60
6
Win
d

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k
i
n
g

U
n
i
t
s
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
24
2
To
t
a
l

R
e
s
o
u
r
c
e
s
2,
1
9
2
2,
2
6
7
2,
2
7
7
2,
1
6
6
2,
1
6
6
2,1
7
7
2,1
7
2
2,
1
9
9
2,
1
0
8
2,
1
1
6
2,
1
1
6
2,
1
0
8
2,
1
1
6
2,
1
1
6
2,1
0
8
1,8
2
6
1,8
2
6
1,
8
1
8
1,
8
2
6
1,
8
2
6
Pe
a
k

P
o
s
i
t
i
o
n

B
e
f
o
r
e

R
e
s
e
r
v
e
s

P
l
a
n
n
i
n
g
28
9
33
7
36
2
29
0
25
6
38
5
35
0
35
3
23
6
21
7
19
1
15
5
12
7
89
40
-2
7
5
-3
1
1
-3
5
6
-3
8
8
-4
2
9
RE
S
E
R
V
E

P
L
A
N
N
I
N
G
Re
q
u
i
r
e
d

O
p
e
r
a
t
i
n
g

R
e
s
e
r
v
e
s
-1
6
2
-1
6
4
-1
6
3
-1
6
2
-1
6
5
-1
5
9
-1
6
1
-1
6
3
-1
6
5
-1
6
7
-1
7
3
-1
7
6
-1
8
0
-1
8
2
-1
8
6
-1
7
0
-1
7
0
-1
7
1
-1
7
2
-1
7
3
Av
a
i
l
a
b
l
e

O
p
e
r
a
t
i
n
g

R
e
s
e
r
v
e
s
23
42
42
8
8
8
8
34
34
34
34
34
34
34
34
34
34
34
34
34
Pla
n
n
i
n
g

M
a
r
g
i
n
-2
3
3
-2
3
6
-2
3
9
-2
4
0
-2
4
5
-2
5
0
-2
5
4
-2
5
8
-2
6
1
-2
6
5
-2
6
9
-2
7
2
-2
7
7
-2
8
3
-2
8
9
-2
9
3
-2
9
8
-3
0
4
-3
0
9
-3
1
5
To
t
a
l

R
e
s
e
r
v
e
s

P
l
a
n
n
i
n
g
-3
7
2
-3
5
8
-3
6
0
-3
9
4
-4
0
2
-4
0
0
-4
0
7
-3
8
7
-3
9
2
-3
9
8
-4
0
8
-4
1
4
-4
2
3
-4
3
1
-4
4
1
-4
2
9
-4
3
4
-4
4
1
-4
4
7
-4
5
4
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

R
e
s
e
r
v
e
s

P
l
a
n
n
i
n
g
-8
3
-2
1
2
-1
0
5
-1
4
6
-1
5
-5
7
-3
4
-1
5
7
-1
8
1
-2
1
6
-2
5
9
-2
9
6
-3
4
2
-4
0
1
-7
0
4
-7
4
6
-7
9
6
-8
3
5
-8
8
3
Pla
n
n
i
n
g

M
a
r
g
i
n

B
e
f
o
r
e

N
W

M
a
r
k
e
t
16
%
20
%
21
%
16
%
14
%
22
%
20
%
21
%
14
%
13
%
12
%
10
%
8%
6%
4%
-1
1
%
-1
3
%
-1
5
%
-1
6
%
-1
8
%
Av
i
s
t
a

S
h
a
r
e

o
f

E
x
c
e
s
s

N
W

C
a
p
a
c
i
t
y
73
7
65
6
56
5
47
7
40
0
32
6
25
5
18
6
11
5
56
0
0
0
0
0
0
0
0
0
0
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

N
W

M
a
r
k
e
t
65
4
63
5
56
7
37
3
25
4
31
1
19
9
15
2
-4
2
-1
2
5
-2
1
6
-2
5
9
-2
9
6
-3
4
2
-4
0
1
-7
0
4
-7
4
6
-7
9
6
-8
3
5
-8
8
3
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

N
W

M
a
r
k
e
t
55
%
54
%
51
%
41
%
35
%
40
%
34
%
31
%
21
%
16
%
12
%
10
%
8%
6%
4%
-1
1
%
-1
3
%
-1
5
%
-1
6
%
-1
8
%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 58 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-28
Table 2.8: Summer 18-Hour Capacity Position (MW)

20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
TO
T
A
L

L
O
A
D

O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e

L
o
a
d
-1
,
5
1
4
-1
,
5
5
6
-1
,
5
9
7
-1
,
6
4
4
-1
,
6
7
3
-1
,
7
0
1
-1
,
7
2
7
-1
,
7
4
8
-1
,
7
7
1
-1
,
7
9
3
-1
,
8
1
5
-1
,
8
3
8
-1
,
8
6
8
-1
,
9
0
0
-1
,
9
3
7
-1
,
9
6
4
-1
,
9
9
5
-2
,
0
2
6
-2
,
0
5
9
-2
,
0
9
4
Fir
m

P
o
w
e
r

S
a
l
e
s
-2
4
3
-2
1
8
-2
1
2
-1
5
9
-1
5
9
-9
-9
-8
-8
-8
-8
-8
-8
-7
-7
-7
-7
-7
-7
-7
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-1
,
7
5
7
-1
,
7
7
4
-1
,
8
0
9
-1
,
8
0
4
-1
,
8
3
2
-1
,
7
1
0
-1
,
7
3
6
-1
,
7
5
6
-1
,
7
7
8
-1
,
8
0
0
-1
,
8
2
2
-1
,
8
4
6
-1
,
8
7
6
-1
,
9
0
8
-1
,
9
4
4
-1
,
9
7
1
-2
,
0
0
2
-2
,
0
3
3
-2
,
0
6
7
-2
,
1
0
2
RE
S
O
U
R
C
E
S
Fir
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
85
85
85
85
85
85
85
83
83
82
82
82
82
82
82
82
82
82
82
82
Hy
d
r
o

R
e
s
o
u
r
c
e
s
90
0
81
9
90
2
85
9
86
6
86
4
88
5
83
3
84
0
85
9
83
3
84
0
85
9
83
3
84
0
85
9
83
3
84
0
85
9
83
3
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
55
1
55
1
55
1
55
1
55
1
Wi
n
d

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k
i
n
g

U
n
i
t
s
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
To
t
a
l

R
e
s
o
u
r
c
e
s
1,
9
6
0
1,
8
8
0
1,
9
6
2
1,
9
1
9
1,
9
2
6
1,
9
2
4
1,9
4
5
1,
8
9
1
1,
8
9
7
1,9
1
6
1,
8
9
1
1,
8
9
6
1,
9
1
6
1,
8
9
0
1,
8
9
6
1,
6
6
8
1,
6
4
2
1,6
4
8
1,
6
6
8
1,
6
4
2
Pe
a
k

P
o
s
i
t
i
o
n

B
e
f
o
r
e

R
e
s
e
r
v
e
s

P
l
a
n
n
i
n
g
20
3
10
6
15
2
11
6
94
21
4
20
9
13
5
11
9
11
6
68
51
41
-1
8
-4
8
-3
0
4
-3
6
1
-3
8
5
-3
9
9
-4
6
0
RE
S
E
R
V
E

P
L
A
N
N
I
N
G
Re
q
u
i
r
e
d

O
p
e
r
a
t
i
n
g

R
e
s
e
r
v
e
s
-1
5
3
-1
5
7
-1
5
9
-1
6
0
-1
6
2
-1
5
5
-1
5
7
-1
6
0
-1
6
1
-1
6
3
-1
6
5
-1
6
7
-1
6
9
-1
7
1
-1
7
2
-1
5
7
-1
5
6
-1
5
7
-1
5
8
-1
5
8
Av
a
i
l
a
b
l
e

O
p
e
r
a
t
i
n
g

R
e
s
e
r
v
e
s
15
5
66
17
1
15
9
15
9
15
9
16
1
15
8
15
8
16
1
15
8
15
8
16
1
15
8
15
8
16
1
15
8
15
8
16
1
15
8
Pl
a
n
n
i
n
g

M
a
r
g
i
n
-2
2
7
-2
3
3
-2
4
0
-2
4
7
-2
5
1
-2
5
5
-2
5
9
-2
6
2
-2
6
6
-2
6
9
-2
7
2
-2
7
6
-2
8
0
-2
8
5
-2
9
0
-2
9
5
-2
9
9
-3
0
4
-3
0
9
-3
1
4
To
t
a
l

R
e
s
e
r
v
e
s

P
l
a
n
n
i
n
g
-2
2
7
-3
2
5
-2
4
0
-2
4
8
-2
5
5
-2
5
5
-2
5
9
-2
6
4
-2
6
9
-2
7
1
-2
7
9
-2
8
5
-2
8
9
-2
9
8
-3
0
4
-2
9
5
-2
9
9
-3
0
4
-3
0
9
-3
1
4
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

R
e
s
e
r
v
e
s

P
l
a
n
n
i
n
g
-2
4
-2
2
0
-8
7
-1
3
2
-1
6
1
-4
1
-5
0
-1
2
9
-1
5
0
-1
5
5
-2
1
1
-2
3
4
-2
4
9
-3
1
6
-3
5
2
-5
9
9
-6
6
0
-6
8
9
-7
0
8
-7
7
4
Pl
a
n
n
i
n
g

M
a
r
g
i
n

B
e
f
o
r
e

N
W

M
a
r
k
e
t
20
%
10
%
18
%
15
%
14
%
22
%
21
%
17
%
16
%
15
%
12
%
11
%
11
%
7%
6%
-7
%
-1
0
%
-1
1
%
-1
2
%
-1
4
%
Av
i
s
t
a

S
h
a
r
e

o
f

E
x
c
e
s
s

N
W

C
a
p
a
c
i
t
y
27
5
22
1
17
8
14
1
10
7
78
52
31
10
3
0
0
0
0
0
0
0
0
0
0
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

N
W

M
a
r
k
e
t
25
1
1
91
9
-5
4
36
2
-9
8
-1
4
0
-1
5
2
-2
1
1
-2
3
4
-2
4
9
-3
1
6
-3
5
2
-5
9
9
-6
6
0
-6
8
9
-7
0
8
-7
7
4
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

N
W

M
a
r
k
e
t
36
%
22
%
28
%
23
%
20
%
26
%
24
%
18
%
16
%
16
%
12
%
11
%
11
%
7%
6%
-7
%
-1
0
%
-1
1
%
-1
2
%
-1
4
%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 59 of 1069
Chapter 2: Loads & Resources

Avista Corp 2011 Electric IRP 2-29
Table 2.9: Average Annual Energy Position (aMW)

20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
TO
T
A
L

L
O
A
D

O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e

L
o
a
d
-1
,
1
0
9
-1
,
1
3
1
-1
,
1
4
8
-1
,
1
6
5
-1
,
1
8
6
-1
,
2
0
9
-1
,
2
2
8
-1
,
2
4
4
-1
,
2
6
0
-1
,
2
7
7
-1
,
2
9
3
-1
,
3
1
0
-1
,
3
3
3
-1
,
3
5
7
-1
,
3
8
6
-1
,
4
0
6
-1
,
4
2
9
-1
,
4
5
2
-1
,
4
7
7
-1
,
5
0
2
Fir
m

P
o
w
e
r

S
a
l
e
s
-1
4
0
-1
2
7
-1
0
9
-5
8
-5
8
-6
-6
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-1
,
2
4
9
-1
,
2
5
8
-1
,
2
5
8
-1
,
2
2
3
-1
,
2
4
4
-1
,
2
1
5
-1
,
2
3
4
-1
,
2
4
9
-1
,
2
6
6
-1
,
2
8
2
-1
,
2
9
8
-1
,
3
1
6
-1
,
3
3
8
-1
,
3
6
2
-1
,
3
9
1
-1
,
4
1
1
-1
,
4
3
4
-1
,
4
5
7
-1
,
4
8
2
-1
,
5
0
7
RE
S
O
U
R
C
E
S
Fir
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
16
3
16
4
16
3
16
5
16
3
11
2
11
1
91
66
66
65
65
65
65
65
65
65
65
65
65
Hy
d
r
o
52
2
52
5
52
7
49
5
49
5
49
5
49
0
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
75
5
71
4
75
1
74
4
74
6
74
1
72
4
75
8
72
1
72
1
75
8
72
1
72
1
75
8
68
4
51
5
54
1
51
5
51
5
54
1
To
t
a
l

R
e
s
o
u
r
c
e
s
1,4
4
1
1,
4
0
3
1,
4
4
2
1,
4
0
5
1,
4
0
4
1,
3
4
8
1,
3
2
5
1,
3
3
0
1,2
6
8
1,2
6
8
1,3
0
4
1,
2
6
6
1,
2
6
7
1,
3
0
4
1,
2
2
9
1,
0
6
0
1,
0
8
7
1,
0
6
0
1,0
6
0
1,0
8
7
En
e
r
g
y

P
o
s
i
t
i
o
n

B
e
f
o
r
e

C
o
n
t
i
n
g
e
n
c
y

P
l
a
n
n
i
n
g
19
1
14
5
18
4
18
2
16
1
13
3
91
81
2
-1
4
6
-4
9
-7
1
-5
8
-1
6
2
-3
5
1
-3
4
7
-3
9
7
-4
2
1
-4
2
1
CO
N
T
I
N
G
E
N
C
Y

P
L
A
N
N
I
N
G
Pe
a
k
i
n
g

R
e
s
o
u
r
c
e
s
15
3
15
3
15
3
13
8
15
3
15
4
15
3
14
7
14
6
14
5
14
7
14
6
14
5
14
7
14
6
14
5
14
7
14
6
14
5
14
7
Co
n
t
i
n
g
e
n
c
y
-2
2
8
-2
2
9
-2
3
0
-2
3
1
-2
3
2
-2
3
3
-2
3
3
-2
1
6
-1
9
7
-1
9
8
-1
9
8
-1
9
9
-2
0
0
-2
0
1
-2
0
2
-2
0
3
-2
0
4
-2
0
5
-2
0
6
-2
0
0
En
e
r
g
y

P
o
s
i
t
i
o
n

W
i
t
h

C
o
n
t
i
n
g
e
n
c
y

P
l
a
n
n
i
n
g
11
6
69
10
8
89
82
54
11
13
-4
9
-6
7
-4
6
-1
0
3
-1
2
6
-1
1
2
-2
1
8
-4
0
8
-4
0
5
-4
5
6
-4
8
2
-4
7
5
En
e
r
g
y

M
a
r
g
i
n
28
%
24
%
27
%
26
%
25
%
24
%
20
%
18
%
12
%
10
%
12
%
7%
6%
7%
-1
%
-1
5
%
-1
4
%
-1
7
%
-1
9
%
-1
8
%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 60 of 1069

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 61 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-1
3. Energy Efficiency
Introduction
Avista began offering energy efficiency programs in 1978. Some of the most notable
efficiency achievements include the Energy Exchanger program. It converted
approximately 20,000 homes from electricity to natural gas space and/or water heating
from 1992 to 1994. Avista pioneered the country’s first system benefit charge for energy
efficiency in 1995. Our conservation response during the 2001 Western Energy Crisis
exceeded all expectations. Conservation programs regularly meet or exceed regional
shares of energy efficiency gains as outlined by the Northwest Power Planning and
Conservation Council (NPCC).

Figure 3.1 illustrates Avista’s historical electricity conservation acquisitions. The
Company has acquired 156.3 aMW of energy efficiency since 1978; however, the
assumed 18-year average life of the conservation portfolio means that some of the
measures have reached the end of their useful lives and are no longer reducing loads.
The 18-year assumed measure life accounts for the difference between the Cumulative
and Online lines in Figure 3.1.

Section Highlights
Avista began offering conservation programs in 1978.
This IRP includes a Conservation Potential Assessment of the Company’s
Idaho and Washington service territories.
Conservation reduces load growth by 48 percent through the IRP timeframe.
Company-sponsored conservation reduces retail loads by approximately 10
percent, or 120 aMW.
Avista evaluated over 2,800 equipment options and over 1,500 measure
options covering all major end-use equipment, as well as devices and actions
to reduce energy consumption for this IRP.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 62 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-2
Figure 3.1: Historical and Forecast Conservation Acquisition

Energy efficiency programs provide a range of conservation and education programs to
residential, low-income, commercial, and industrial customer segments. The programs
are either prescriptive or site-specific. Prescriptive programs, or standard offers, provide
cash incentives for standardized products such as the installation of high-efficiency
appliances. Prescriptive programs are suitable in situations where uniform products or
offerings are applicable for large groups of homogeneous customers. Standardized
programs are primarily for residential and small commercial customers. Site-specific
programs, or customized services, provide cash incentives for any cost-effective energy
savings measure or equipment with an economic payback greater than one year and
less than eight years for lighting projects or between one and 13 years for all other end-
uses and technologies.

Efficiency programs with paybacks of less than one year are not eligible for incentives,
though Avista will assist a customer in program design and implementation. Site-
specific programs require customized services for commercial and industrial customers
because of the unique characteristics of customers’ premises and processes. In some
cases, when it can be established that similar applications of energy efficiency
measures results in somewhat consistent savings estimates and the technically
achievable savings potential is high, a prescriptive approach is offered. An example is
prescriptive lighting for commercial and industrial applications. While this application is
not purely prescriptive in the traditional sense, such as with a residential program, a
more prescriptive approach for these types of similar energy efficiency installations
provides for an ease of marketability to customers and vendors.

0
60
120
180
240
300
360
420
480
540
600
0
2
4
6
8
10
12
14
16
18
20
19
7
8
19
8
0
19
8
2
19
8
4
19
8
6
19
8
8
19
9
0
19
9
2
19
9
4
19
9
6
19
9
8
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
cu
m
u
l
a
t
i
v
e

s
a
v
i
n
g
s

(
a
M
W
)
an
n
u
a
l

s
a
v
i
n
g
s

(
a
M
W
)
Cumulative
Online
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 63 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-3
To be consistent with I-937 conservation targets (WAC 480-109 and RCW 19.285) and
the NPCC Sixth Power Plan, Avista supplements its energy efficiency activities by
including potentials for transmissions and distribution efficiency measures. More details
about the transmission and distribution efficiency projects are in the Transmission &
Distribution chapter of this IRP.
Conservation Potential Assessment Approach
After publication of the 2009 Electric IRP, the Washington Utilities and Transportation
Commissions (UTC) requested an external Conservation Potential Assessment (CPA)
study for the 2011 IRP. Avista in 2010 retained Global Energy Partners (Global) to
conduct this study for its Idaho and Washington electric service territories. The CPA
identifies a 20-year potentials study for energy efficiency and demand response and
provides data on resources specific to Avista’s service territory for use in the 2011 IRP
and in accordance with the energy efficiency goals in Washington’s Energy
Independence Act (I-937). The energy efficiency potentials consider such things as the
impacts of existing programs, naturally occurring energy savings, the impacts of known
building codes and standards as of 2010, technology developments and innovations,
changes to the economy and energy prices.

Global took the following steps to assess and analyze energy efficiency and demand
response potentials in the Company’s service territory. Figure 3.2 illustrates the steps.

1. Perform a market assessment of base year consumption for the residential
(including low income), commercial, and industrial sectors. The assessment uses
utility and secondary data to characterize customers’ electric usage behavior in
Avista’s service territory. Global uses this market assessment to develop energy
market profiles that describe energy consumption by market segment, vintage
(existing versus new construction), end-use, and technology.
2. Develop a baseline energy forecast by sector and by end-use for the entire study
period.
3. Identify and analyze energy-efficiency measures appropriate for Avista’s service
territory, including regional savings from energy efficiency measures acquired
through the Northwest Energy Efficiency Alliance (NEEA) efforts.
4. Estimate technical, economic, and achievable energy efficiency potential.
Technical potential involves choosing the most efficient measure, regardless of
cost. Economic potential involves choosing the most efficient cost-effective
measure. Achievable potential adjusts economic potential to account for factors
other than pure economics, such as consumer behavior or market penetration
rates.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 64 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-4
Figure 3.2: Analysis Approach Overview
The CPA uses 2009 calendar year data, the first complete year of billing data available
when the study began. Avista’s recent load study, which also uses a 2009 baseline
year, contributed to the selection of the 2009 baseline year for the CPA. This was
Avista’s first external CPA for its Idaho and Washington service territories.

The CPA segments Avista customers by state and by rate class. The rate classes used
in this study included residential, commercial and industrial, general service,
commercial and industrial large general service, extra large commercial, and extra large
industrial. The residential class was further segmented into single family, multi-family,
mobile home and low income customers. The low-income threshold used for this study
was defined as 200 percent of the federal poverty level. Global used the NPCC
calculator to determine future efficiency potentials for the pumping rate class, which
represents 2 percent of total utility loads. Pumping schedules are included in the
calculation of demand response potential, as discussed in the Demand Response
section of this chapter. Within each segment, energy use was characterized by end-use
(e.g., space heating, cooling, lighting, water heat, motors, etc.) and by technology (e.g.,
heat pump, resistance heating, or furnace for space heating).

The baseline forecast is the “business as usual” metric without new utility conservation
programs. Energy savings from new energy efficiency measures are compared against
this baseline. This baseline of annual electricity consumption and peak demand by
customer segment and end-use supports projections of energy usage absent future
efficiency programs. The baseline forecast includes projected impacts of known building
codes and energy efficiency standards as of 2010 when the study was conducted that
have direct bearings on the amount of utility program energy efficiency potential that
exists over and above the effects of these efforts, including projected market condition
changes. Market changes include customer and market growth, income growth, retail
Energy Efficiency
Potential
Energy Market
Profiles
by end use, fuel,
segment, and vintage
Avista data
Secondary data
(NWPCC, U.S. Census)
Forecast assumptions:
Customer growth
Price forecast
Purchase shares
Codes and standards
Energy efficiency measure list
Measure costs
Energy analysis to
estimate savings
Develop prototypes and
perform energy analysis
Baseline Forecast
by End Use
Base-year Energy
Consumption
by state, fuel, and
sector
Avista data
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 65 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-5
rates forecasts, trends in end-use and technology saturations, equipment purchase
decisions, consumer price elasticity, income and persons per household, as well as
customer potential estimates in the context of total energy use in the future so that
projections of available energy efficiency savings can be derived.

The baseline forecast used in the CPA, prior to the consideration of efficiency
potentials, projects overall electricity consumption growth of 48 percent. This
compounded average annual growth rate of 1.7 percent during this 20-year period is
consistent with Avista’s current and previous IRP forecasts.

For each customer sector, a robust list of electrical energy efficiency measures was
compiled, drawing upon the NPCC Sixth Power Plan, the Regional Technical Forum
(RTF), and other measures considered applicable to Avista. This list of energy efficiency
equipment and measures included 2,808 equipment options and 1,524 measure
options, representing a wide variety of end-use equipment, as well as devices and
actions able to reduce energy consumption. A comprehensive equipment list and
measure options are in Appendix C. Measure cost, savings, estimated useful life, and
other performance factors were characterized for the list of measures and economic
screening was performed on each measure for every year of the study to develop the
economic potential. Many measures do not pass the economic screen of avoided cost,
but some measures might become part of the energy efficiency program as contributing
factors evolve during the 20-year planning horizon.
Overview of Energy Efficiency Potentials
Global utilized an approach adhering to the conventions outlined in the National Action
Plan for Energy Efficiency (NAPEE) Guide for Conducting Potential Studies (November
2007).1 The NAPEE Guide represents the most credible and comprehensive national
industry practice for specifying energy efficiency potential. Specifically, three types of
potentials are in this study:
Technical Potential
Conservation potential uses the most efficient option commercially available to each
purchase decision, regardless of cost. This theoretical case provides the broadest
and highest definition of savings potential because it quantifies savings that would
result if all current equipment, processes, and practices in all market sectors were
replaced by the most efficient and feasible technology. Technical potential does not
take into account the cost-effectiveness of the measures. Further, this study defines
technical potential as “phase-in technical potential,” assuming only that the portion of
the current equipment stock that has reached the end of its useful life and is due for
turnover is changed out by the most efficient measures available. Non-equipment
measures, such as controls and other devices (e.g., programmable thermostats)
phase-in over time, just like the equipment measures. Lighting retrofits, which are in
1 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for
2025: Developing a Framework for Change. www.epa.gov/eeactionplan.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 66 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-6
effect early replacements of existing lighting systems, count as a non-equipment
measure in this CPA study.
Economic Potential2
Economical conservation results from the purchase of the most cost-effective option
available for a given equipment or non-equipment measure. Cost effectiveness is
determined by applying the Total Resource Cost (TRC) test using all quantifiable
costs and benefits regardless of who accrues them and inclusive of non-energy
benefits as identified by the Council.3 The inclusion of non-energy benefits did not
make any of the failing measures pass. Measures that passed the economic screen
represent aggregate economic potential. As with technical potential, economic
potential calculations use a phased-in approach. Economic potential is a hypothetical
upper-boundary of savings potential representing only economic measures; it does
not consider customer acceptance and other factors.
Achievable Potential
Achievable Potential refines economic potential by taking into account expected
program participation, customer preferences, and budget constraints. For purposes of
this particular CPA, Global provided two types of achievable potential – Maximum and
Realistic.

Maximum Achievable Potential is the upper boundary of the achievable potential range
or the maximum achievable savings that could be achieved through Avista’s energy
efficiency programs. Maximum Achievable Potential presumes incentives that are
sufficient to ensure customer adoption. Oftentimes, incentives take the form of rebates
that typically represent a substantial portion of the customer’s extra cost for the energy
efficient measure. These high incentives are combined with substantial administrative
and marketing costs that are used for customer awareness campaigns and educational
opportunities. It also considers a maximum participation rate by customers for the
various energy efficiency programs designed to deliver the various measures. Global
also developed a Market Acceptance Rate which is a factor based on the Council’s
ramp rate curves used in the Sixth Power Plan. These factors were applied to the
estimate of economic potential from the CPA study to estimate Maximum Achievable
Potential.

Realistic Achievable Potential represents the lower boundary of achievable potential or
a forecast of achievable savings resulting from customer behavior and penetration rates
of efficient technologies. It uses a set of Program Implementation Factors, which take
into account existing market, financial, political and regulatory barriers that are likely to
limit the amount of savings that may be achieved through energy efficiency programs.
2 The Industry definition of economic potential and the definition of economic potential referred to in this
document are consistent with the definition of “realizable potential for all realistically achievable units”. 3 There are other tests that can be used to represent the economic potential (e.g., Participant or Utility
Cost), but the TRC is generally accepted as the most appropriate representation of economic potential
because it tends to be most representative of the net benefits of energy efficiency to society as a whole.
The economic screen uses the TRC as a proxy for moving forward and representing achievable energy
efficiency savings potential for those measures that are most widely cost-effective.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 67 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-7
For example, it considers that other goals such as low rates and customer equity
influence the development of final program designs and savings targets. It also
considers customer incentive levels that are in line with typical industry practice, defined
marketing campaigns, and internal budget constraints. Political barriers often reflect
differences in regional attitudes toward energy efficiency and its value as a resource.
The Realistic Achievable Potential also reflects recent utility experience and reported
savings from past and present programs.

The CPA forecasts incremental annual Maximum Achievable Potential for all sectors at
9.8 aMW (85,824 MWh) in 2012, increasing to cumulative savings of 321.4 aMW
(2,815,551 MWh) by 2031. The CPA forecasts annual Realistic Achievable Potential for
all sectors at 5.7 aMW (or 49,804 MWh) in 2012, increasing to cumulative savings of
231.2 aMW (or 2,025,679 MWh) by 2031. Table 3-1 and Figure 3-3 show the CPA
results for baseline energy use, technical, economic, and realistic achievable potential.
The projected baseline electricity consumption forecast increases 43 percent during the
20-year planning horizon. Projected achievable energy savings, as a percentage of the
baseline energy forecast, grows from 0.6 percent in 2012 to 16.1 percent in 2031.
Figure 3.3 compares the technical, economic, achievable potentials, and cumulative
first-year savings, at selected years. It is important to note, that in the early years, the
difference between Maximum Achievable Potential and Realistic Achievable Potential is
minimal and converges at the end of the 20-year planning horizon. Realistic Achievable
Potential merely adjusts assumptions regarding the rate at which the savings are
estimated to be acquired during the planning period.

Table 3.1: Energy Forecasts and Cumulative Savings (Across All Sectors for Selected
Years)

Energy Forecasts
(MWh) 2012 2017 2022 2027 2031
Baseline Forecast 8,799,039 9,463,880 10,417,347 11,536,869 12,574,182
Achievable 8,749,236 9,068,483 9,476,769 9,998,002 10,548,503
Economic 8,569,382 8,037,426 8,018,993 8,594,412 9,282,289
Technical 8,487,766 7,441,765 6,981,872 7,281,206 7,842,616
Energy Savings
(MWh) 2012 2017 2022 2027 2031
Achievable 49,804 395,397 940,578 1,538,868 2,025,679
Economic 229,657 1,426,454 2,398,355 2,942,457 3,291,894
Technical 311,274 2,022,115 3,435,475 4,255,664 4,731,566

Energy Savings
(% of Baseline) 2012 2017 2022 2027 2031
Achievable 0.6% 4.2% 9.0% 13.3% 16.1%
Economic 2.6% 15.1% 23.0% 25.5% 26.2%
Technical 3.5% 21.4% 33.0% 36.9% 37.6%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 68 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-8
Figure 3.3: Cumulative Conservation Potentials, Selected Years

Conservation Targets
This IRP process includes conservation targets for Washington’s energy efficiency
portion of the Energy Independence Act (I-937) goal. Other components including
conservation from distribution and transmission efficiency improvements also meeting
this target would be additive to this conservation target for a complete target for
Washington comparable to what is included in the Sixth Power Plan target. Additionally,
since this IRP uses a methodology consistent with the NPCC methodology, the
conservation target for Idaho is more aggressive than required.
Based on first year and incremental savings, Table 3.2 illustrates Avista’s Realistic and
Maximum Achievable Potential for 2012-2013, as well as a comparison with the Sixth
Power Plan’s calculator option 1. This calculator is intended to provide an approximation
of the level of conservation that utilities should target in order to be consistent with the
Council’s regional goals. The CPA study completed for Avista incorporates this
methodology into an Avista-specific estimate of savings potential to be acquired through
its programs.
During the first five years, lighting and appliance standards slow residential baseline
growth rates, reducing the potential for savings from residential energy efficiency
programs. Commercial and industrial potential shows consistent growth.
For the 2012-2013 compliance period, the Sixth Power Plan goal is within the goal
range developed in the CPA, with a floor of Realistic Achievable Potential and a ceiling
of Maximum Achievable Potential. However, the Sixth Power Plan includes components
other than conservation such as distribution system efficiencies. When savings due to
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2031
sa
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b
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Achievable
Economic
Technical
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 69 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-9
these efficiencies are subtracted from the Sixth Power Plan goals, the resulting values
are well within the range of the potential study.

Table 3.2: Incremental Annual Achievable Potential Energy Efficiency (aMW)

2012 2013
NPCC Sixth Power Plan Target
Idaho 5.17 5.60
Washington 8.22 8.90
Total 13.39 14.50

Less Distribution Efficiency from the Sixth Plan
Idaho -0.22 -0.28
Washington -0.47 -0.60
Total -0.69 -0.88

Sixth Power Plan Target without Distribution Efficiency
Idaho 4.95 5.32
Washington 7.75 8.30
Total 12.70 13.62

Incremental Achievable Potential Range4
Idaho 1.95 – 3.50 2.17 – 4.51
Washington 3.74 – 6.30 4.31 – 8.58
Total 5.69 – 9.80 6.48 – 13.09

Achievable from Existing Programs
Idaho 1.58 1.55
Washington 2.93 2.85
Total 4.51 4.40

Goal Range per Conservation Potential Assessment
Idaho 3.53 – 5.09 3.72 – 6.06
Washington 6.67 – 9.23 7.16 – 11.43
Total 10.20 – 14.32 10.88 – 17.49

Figure 3.4 shows incremental annual achievable roughly tracking avoided costs
throughout the study period, but factors in addition to avoided cost can influence
achievable potential, particularly where programs are ramping up or are ramping down.
These impacts are particularly relevant in the early years of the CPA study.

4 Incremental Realistic Achievable Potential was used for purposes of modeling resource acquisition from
conservation. For I-937, a range target will be presented with the ceiling of the range being Maximum
Achievable Potential and the floor being Realistic Achievable Potential as determined by the independent
CPA.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 70 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-10
Figure 3.4: Incremental Annual Achievable Energy Efficiency (MWh) vs. Avoided Cost5

Electricity to Natural Gas Fuel Switching
Fuel switching from electricity to natural gas is included in the targets as described
above. Tables 3.3 and 3.4 illustrate savings potentials from converting electric furnaces
and water heaters to natural gas. Nearly all savings are in the residential sector.
Conversion ramps up slowly, but because it removes most of the electricity use from
two of the largest residential end uses (water heating and space heating), it accounts for
a substantial portion of savings by 2031. For water heating, about one-fourth of the
savings from gas conversions occurs in new construction. For furnaces, new
construction accounts for roughly one-third of the total.

Table 3.3: Cumulative Achievable Savings from Conversion to Natural Gas

2012 2017 2022 2027 2031
Water heater - convert to gas potential
(MWh)
45.7 4,967 69,406 146,834 201,182
Water heater - convert to gas percentage of
total potential
0.1% 1% 7% 10% 10%
Furnace - convert to gas potential (MWh) 10.1 2,527 45,979 108,447 158,470
Water heater - convert to gas percentage of
total potential
0.0% 1% 5% 7% 8%

5 Avoided costs are 2009 real dollars and include energy costs, risk, losses, avoided T&D, and the 10 percent Power
Act premium.
$-
$13
$25
$38
$50
$63
$75
$88
$100
-
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40,000
60,000
80,000
100,000
120,000
140,000
160,000
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(
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Extra Large Industrial Extra Large Commercial
Large Commercial Small Commercial
Residential Avoided Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 71 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-11
Table 3.4: Cumulative Achievable Savings from Conversion to Natural Gas by State
(MWh)

Washington Conversion Potential 2012 2017 2022 2027 2031
Water heater - convert to gas potential 36 3,966 55,623 117,942 161,411
Furnace - convert to gas potential 1 1,509 31,082 76,213 112,522
Total Washington conversion potential 37 5,475 86,705 194,155 273,933
Idaho Conversion Potential 2012 2017 2022 2027 2031
Water heater - convert to gas potential 10 1,001 13,783 28,893 39,770
Furnace - convert to gas potential 9 1,018 14,898 32,234 45,948
Total Idaho conversion potential 19 2,019 28,681 61,127 85,718

Comparison with the Sixth Power Plan Methodology
As required by Washington Administrative Code (WAC) Chapter 480-109-010 (3)(c),
Avista below describes the technologies, data collection, processes, procedures and
assumptions used to develop its I-937 biennial targets, along with changes in
assumptions or methodologies used in the Company’s IRP or the NPCC Sixth Power
Plan. WAC Chapter 480-109-010 (4)(c) requires UTC approval, approval with
modifications, or rejection of the targets.

Global met with the NPCC staff to compare methodologies and approaches to ensure
methodological consistency. The CPA methodology is consistent with the Sixth Power
Plan in several key ways. Both the NPCC Sixth Power Plan and Global’s approaches
utilized end-use models employing a bottom-up approach. The models draw on
appliance stock, saturation levels and efficiencies information to construct future load
requirements. Global conducted a thorough review of baseline and measure
assumptions used by the NPCC and developed a baseline energy use projection,
absent any additional energy efficiency measures while including the impact of known
codes and standards currently approved. The study reviewed and incorporated NPCC
assumptions when Avista-specific or more updated data was not available.

The CPA study developed a comprehensive list of energy-efficiency technologies and
end-use measures, including those in the Sixth Power Plan. Since the efficiency
measures, equipment, and other data used in the Sixth Power Plan are somewhat
dated, information on measures and equipment specific to Avista were updated for this
CPA. Global developed equipment saturations, measure costs, savings, estimated
useful lifetimes and other parameters based on data from the Sixth Power Plan
Conservation Supply Curve workbook databases, the Regional Technology Forum,
NEEA reports, and other data sources. Similar to the Sixth Power Plan, the study
accounts for the difference between lost and non-lost opportunities, and how this affects
the rate at which energy efficiency measures penetrate the market. The study used the
Total Resource Cost (TRC) test as the measure for judging cost-effectiveness. A
comprehensive list of measures and equipment evaluated in the CPA study is included
in Appendix C. For a more detailed discussion of measures and equipment evaluated
within the potential study, please refer to the Conservation Potential Assessment report
prepared by Global in Appendix D.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 72 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-12
After screening measures for cost-effectiveness, the CPA applied a series of factors to
evaluate realistic market acceptance rates and program implementation considerations.
The resulting achievable potential reflects the realistic deployment rates of energy
efficiency measures in Avista’s service territory. These factors account for market
barriers, customer acceptance, and the time required to implement programs. To
develop these factors, Global reviewed the ramp rates used in the Sixth Power Plan
Conservation Supply Curve workbooks and considered Avista’s experience.

The Sixth Power Plan assesses a 20-year period beginning in 2010, while the CPA
study begins in 2012. Where the Sixth Power Plan relies on average regional data, the
CPA utilized data from Avista’s service territory, as well as more recent economic data.
Therefore, an allocation of regional potential based on sales, as applied in the Sixth
Power Plan, would not necessarily account for Avista’s unique service territory
characteristics such as customer mix, use per customer, end-use saturations, fuel
shares, current measure saturations, and expected customer and economic growth. In
addition, some industries included in the Sixth Power Plan might not exist in Avista’s
service territory. While the Sixth Power Plan incorporates Distribution System
efficiencies, the Avista CPA includes only energy efficiency from energy conservation
while Distribution System efficiencies and Thermal System efficiencies would be
incorporated into Avista’s I-937 targets from other sources.

The Sixth Power Plan assumed that 85 percent of the cost-effective, or economic, non-
lost opportunity potential will be achieved over the 20 years covered by the Sixth Power
Plan. The projected achievement amount during the first 10 years (consistent with the I-
937 timeframe) is approximately 60 percent. For lost opportunities, the plan assumes
achievement of approximately 65 percent of the cost-effective, or economic, potential
during the 20-year period. Due to ramp rates used within the plan, this equates to only
37 percent achievement within the first 10 years, the period considered for I-937. The
CPA study assumed that cost-effective measures reach a maximum saturation level of
85 percent over the 20-year period for lost opportunities, and 65 percent to 85 percent
for non-lost opportunities. These figures equal or exceed adoption rates assumed within
the Sixth Power Plan.

Sensitivity of Potential to Customer and Economic Growth
The CPA study shows that energy efficiency offsets roughly 50 percent of load growth,
whereas the Sixth Power Plan estimates that energy efficiency can offset 80 percent.
While Avista’s service territory differs from the larger region in many ways, including its
climate and particular customer mix, there are other contributing factors to this
difference. One significant factor may be the CPA customer and economic growth
assumptions. To understand how growth affects the results of the study, Global
LoadMAP modeled several scenarios with lower customer and economic growth, as
indicated in Table 3.5.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 73 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-13
Table 3.5: Varying Growth Scenario Descriptions

Reference
Scenario
Low Growth
Scenario 1
Low Growth
Scenario 2
Home size
(physical size in
square feet)
~ 1% per year growth Capped at 110% of
existing household
size
Capped at 110% of
existing household size
Per capita income
growth
1.6% 2011–2015;
2.2% 2016–2020;
2.1% thereafter
1.6% after 2016 1.6% after 2016
Residential sector
market growth
1.30% after 2015 (WA)
1.25% after 2015 (ID)
no change 1.0% after 2015 (WA &
ID)
Commercial sector
market growth,
Washington &
Idaho
~ 2.0% (varies by
segment)
no change 1.0% all segments

Table 3.6 shows that as economic and customer growth decreases, the ability of energy
efficiency to offset growth increases. In the reference scenario, energy efficiency offsets
54 percent of growth in consumption, while in the lower growth scenarios, energy
efficiency offsets 55 percent and 77 percent of growth. This is the case because with
reduced levels of new construction, both load growth and energy savings drop, but
savings from the retrofit of existing buildings are a greater proportion of overall growth.

Table 3.6: Varying Growth Scenario Results (MWh)

Reference
Scenario
Low Growth
Scenario 1
Low Growth
Scenario 2
Baseline forecast 2012 8,799,039 8,799,039 8,799,033
Baseline forecast 2031 12,574,182 12,272,136 11,025,256
Load Growth 2012-2031 3,775,143 3,473,097 2,226,222
Achievable potential case forecast 2031 10,697,432 10,361,667 9,302,736
Achievable potential savings 2031 2,025,679 1,910,469 1,722,519
Percentage of growth offset 54% 55% 77%
Avoided Cost Sensitivities
Global modeled several scenarios with varying avoided costs assumptions in addition to
the Expected Case used for the 2011 IRP to test sensitivity to changes in avoided costs.
The scenarios included 150 percent, 125 percent, and 75 percent of the avoided costs
relative to the Expected Case. Figure 3.5 illustrates the avoided cost scenarios. Overall,
due to the technical potential ceiling, energy efficiency proved to be insensitive to
avoided cost assumptions. In particular, acquiring incremental energy efficiency
becomes increasingly expensive, so that increases in avoided costs do not provide
equivalent percentage increases in achievable potential. The Expected Case achievable
potential is approximately 16.8 percent of the baseline forecast by 2031. With the 150
percent avoided cost case, achievable potential increases by 15 percent compared with
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 74 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-14
the Expected Case reference scenario, while the 125 percent and the 75 percent
avoided cost cases yielded achievable potential equal to 79 percent and 108 percent of
the reference scenario respectively. Table 3.5 shows achievable potential under the four
avoided cost scenarios.

In 2012, 52 percent of the projected achievable potential is from residential class
measures. By 2017, a shift occurs whereby 68 percent of the achievable potential
comes from non-residential classes, with the significant portion of these savings, 42
percent, estimated to come through the large general service segment. In the residential
sector in 2017, approximately 40 percent of projected savings come from interior
lighting, followed by water heating, space heating and electronics. In subsequent years,
residential savings from lighting decreases, with space and water heating providing
greater relative savings potential.

In the commercial and industrial sectors, lighting accounts for approximately 62 percent
of savings potential in 2017 followed by heating, ventilation and air conditioning (HVAC),
office equipment, exterior lighting and machine drives. Over time, the savings potential
from lighting decreases, but still remains close to half of the savings potential in 2031.

Figure 3.5: Energy Savings, Achievable Potential Case by Avoided Costs Scenario

0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
3,000,000
3,500,000
4,000,000
4,500,000
5,000,000
20
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0
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me
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o
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s
150% of avoided costs
125% of avoided costs
75% of avoided costs
Technical Potential
100% of avoided costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 75 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-15
Table 3.7: Achievable Potential with Varying Avoided Costs

Reference
Scenario
75% of
Avoided
Costs
125% of
Avoided
Costs
150% of
Avoided
Costs
Achievable potential savings
2031 (MWh)
2,025,679 1,590,850 2,186,730 2,327,510
Percentage change in
savings vs. 100% avoided
cost scenario
n/a -21% 8% 15%

Heat pump water heater measures in the Sixth Power Plan were projected to replace
compact fluorescent lights (CFLs) contribution (i.e., significant savings at relatively low
costs) in earlier plans. The CPA found that heat pump water heaters are not cost-
effective, with the exception of new single-family homes, under the Expected Case.
However, the measure becomes cost-effective for more market segments under the 150
percent of avoided cost scenario.

Figure 3.6 shows supply curves composed of the stacked measures and equipment in
2031 in ascending order of avoided cost. Since there is a gap in the cost of the energy
efficiency measures moving up the supply curve, the measures with a very high cost
cause a rapid sloping of the curve. The portfolio average cost for each case is shown as
well. The shift of the supply curve toward the right as avoided costs increase is a
consequence of increasing amounts of cost-effective potential, but the average cost of
acquiring that potential is increasing also.

Figure 3.6: Supply Curves of the Evaluated Conservation Measures6
6 The triangles in Figure 3.6 indicate the portfolio average cost for each avoided cost scenario.
$0.00
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$0.25
0%5%10%15%20%
co
s
t

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r

k
W
h

s
a
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d
% Reduction from Baseline in 2032
Expected Case
75% avoided costs scenario
125% avoided costs scenario
150% avoided costs scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 76 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-16
Energy Efficiency-Related Financial Impacts
I-937 requires utilities with over 25,000 customers to obtain a fixed percentage of their
electricity from qualifying renewable resources and to acquire all cost-effective and
achievable energy conservation. For the first 24-month period under the law (2010-
2011), this equaled a ramped-in share of the regional ten-year target identified in the
Sixth Power Plan. Penalties of at least $50 per MWh exist for utilities not achieving
Washington targets for conservation resource acquisition.

Regional discussions were under way regarding the definition of “pro-rata” during the
2009 IRP. Avista proposed ramping the 10-year targets identified in the Sixth Power
Plan instead of acquiring 20 percent of the first ten-year target identified in the Sixth
Power Plan. The “pro-rata” amount would have created drastic ramping challenges,
especially in the early years. Due to inconsistencies between the 2009 IRP and the
Council’s methodology, the Company elected to use the NPCC’s Option #1 of the Sixth
Power Plan to establish its conservation acquisition target, adjusted to include electric-
to-natural gas space and water heating fuel conversions. The acquisition target was 11
percent greater than Avista’s IRP energy efficiency target for the same period. In April
2010, the UTC approved the Company’s ten year Achievable Potential and Biennial
Conservation Target Report in Docket UE-100176.

The I-937 requirement to acquire all cost-effective and achievable conservation poses
significant financial implications for Washington customers. In 2012, the projected
incremental annual cost to Washington customers is $2.0 million. This annual amount
grows to $41.8 million by the tenth year, representing a total of $199.2 million over this
ten-year period for Washington. Figure 3.7 shows the annual cost (in millions) for this
acquisition of past and future conservation. As shown in the figure, future cost for new
conservation reflects margin returns as compared to historical acquisition.

This incremental level of acquisition driven by Washington I-937 will result in annual rate
increases to Washington electric customers of an approximate range of $8 to $302 per
average customer across all classes. Figure 3.8 illustrate the annual cost associated
with the energy efficiency acquisition required to meet I-937 goals.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 77 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-17
Figure 3.7: Cost of Existing & Future Conservation

Figure 3.8: Cost of Conservation per Customer per I-937

0
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Nominal Cost
Annual Savings
$0
$50
$100
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1
20
3
2
Avg Customer Cost of Total Conservation
Avg Customer Cost of Incremental Conservation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 78 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-18
Integrating Results into Business Planning and Operations
The CPA and IRP energy efficiency evaluation processes provide high-level estimates
of cost-effective conservation acquisition opportunities. While results of the IRP
analyses establish baseline goals for continued development and enhancement of
conservation programs, the results are not detailed enough to form an acquisition plan.
Avista uses IRP evaluation results to establish a budget for conservation measures, to
help determine the size and skill sets necessary for future conservation operations, and
for identifying general target markets for energy efficiency programs. This section
provides an overview of recent operations of the individual sectors as well as
conservation business planning.

For this IRP, the Company procured its first external conservation potential assessment
study for Washington and Idaho from Global Energy Partners. This study is useful for
the implementation of energy efficiency programs in the following ways.

Identifying by sector, segment, end-use and measure where energy savings may
come from during the next 20-year timeframe. The implementation staff can use
CPA results to determine which segments and end-uses/measures to target
through energy efficiency programs.
Identifying measures with the highest TRC benefit-cost ratios and targeting those
lowest cost resources with the greatest benefit.
Identifying measures that appear to have great adoption barriers by looking at
the economic versus achievable results by measure. Implementation staff can
then better develop programs around barriers that may exist.
Improving the design of current program offerings. Implementation staff can
review the measure level results by sector and compare the savings with the
largest-savings measures currently offered by the Company. This analysis may
lead to the elimination of some programs or the addition of other programs.
Consideration might be given to identifying lost opportunities (i.e. “low-hanging
fruit”) and whether to target one particular measure over another measure. One
possibility may be to offer higher incentives on measures with higher benefits and
lower incentives on measures with lower benefits.

In addition to how the IRP results and the potential study flow into operational planning,
an overview of 2010 and 2011 energy efficiency acquisitions by sector is given below.
This is prior to the implementing the actions mentioned above.

Residential Sector Overview
Avista offers most residential energy efficiency programs through prescriptive, or
standard offer, programs targeting a range of end-uses. Programs offered through this
prescriptive approach by Avista during 2010 included space and water heating
conversions, ENERGRY STAR® appliances, ENERGY STAR® homes, space and water
equipment upgrades and home weatherization.

Avista offers the remaining residential energy efficiency programs through other
channels. For example, a third party administer JACO operates the refrigerator/freezer
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 79 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-19
recycling program. CFL and specialty CFL buy-downs at the manufacturer level provide
customers access to lower-priced CFL bulbs. Home energy audits, subsidized by a
grant from the American Recovery and Reinvestment Act (ARRA), began in 2010. This
program offers home inspections that include numerous diagnostic tests and provides a
leave-behind kit containing CFLs and weatherization materials. Finally, Avista provides
educational tips and CFLs at various rural and urban events in an effort to reach all
areas within its service territory.

Avista processed over 36,000 energy efficiency rebates in 2010, benefiting
approximately 25,000 households. Nearly $6.3 million in customer rebates offset the
cost of implementing energy efficiency upgrades. Residential programs contributed
24,247 MWh and nearly 1.1 million therms of energy savings.

The results of an Ecotope study resulted in several planned modifications to the 2011
residential programs. These modifications include the discontinuation of the windows
program, contractor installed weatherization requirements (eliminating do-it-yourself
projects), reducing incentives for electric to natural gas water heater conversion, and
the inclusion of the rooftop damper program on the residential form. We address these
efficiency program modifications below.

The CPA study illustrates potential markets and provides a list of cost-effective
measures analyzed through the on-going energy efficiency business planning process.
This review of residential program concepts and their sensitivity to more detailed
assumptions will feed into program plans for target markets. Potential measures not
currently considered at the time of the CPA that may arise in the future will be
reevaluated for possible inclusion in the Business Plan.

Residential Energy Efficiency Offering In Depth
Avista encourages customers to take part in home energy audits. Employees and
customers in Spokane County can sign up for a comprehensive home energy audit
offered by Avista for as low as $49. Funding for this pilot program comes from a
combination of Avista energy efficiency funds and federal stimulus dollars through the
Energy Efficiency Community Block Grant program. Avista collaborated with the City of
Spokane, Spokane County and the City of Spokane Valley to provide this program at a
significantly reduced cost.
The home energy audits use certified professionals with state-of-the-art equipment and
techniques to identify home energy use and safety improvements. The auditor
discusses existing energy use, if there are any energy efficiency concerns, and areas of
the home that are not as comfortable as owners would like them to be. Once the audit is
complete, the customer receives a detailed report on the findings, along with
recommendations to make their home more energy efficient.
In addition to a wealth of information, participating homeowners receive an energy
efficiency/weatherization kit with a retail value of approximately $50. It contains compact
fluorescent light bulbs, low-flow showerheads, expanding foam sealant and other
energy-saving materials. Customers are able to visit www.avistautilties.com to find out
more and to view a video about this and other energy efficiency programs.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 80 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-20
Limited Income Sector Overview
Six Community Action Agencies (CAAs) administer low-income programs. During 2010
these programs targeted a range of end-uses including space and water heating
conversions, ENERGY STAR refrigerators, space and water heating equipment
upgrades, and weatherization which are offered site-specifically through individualized
home audits. The Company also funds health and human safety investments
considered necessary to ensure habitability of homes and protect investments in energy
efficiency, as well as administrative fees enabling CAAs to continue to deliver these
programs.

During 2010, the Company convened the Low Income Collaborative to explore new
approaches promoting low-income conservation, identify barriers to its development and
to address issues raised by The Energy Project in Avista’s 2009 Washington General
Rate Case. On September 1, 2010, the Company filed the conclusions of the Low
Income Collaborative as requested by the UTC.

Issues addressed through the low income collaborative included defining the low-
income customer class, identifying market barriers to the success of low income energy
efficiency programs, identifying measures for success, and identifying low income
energy efficiency delivery mechanisms and funding sources.

The CAAs had 2010 budgets of $1.3 million for Washington and $660,000 for Idaho.
The Company processed about 1,500 rebates, benefitting approximately 550
households. During 2010, the Company paid $1.7 million in rebates to the CAAs to
provide fully subsidized energy efficiency upgrades, health and human safety, and
administrative costs for the CAAs to administer these programs. The CAAs spent nearly
$144,000 on health and human safety, which was 8.3 percent of their total expenditures
and within their 15 percent allowance for this spending category. Low Income energy
efficiency programs contributed 2,102 MWh of electricity savings and 61,271 therms of
natural gas savings.

All of the CAAs received a funding increase in 2011 resulting from recent rate cases in
both Washington and Idaho making the total funding $2 million for Washington,
$940,000 for Idaho, and an additional $40,000 for conservation education.

CAAs submitting for reimbursement in 2011 must include the age of the home and
square footage to improve billing analysis and other evaluation efforts. Energy savings
claims are now consistent with the regular residential programs, rather than CAAs using
various models to estimate their energy savings. Impact evaluation led the Company to
believe that these models were treating the installation of measures individually, rather
than incrementally, resulting in overestimates of savings achieved. This change should
provide for higher realization rates since the original estimates should be closer to
actual observations in billing analysis. This modification was made in response to
Ecotope’s 2011 Energy Impact Evaluation Report of Select 2008 Programs.

The CAAs are required to submit marginally cost-effective measures for “pre-approval”
to protect the cost-effectiveness of the portfolio. This process has been in effect for the
past three years and has allowed the Company to manage on a monthly basis the
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 81 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-21
overall TRC for the Low Income Portfolio. Examples of measures that need pre-
approval include natural gas furnaces, natural gas water heaters and ENERGY STAR
refrigerators.

Non-Residential Sector Overview
For the non-residential sectors (commercial, industrial and multi-family applications),
energy efficiency programs are offered on a site-specific or custom basis. We can offer
a more prescriptive approach when treatments result in similar savings and the
technical potential is high. An example is the prescriptive lighting program. The
applications are not purely prescriptive in the traditional sense, such as with residential
applications where homogenous programs are provided for all residential customers;
however, a more prescriptive approach can be applied for these similar applications.

Non-residential prescriptive programs offered by Avista include, but are not limited to,
space and water heating conversions, space and water heating equipment upgrades,
appliance upgrades, cooking equipment upgrades, personal computer network controls,
commercial clothes washers, lighting, motors, refrigerated warehouses, traffic signals,
and vending controls. Also included are residential program offerings such as multi-
family direct install through UCONS (which ended in December 2009, however, a
handful of projects were reported in 2010) and multi-family market transformation since
these projects are implemented site-specifically unlike other residential programs.

During 2010, the Company processed approximately 2,400 energy efficiency projects
resulting in the payment of $7.9 million in rebates paid directly to customers to offset the
cost of their energy efficiency projects. These projects contributed 43,430 MWh of
electricity and 742,559 therms of natural gas savings.

In January 2011, Avista launched two new prescriptive programs – commercial windows
and insulation and commercial natural gas HVAC. Another prescriptive program, for
standby generator block heaters, was evaluated and launched April 1, 2011. A survey of
various municipalities in 2010 to determine saturation levels of light-emitting diode traffic
signals and as a result, this program will end. Participants submitting paperwork by
December 15, 2011, will still be eligible to receive an incentive payment. The
Leadership in Energy and Environmental Design building rating program ended
December 31, 2010. Projects completed by December 31, 2011 with paperwork
submitted by March 31, 2012, will be eligible for an incentive.

Energy Smart Grocer is a regional, turnkey program administrated through PECI. This
program has been operating for several years. This program will approach saturation
levels during the early part of this 20-year planning horizon. We implement the
remaining programs in the site-specific sector through the Company’s energy efficiency
infrastructure.

The programs highlighted by the recently completed CPA study will be reviewed for the
development of target marketing and the creation of new energy efficiency programs. All
electric-efficiency measures with a simple payback exceeding one year and less than
eight years for lighting measures or thirteen years for other measures automatically
qualify for the non-residential portfolio. The IRP provides account executives, program
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 82 of 1069
Chapter 3–Energy Efficiency
Avista Corp 2011 Electric IRP 3-22
managers/coordinators and energy efficiency engineers with valuable information
regarding potentially cost-effective target markets. However, the unique and specific
characteristics of a customer’s facility override any high-level program prioritization for
non-residential customers.

Non-Residential Energy Efficiency Example
The scope of this energy efficiency project included a solution to replace an existing
compressor used to circulate water in Medical Lake. The existing equipment was a 50
horsepower screw compressor with a 1,750-RPM three-phase motor that operated 24
hours per day, seven days per week from May 1st through October 31st. The proposed
replacement for the existing equipment was five Solar Bee solar-powered DC agitators
used to circulate the lake. The compressor is projected to be removed after four of the
five solar units have been installed. The estimated annual energy savings associated
with this energy efficiency project is approximately 128,000 kWh, which is equivalent to
the 50 horsepower compressor running at an estimated 80 percent of full load for six
months. Non-quantified non-energy benefits (NEBs) associated with this project include
improved water quality and reduced (or possibly eliminated) chemical treatment. The
energy efficiency incremental measure cost for the customer is approximately $57,000
and estimated savings of $8,916 in annual energy costs at current rates. At completion,
the customer would receive an estimated $25,000 incentive, which would reduce their
6.4-year simple payback to 3.6 years.

Demand Response
Prior to the addition of energy efficiency resources, additional capacity resources were
estimated to be needed in 2013. Once energy efficiency resources were layered onto
existing supply-side resources in the PRiSM model, this capacity need was moved out
to 2019 for summer capacity and 2021 for winter capacity. This capacity need comes
from expiring contracts as well as native load growth.

As part of the CPA study, Global evaluated typical demand response program options,
including direct load control, curtailable and demand bidding/buy-back programs. Using
the Company’s capacity costs, prior to the inclusion of energy efficiency, Global found
that these demand response programs were cost-effective. However, because energy
efficiency is assumed to be acquired first consistent with I-937, the savings resulting
from energy efficiency removed the need for additional capacity, making demand
response not cost effective at this time.

Since Avista does not have an immediate capacity shortage, the Company will not
continue to model demand response programs in the near term, but may continue to
evaluate some of these demand response programs in the future.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 83 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-1
4. Policy Considerations
Many environmental policy issues could significantly affect the operation of the
Company‟s current generation resources and could affect the types of resources it
might pursue in the future. Over time, the direction of these expected future policy
considerations has changed, sometimes dramatically. The Company expects the nature
and impact of future environmental policies to continue changing. The 2009 IRP
included an Environmental Policy chapter that mainly focused on greenhouse gas policy
and renewable portfolio standards. The current political and regulatory environments
have changed significantly since the publication of the last IRP. The immediate
prospects for implementation of cap and trade programs to reduce greenhouse gas
emissions has diminished, leading to a new focus on regulatory measures pursued by
the Environmental Protection Agency (EPA) and on political and legal initiatives
commenced by environmental groups to apply pressure on thermal generation –
specifically coal-fired generation. The areas of regulation have particular implications,
as they involve regulation of emissions affecting regional haze, coal ash disposal,
mercury emissions, water quality, as well as greenhouse gas emissions. This chapter
provides an overview and discussion about some of the more pertinent environmental
policy issues facing the Company.

Environmental Concerns
Environmental concerns, such as greenhouse gas emissions, present a unique
resource planning challenge due to the continuously evolving nature of environmental
regulation and its ever-changing projections of the scope and costs of various
programs. If environmental concerns were the only issue faced by electric utilities,
resource planning would be reduced to a determination of the required amounts and
types of renewable generating technology and energy efficiency to acquire. However,
the need to maintain system reliability, acquire resources at least cost, mitigate price
volatility, meet renewable generation requirements and manage financial risks
compound utility planning complexity. Each generating resource has distinctive
operating characteristics, cost structures, and environmental challenges. Traditional
generation technologies, like coal-fired and natural gas-fired plants, are well understood
and provide capacity along with energy.

Chapter Highlights
Avista supports national greenhouse gas legislation that is workable, cost
effective, and fair.
Avista supports national greenhouse gas legislation that protects the
economy, supports technological innovation, and addresses emissions from
developing nations.
The Company is a member of the Clean Energy Group.
Avista‟s Climate Change Council monitors greenhouse gas legislation and
environmental regulation issues.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 84 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-2
Coal-fired units have high capital costs, long permitting and construction lead times, and
relatively low and stable fuel costs. They are difficult, if not impossible in some
jurisdictions, to site due to state laws and local opposition, and environmental issues
ranging from the impacts of coal mining to power plant emissions. Further, remote mine
locations increase cost by either the transportation of coal to the plant or the
transportation of the generated electricity to load. By comparison, natural gas-fired
plants have relatively low capital costs as compared to coal, are typically located close
to load centers, can be constructed in relatively short time frames, emit less than half
the greenhouse gases emitted by coal, and are the only utility-scale baseload resource
that can be developed in certain locations. However, fuel price volatility affects natural
gas-fired plants. They are also challenged by having diminished performance during
periods of hot weather, by the difficulty of securing water rights for their efficient
operation, and by the fact that the plants still emit significant greenhouse gases relative
to renewable resources.

Renewable energy technologies such as wind, biomass, and solar generation have
different challenges. Renewable resources are attractive because they have low or no
fuel costs and few, if any, emissions. However, renewable generation can have limited
or no on-peak capacity contribution to the operation of the Company‟s system, and
intermittent renewable resources can present integration challenges and require
additional non-renewable generation capacity investment. These resources also
generally have high upfront capital costs, and have their own environmental challenges
to overcome, particularly with respect to siting. Similar to coal plants, renewable
resource projects are located near their fuel sources. The need to site renewable
resources in remote locations often requires significant investments in transmission
interconnection and capacity expansion, as well as raising possible wildlife and
aesthetic issues, such as those that utility-scale solar projects in the southwestern U.S.
have encountered. Unlike coal or natural gas-fired plants, the fuel for non-biomass
renewable resources cannot be transported from one location to another to better utilize
existing transmission facilities or to minimize opposition to project development.
Biomass facilities themselves can be particularly challenged because of their
dependence on the health of the forest products industry and access to biomass
materials located in publicly owned forests.

Furthermore, the long-term economic viability of renewable resources is uncertain for at
least two important reasons. First, federal investment and production tax credits and
direct grants in lieu of tax incentives are scheduled to expire in 2012 or 2013, depending
on the technology. The continuation of credits and grants cannot be assumed in light of
the impact such subsidies have on the finances of the federal government and the
relative maturity of wind technology development. Second, the costs of renewable
technologies are affected by many relatively unpredictable factors, such as renewable
portfolio standard mandates, material prices and currency exchange rates, the effects of
which cannot be accurately predicted. Capital costs for wind and solar have decreased
since the 2009 IRP, but there are no guarantees that prices will continue to stay at
current levels.

Though there appears to be very little, if any, chance that a national greenhouse gas
cap and trade program being implemented soon, there still is a great deal of uncertainty
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 85 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-3
around its regulation. There is strong regional and national support to address climate
change. Since the 2009 IRP publication, many changes in the approach and potential
for actual greenhouse gas emissions regulation have occurred, including:

 Consideration is presently being given toward a clean energy standard at the
federal level, instead of a more direct form of greenhouse gas emission
regulation, such as a cap and trade program;
 The current split of control between the U.S. House of Representatives and the
Senate effectively postpones national cap and trade legislation for greenhouse
gas emissions until after the 2012 election, at the earliest;
 The EPA has commenced actions to regulate greenhouse gas emissions under
the Federal Clean Air Act, although some of these efforts have been delayed and
the agency „s justification for advancing some of its initiatives are being judicially
challenged ; and
 Development of economy-wide cap and trade regulation at the regional level now
focus primarily on California and British Columbia rather than on the broader
Western Climate Initiative.
Avista’s Climate Change Policy Efforts
Avista‟s Climate Policy Council is a clearinghouse for all matters related to climate
change. In regards to climate change, the Council:
 Facilitates internal and external communications on climate policy issues;
 Analyzes policy impacts, anticipates opportunities and evaluates strategy for
Avista; and
 Develops recommendations on climate related policy positions and action plans.
The core team of the Climate Policy Council includes a designated chairperson, key
officers, and representatives from Environmental Affairs, Government Relations,
Corporate Communications, Engineering, Energy Solutions, Legal Affairs, and
Resource Planning. Other areas of the Company participate as needed. The monthly
meetings for this group include work divided into immediate and long-term concerns.
The immediate concerns include such topics as reviewing and analyzing proposed or
pending state and federal legislation, reviewing corporate climate change policy, and
responding to internal and external data requests about climate change issues. Longer-
term issues involve topics such as emissions tracking and certification, providing
recommendations for greenhouse gas goals and activities, evaluating the merits of
different greenhouse gas policies, actively participating in the development of
legislation, and benchmarking climate change policies and activities against other
organizations.

Avista maintains its membership in the Clean Energy Group, which includes Calpine,
Entergy, Exelon, Florida Power and Light, Pacific Gas & Electric and Public Service
Energy Group. This group collectively evaluates and supports different greenhouse gas
policies. Avista also participates in national and regional discussions about hydroelectric
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 86 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-4
and biomass issues through membership in national hydroelectric and biomass
associations.

Avista’s Position on Climate Change Legislation
Avista anticipates the passage of federal greenhouse gas (climate change) legislation in
some form within the next five years. A comprehensive national climate change policy
could assume the form of a cap and trade program, carbon tax, national portfolio
standard, emissions performance standard, or some combination of the four. The
Expected Case in this IRP uses 2015 as the starting date for greenhouse gas emissions
costs. The 2015 start date was chosen early in the development of the modeling
exercises for this plan, and the actual effective date will most likely be after 2015 by the
time legislation could be enacted and rules promulgated. The Company chose to
develop a weighted cost using four different cases for greenhouse gas emissions
because of the uncertainty about the timing and scope of this legislation. The four cases
include regional cap and trade, national cap and trade, national carbon tax and no
greenhouse gas policies. Details about the different greenhouse gas policies modeled
for this IRP are located at the end of this chapter.

The current lack of a definitive greenhouse policy direction makes an uncertain planning
environment as Avista plans to meet future customer loads. Avista does not have a
preferred form of greenhouse gas policy at this time, but supports federal legislation that
is:

 Workable and cost effective;
 Fair;
 Protective of the economy and consumers;
 Supportive of technological innovation; and
 Includes emissions from developing nations.

Workable and cost effective legislation should be crafted to produce actual greenhouse
gas reductions through a single system, as opposed to competing, if not conflicting,
state, regional and federal systems. The legislation also needs equitable distribution
across all sectors of the economy based on relative contribution to greenhouse gas
emissions. Protecting the economy and consumers is of utmost importance. The
legislation cannot be so onerous that it stalls the economy or fails to have any sort of
adjustment mechanism in case the market solution fails causing allowance or offset
prices to escalate at unmanageable rates. Supporting technological innovations should
be a key component of any greenhouse gas legislation because innovation can help
contain costs, as well as provide a potential economic boost to the manufacturing
sector. Climate change legislation must involve developing nations with increasing
greenhouse gas emissions and legislation should include strategies for working with
other nations directly or through international bodies to control worldwide emissions.
Greenhouse Gas Emissions Concerns for Resource Planning
Resource planning in the context of greenhouse gas emissions regulation raises
concerns about the balance between the Company‟s obligations for environmental
stewardship and the cost implications for our customers. Consideration must be given to
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Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-5
the cost effectiveness of resource decisions as well as the need to mitigate the financial
impact of potential future emissions risks.
Complying with greenhouse gas regulations, particularly in the form of a cap and trade
mechanism, involves two actions: ensuring the Company maintains sufficient
allowances and/or offsets to correspond with its emissions during a compliance period,
and undertaking measures to reduce the Company‟s future emissions. Enabling
emission reductions on a utility-wide basis can entail any of the following:
 Increasing efficiency of existing fossil-fueled generation resources;
 Reducing emissions from existing fossil-fueled generation through fuel
displacement including co-firing with biomass or biofuels;
 Permanently decreasing the output from existing fossil-fueled resources and
substituting it with lower emitting resources;
 Decommissioning or divesting of fossil-fueled generation and substituting lower
emitting resources;
 Reducing exposure to market purchases of fossil-fueled generation, particularly
during periods of diminished hydropower production, by establishing larger
reserves based on lower emitting technologies; and
 Increasing investments in energy efficiency measures.

With the exception of increasing Avista‟s commitment to energy efficiency, the costs
and risks of the actions listed above cannot be adequately, let alone fully, be evaluated
until the nature of greenhouse gas emission regulations is known; that is, after a
regulatory regime has been implemented and the economic effects of its interacting
components can be modeled. A specific reduction strategy as part of an IRP may be
forthcoming when greater regulatory clarity and more precise modeling parameters
exist. In the meantime, the model for this IRP uses the average cost of the weighted
policies discussed at the end of this chapter. The 2011 IRP focuses on the costs and
mitigation of carbon dioxide since it is the most prevalent and primary greenhouse gas
emitted from fossil-fueled generation sources.

National Greenhouse Gas Emissions Legislation
Several themes have emerged from various climate change legislative proposals
considered since publication of the 2009 IRP. These include:

 Climate change is now viewed as largely an anthropogenic or human-developed
phenomenon.
 A preference in certain economic sectors towards application of greenhouse gas
regulations on an economy-wide basis, rather than on piecemeal regulatory
approaches that target specific sectors or technologies.
 Technology will be a key component to reducing overall greenhouse gas
emissions, particularly in the electric sector. Significant investment in carbon
capture and sequestration technology will be needed because coal will continue
to be an important part of the U.S. generation fleet into the near future.
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R. Lafferty, Avista
Schedule 1, Page 88 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-6
 Developing countries must be involved in reducing global emissions as
greenhouse gas emissions generally increase along with economic growth.
 The longer federal legislation takes to enact, the higher the probability of
inconsistent state and regional regulatory schemes. A patchwork of regulation
may obstruct the operation of businesses serving multiple jurisdictions by
causing market disruptions and increasing the uncertainty of how federal and
disparate state and regional regulatory systems might interact.

These themes all point toward a need to develop national greenhouse gas legislation in
a timely manner to ensure the best environmental and economic outcomes. The
Waxman-Markey bill (H.R. 2454), passed in the U.S. House of Representatives in June
2009, importantly acknowledged these multi-jurisdiction problems by proposing to
effectively supersede state and regional cap and trade regulation over emissions
covered under federal law between 2012 and 2017.

Federal Policy Considerations
The direction of federal policies toward greenhouse gas emissions mitigation has
changed since the 2009 IRP. In that document, the Company projected a national cap
and trade program would be enacted and effective in 2012. This IRP assumes some
version of a national greenhouse gas policy will be in place starting in 2015, but the type
of policy is uncertain. If the models for this IRP did not have to be locked down early in
the process, we would have pushed the timeframe out even further because of the
uncertainty of any federal-level climate change policy with the current split between the
House and the Senate, the soft state of the U.S. economy, and the upcoming 2012
elections. Given this low level of certainty, the Company developed four hypothetical
greenhouse gas policy models. Details are provided later in this chapter.

Avista‟s main concern with any potential federal cap and trade legislation involves
compliance costs, an issue centering primarily, though not exclusively, on emission
allowances. Avista favors the Edison Electric Institute approach where half of the
allowances allocated to electric utilities are load-based and the other half are emissions-
based. This more equitable compromise would provide prevent a windfall for non-utility
generators with large historical greenhouse gas emissions at the expense of utilities,
like Avista, that already rely on non-emitting renewable energy. Administrative or direct
allocation, at least in the beginning of the program, is also favored because it will
mitigate compliance cost impacts on customers while the allowance markets and
emissions reductions technologies are developed.

There currently is no pending federal climate change legislation before Congress. In lieu
of comprehensive climate change legislation, early in 2011, President Obama endorsed
the idea of a Clean Energy Standard that would result in the nation deriving 80 percent
of its electricity by 2035 from renewable resources and lower greenhouse gas emitting
generation, such as natural gas-fired generation, “clean coal” generation with captured
and sequestered emissions, and nuclear power. Formal Clean Energy Standard
legislation has yet to be introduced in Congress. At the time this IRP was prepared,
members of the U.S. Senate had collected comments on a White Paper on a Clean
Energy Standard and Senator Jeff Bingaman (D-New Mexico) was drafting legislation in
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 89 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-7
coordination with the President‟s staff, which he said in early June 2011, likely would not
pass the Senate Energy and Natural Resources Committee. Even greater doubts exist
that such a proposal could pass the U.S. House of Representatives. Given that Clean
Energy Standard legislation in not likely to be enacted during 2011and 2012, Avista did
not model the Clean Energy Standard for this IRP.

The 111th Congress considered renewable energy standard legislation (RES), such as
the Waxman-Markey bill; (H.R. 2454) and S. 1462 by Senator Bingaman. Such
proposals contemplated a renewable energy standard of between 10 and 25 percent by
specific dates. These measures generally included a “hydro netting” provision; this
provision excludes loads served by hydropower energy from the RES requirement. For
example, if a utility has 1,000 aMW of load, a 10 percent RES goal, and 200 aMW of
hydroelectric generation; then the utility‟s RES goal would only be 80 aMW instead of
100 aMW because of the hydro-netting. Federal legislation has conceptually – and
significantly – differed from the Energy Independence Act (I-937) in Washington State,
in particular with respect to hydro-netting. The absence of hydro-netting in I-937 makes
the Washington law more restrictive than proposed federal renewable energy
requirements. Therefore, absent Idaho RPS legislation, Avista would need to meet only
the federal renewable energy requirements for its Idaho service territory. National
legislation so far also includes existing biomass generation resources, including Kettle
Falls, against the renewable energy standard, as well as power from upgrades to
hydropower facilities that were effectuated before 1999 (the date established in I-937 to
determine resource eligibility). Treatment of renewable resources in federal legislation
would not have allowed the Company to use renewable energy credits (RECs) from
resources that were only eligible under federal law, but not I-937, to comply with
Washington‟s renewable energy targets. However, Avista would be able to make REC
sales from federally eligible facilities into a national market and into states governed
solely by federal requirements (i.e., Idaho) and those states whose renewable energy
eligibility requirements are similar to federal ones. More details about I-937 are included
in the Washington policy consideration section later in this chapter.

The federal Production Tax Credit (PTC), Investment Tax Credit (ITC), and Treasury
grant programs are key federal policy considerations for incenting the development of
renewable generation. The current PTC and ITC programs are available through the
end of 2012 for wind and through the end of 2013 for other renewable resources. We
did not model an extension of these tax incentives because of the uncertainty of their
continuation due to the current federal budget deficit situation. If extended, the PTC or
ITC may accelerate the development of some regional renewable energy projects to
meet the extended deadline.

State and Regional Level Policy Considerations
The failure of the federal government to enact greenhouse gas policies during the
current decade encouraged several states, such as California and New Mexico, to
develop their own climate change laws and regulations. Climate change legislation can
take many forms, including economy-wide regulation in the form of a cap and trade
system. However, comprehensive climate change policy can also have multiple
individual components, such as renewable portfolio standards, energy efficiency
standards, and emission performance standards; all of these standards have been
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 90 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-8
enacted in Washington, but not necessarily in other jurisdictions where Avista operates.
Individual state actions produce a patchwork of competing rules and regulations for
utilities to follow, and may be particularly problematic for multi-jurisdictional utilities such
as Avista. There are currently 29 states, including the District of Columbia, with active
renewable portfolio standards.

One of the more notable state-level greenhouse gas initiatives outside of the Pacific
Northwest include the Regional Greenhouse Gas Initiative (RGGI) agreement between
ten northeastern and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland,
Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont)
to implement a cap and trade program for carbon dioxide emissions from power plants.
The District of Columbia, Pennsylvania, and some Canadian provinces are also
participating as RGGI observers. RGGI‟s cap and trade regulations have been effective
since January 2009. New Jersey‟s Governor Christie announced in May 2011 that he
was withdrawing his state from RGGI at the end of 2011. While the Governor still
endorsed the need to reduce greenhouse gas emissions, he argues that RGGI is not
the right mechanism for achieving reductions. Some claim that Governor Christie‟s
action may severely undermine the future prospects for RGGI.

The Western Regional Climate Action Initiative, otherwise known as the Western
Climate Initiative (WCI), began with a February 26, 2007, agreement to reduce
greenhouse gas emissions through a regional reduction goal and market-based trading
system. This agreement included the following signatory jurisdictions: Arizona, British
Columbia, California, Manitoba, Montana, New Mexico, Oregon, Utah, Quebec and
Washington. In July 2010, the WCI released its Final Design for a regional cap and
trade regulatory system to cover 90 percent of the societal greenhouse gas emissions
within the region by 2015. So far, the only state to enact legislation authorizing the
regulation of greenhouse gas emissions under a cap and trade system is California
(New Mexico adopted administrative regulations to regulate greenhouse gas emissions
in conjunction with other states, but it did so absent legislative authorization).

At the municipal level, there are several cities participating in the U.S. Mayors Climate
Protection Agreement to reduce GHG emissions to seven percent below 1990 levels by
2012.

A federal cap and trade program, such as that envisioned by the Waxman-Markey
legislation, will not operate in isolation. Members of the Western Climate Initiative, such
as Washington, Oregon, and Montana, can – as some of them have already – pursue
complementary policies to regulate emission sources covered under cap and trade
regulation, as well as those that will not be regulated under a cap and trade program.

The adoption of greenhouse gas goals and any associated regulations by Washington
could directly affect the Company‟s generation assets in the state, which are largely
comprised of the Kettle Falls Generating Station and the Northeast Combustion turbines
and Boulder Park peaking facilities. Oregon‟s greenhouse gas goals and potential future
regulations could apply to the Coyote Springs 2 project.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 91 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-9
Idaho Policy Considerations
Idaho is not a member of the Western Climate Initiative and currently does not regulate
greenhouse gases or have a renewable portfolio standard (RPS). However, the Idaho
Department of Environmental Quality will be administering greenhouse gas standards
under its Clean Air Act delegation from the EPA.

Montana Policy Considerations
Montana has a non-statutory goal to reduce greenhouse gas emissions to 1990 levels
by 2020. In 2007, the Legislature passed House Bill 25. This law requires that new coal-
fired facilities built in the state to sequester 50 percent of their emissions. Montana‟s
renewable portfolio standard law, enacted through Senate Bill 415 in 2005, requires
utilities to meet 10 percent of their load with qualified renewables from 2010 through
2014, and 15 percent beginning in 2015. While involved in the Western Climate
Initiative, Montana has not considered any legislation to authorize its participation in and
implementation of WCI‟s regional cap and trade system. The Montana Department of
Environmental Quality does not handle regional haze issues affecting coal-fired
generation located in the state, as the agency does not have delegation under the
Clean Air Act to regulate regional haze. The federal EPA is responsible for the
application of regional haze criteria to the Colstrip coal-fired plants.

Montana had already implemented a mercury emission standard under Rule 17.8.771
that applies to Colstrip. The standard requires mercury reductions to 0.9 pounds per
trillion Btu beginning January 1, 2010. Avista‟s generation at Colstrip already has
emissions controls that meet Montana‟s mercury emissions goals.

Oregon Policy Considerations
The State of Oregon has a history of considering greenhouse gas emissions and
renewable portfolio standards legislation. The Legislature enacted House Bill 3543 in
2007, calling for reductions of greenhouse gas emissions to 10 percent below 1990
levels by 2020, and 75 percent below 1990 levels by 2050. These reduction goals are in
addition to 1997 regulation requiring fossil-fueled generation developers to offset carbon
dioxide (CO2) emissions exceeding 83 percent of the emissions of a state-of-the-art
gas-fired combined cycle combustion turbine (CCCT) by paying into the Climate Trust of
Oregon. Senate Bill 838 created a renewable portfolio standard that requires large
electric utilities to generate 25 percent of annual electricity sales with renewable
resources by 2025. Intermediate term goals include five percent by 2011, 15 percent by
2015, and 20 percent by 2020. Oregon is an active member in the Western Climate
Initiative, but it has not passed the legislation necessary to implement the WCI‟s cap
and trade proposal. The Boardman Coal Plant, which is the only active coal-fired
generation facility in Oregon, plans to cease using coal by 2020. Portland General
Electric‟s decision to make near-term emissions control investments and to discontinue
the use of coal serves as an example of how regulatory, environmental, political and
economic pressure can culminate in an agreement that results in the early closure of a
low-cost coal-fired power plant.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 92 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-10
Washington State Policy Considerations
Circumstances similar to those that led to the close of the Boardman coal-fired facility in
Oregon encouraged the owners of the Centralia Coal Plant (TransAlta) to agree to shut
down one unit at the facility by December 31, 2020 and the other unit by December 31,
2025. The confluence of regulatory, environmental, political and economic pressure
brought about the scheduled closure of the Centralia Plant. The State of Washington
enacted several measures concerning fossil-fueled generation emissions and
generation resource diversification. A law, enacted in 2004, requires new fossil-fueled
thermal electric generating facilities of more than 25 MW of generation capacity to
mitigate CO2 emissions through third party mitigation, purchased carbon credits, or
cogeneration. Washington‟s Energy Independence Act (I-937), was passed by the
voters in the November 2006 General Election, established a requirement for utilities
with more than 25,000 retail customers to use qualified renewable energy or renewable
energy credits to serve three percent of retail load by 2012, nine percent by 2016 and
15 percent by 2020. Failure to meet these RPS requirements results in a $50 per MWh
fine. The initiative also requires utilities to acquire all cost effective conservation and
energy efficiency measures. Additional details about the energy efficiency portion of I-
937 are located in the Energy Efficiency chapter.

Avista expects to meet or exceed its renewable requirements between 2012 and 2015
through a combination of qualified hydroelectric upgrades and renewable energy credit
(REC) purchases. The 2011 IRP Expected Case ensures that the Company meets all I-
937 RPS goals.

Governor Christine Gregoire signed Executive Order 07-02 in February 2007
establishing the following GHG emissions goals:

 1990 levels by 2020;
 25 percent below 1990 levels by 2035;
 50 percent below 1990 levels by 2050 or 70 percent below Washington‟s
expected emissions in 2050;
 Increase clean energy jobs to 25,000 by 2020; and
 Reduce statewide fuel imports by 20 percent.

The goals of this Executive Order became law when the Legislature enacted Senate Bill
6001 in 2007. This law prohibits electric utilities from entering into long-term financial
commitments beyond five years duration for fossil-fueled generation with greenhouse
gas emissions exceeding 1,100 pounds per MWh. Beginning in 2013, the emissions
performance standard can be lowered every five years to reflect the emissions profile of
the latest commercially available CCCT. The emissions performance standard
effectively prevents utilities from developing new coal-fired generation and expanding
the generation capacity of existing coal-fired generation, unless they can sequester
emissions from the facility. The Legislature amended Senate Bill 6001 in 2009 to
prohibit contractual long-term financial commitments for generation that contain more
than 12 percent of the total power from unspecified sources. The Legislature further
amended Senate Bill 6001 in 2011 to allow long-term contracts for output from the
Centralia Coal Plant in conjunction with that plant making certain emission investments
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R. Lafferty, Avista
Schedule 1, Page 93 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-11
and ceasing to use coal in 2020 for one unit and 2025 for the other unit. This law
change occurred after completion of the modeling for this IRP.

Taking the next step to achieve the State‟s greenhouse gas reduction goals, the
governor introduced legislation (Senate Bill 5735 and House Bill 1819) during the 2009
Legislative Session to authorize the Department of Ecology to adopt rules, consistent
from recommendations from the Western Climate Initiative, enabling the state to
administer and enforce a regional cap and trade program. When that legislation failed,
Governor Gregoire signed Executive Order 09-05 directing the Department of Ecology
to develop emission reduction “strategies and actions”, including complementary
policies, to meet Washington‟s 2020 emission reduction target by October 1, 2010. This
directive requires the agency to “provide to each facility that the Department of Ecology
believes is responsible for the emission of 25,000 metric tons or more of carbon dioxide
equivalent each year in Washington with an estimate of each facility‟s baseline
emissions and to designate each facility‟s proportionate share of greenhouse gas
emission reduction necessary to achieve the state‟s 2020 emission reduction” goal. The
department is also asked, by December 1, 2009, to develop emission benchmarks, by
industry sector, for facilities the Department of Ecology believes will be covered by a
federal or regional cap and trade program. The state may advocate the use of these
emission benchmarks in any federal or regional cap and trade program as an
appropriate basis for the distribution of emission allowances. The department must
submit recommendations regarding its industry benchmarks and their appropriate use to
the Governor by July 1, 2011.

Greenhouse Emissions Measurement and Modeling
Greenhouse gas tracking is an important part of the IRP modeling process because
emissions policy poses a significant risk to Avista. Reducing greenhouse gas emissions
from power plants will fundamentally alter the resource mix as society moves towards a
carbon constrained future. However, there are currently no federal laws limiting
greenhouse gas emissions, estimated costs still need to be projected for planning
purposes because expectations for greenhouse gas regulation can significantly alter
resource decisions.

Figure 4.1 shows the carbon price forecast for this IRP. The 2011 IRP assumes
greenhouse gas emissions policies will not take effect until 2015. To simulate the
expected impacts of greenhouse gas regulation, the Company developed four policy
models and estimated their assumed financial impact on the energy marketplace. Each
policy represents a potential path governments could take over the next several years.
We assigned weighting factors to each policy and the weighted average price of the
policies is included in the Expected Case. The four greenhouse gas policies used in this
IRP are defined in Table 4.1.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 94 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-12
Figure 4.1: Annual Greenhouse Gas

Table 4.1: Modeled Greenhouse Gas Policies

Strategy Weighting
(%) Details
Regional
Greenhouse Gas
Policy
30 – Reductions in California, Oregon, Washington, and New
Mexico between 2014 and 2019.
– Shifts to National Climate Policy in 2020.
National Climate
Policy
30 – Federal legislation only applies beginning in 2015
– About 15 percent below 2005 levels by 2020 and about
35 percent below 2005 levels by 2030.
National Carbon
Tax
30 – Federal legislation only applies beginning in 2015.
– $33 per short ton, then 5 percent per year escalation for
the remainder of the study.
No Greenhouse
Gas Reductions
10 – No carbon reduction program.
– State-level emission performance standards apply and
no new coal-plants are added in the Western U.S.

The Regional Greenhouse Gas policy simulates the decision by several western states
to require greenhouse gas reductions under the auspices of the Western Climate
Initiative (WCI) because a national policy has not been enacted. This policy does not
include all of the WCI members because some states have enacted little, if any,
legislation to allow their states to participate in the WCI cap and trade market. This
policy begins in 2014 and is restricted to California, New Mexico, Oregon and
0
50
100
150
200
250
300
350
400
450
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
mi
l
l
i
o
n
s

o
f

s
h
o
r
t

t
o
n
s
National Cap & Trade
National Carbon Tax
Regional Carbon Policy
No Carbon Policy
Expected Case
Exhibit No. 4
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Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-13
Washington. The policy is superseded in 2020 by a National Climate Policy, described
below. The Regional Greenhouse Gas Policy results in a 10 percent reduction of
electric generation greenhouse gas emissions below 2005 levels by 2020. Projected
prices start at $5 per short ton of CO2 in 2014 and escalate by $1 per year up to $9 per
short ton in 2019. All greenhouse gas measurements and costs in this chapter are in
short tons. In 2020, when the policy switches to a national focus, the price starts at $15
and escalates to $73 per ton in 2030. This policy was weighted by 30 percent in the
model.

The National Climate Policy begins in 2015. This scenario assumes no state level cap
and trade programs. The greenhouse gas emissions reductions are about 15 percent
below 2005 levels by 2020 and about 35 percent below 2005 levels by 2030. Prices
start at $15 per ton in 2015 and escalate to $115 per ton in 2030. This policy was
weighted 30 percent in the model.

The design of the National Carbon Tax Policy loosely resembles the carbon tax in
British Columbia and shows some of the implications of moving to a tax instead of a cap
and trade program. The tax would start in 2015 at the national level and would
supersede any state-level greenhouse gas cap and trade programs. The tax starts at
$33 per ton in 2015 and increases to $69 in 2030. This policy was weighted 30 percent
in the model.

The No Greenhouse Gas Reductions Policy is an unconstrained carbon case where
there are no national or state-level greenhouse gas emissions reductions policies. This
policy was included because there is a small probability of no greenhouse gas taxes or
cap and trade program being instituted. This policy is also necessary to be able to
determine the cost of the other greenhouse policies, since there is the actual cost of a
tax or a credit, plus the additional cost of a less greenhouse gas intensive resource
portfolio. Even though this unconstrained carbon policy does not have any national or
state-level greenhouse gas policies, state-level emissions performance standards are
still applied and no new coal plants were allowed in the model. This policy received a 10
percent weighting in the model.

We also considered the addition of a regulatory model, to represent in spirit of the
direction the EPA is using through the Clean Air Act and through other EPA actions that
are fostering the early closing of coal-fired plants, such as Boardman and Centralia.
These actions include regional haze, mercury abatement, cash ash handling and
disposal, among others. The unique nature of each coal-fired facility, combined with the
different political and environmental climates in each of the western states, made this
type of policy too complex to model at this time. Future IRPs may include some of these
EPA-related regulations as they are developed.

Figure 4.2 shows the greenhouse gas emissions costs per short ton under each of the
policies and under the Expected Case.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 96 of 1069
Chapter 4–Policy Considerations
Avista Corp 2011 Electric IRP 4-14
Figure 4.2: Price of Greenhouse Gas Credits in each Carbon Policy

$0
$20
$40
$60
$80
$100
$120
$140
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
do
l
l
a
r
s

p
e
r

s
h
o
r
t

t
o
n
National Climate Policy
Delayed National Climate Policy
National GHG Tax
No GHG Reductions
Expected Case
Regional GHG Policy
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 97 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-1
5. Transmission & Distribution
Introduction
This chapter describes Avista’s transmission system, completed and planned upgrades,
transmission planning issues, and estimated costs and issues of new generation
resource integration.
Coordinating transmission system operations and planning activities among regional
transmission providers is necessary to maintain reliable and economic transmission
service for Avista customers. Transmission providers and interested stakeholders
continue to modify the region’s approach to planning, constructing, and operating the
transmission system under Federal Energy Regulatory Commission (FERC) rules, and
state and local siting agencies guidance. This chapter complies with Avista’s FERC
Standards of Conduct compliance program governing communications between Avista
merchant and transmission functions.

Avista’s Transmission System
Avista owns and operates a system of over 2,200 miles of electric transmission
facilities. This includes approximately 685 miles of 230 kilovolt (kV) line and 1,527 miles
of 115 kV line. Figure 5.1 illustrates the Company’s transmission system. The Company
owns an 11 percent interest in 495 miles of a 500 kV line between Colstrip and
Townsend, Montana. The transmission system includes switching stations and high-
voltage substations with transformers, monitoring and metering devices, and other
system operation-related equipment. The system transfers power from Avista’s
generation resources to its retail load centers. Avista also has network interconnections
with the following utilities:
Bonneville Power Administration (BPA)
Chelan County PUD
Grant County PUD
Idaho Power Company
NorthWestern Energy
PacifiCorp
Pend Oreille County PUD
Chapter Highlights
Projected costs of transmission upgrades are included in the 2011 Preferred
Resource Strategy.
The Company received matching federal grants and is investing in three grid
modernization programs projected to reduce load by 5.57 aMW by 2013.
Sixty distribution feeders passed preliminarily economic screening during the
IRP timeframe, reducing system losses by 6.1 aMW.
The Company participates in various regional transmission planning forums.
Avista will upgrade various transmission paths over the next five years.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 98 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-2
Figure 5.1: Avista Transmission Map

Network interconnections enhance reliability and serve as points of receipt for power
from generating facilities outside of a utility service area. Avista has interconnections to
deliver its Colstrip, Coyote Springs 2, Lancaster, Washington Public Power Supply
System Washington Nuclear Plant No. 3 settlement contract, and Mid-Columbia
contract power. Avista serves various wholesale loads using government-owned and
cooperative utility interconnections at transmission and distribution voltage levels.
Recent Transmission Improvements
Since the 2009 IRP, Avista made the following transmission enhancements:
Added a 115 kV capacitor bank at Grangeville;
Installed new 115 kV substation and transmission integration equipment at Idaho
Road;
Replaced a failed transformer at the Avondale 115 kV substation;
Reconstructed the 115 kV switchyard and distribution substation, and added a
capacitor bank to the Nez Perce 115 kV substation;
Reconductored the Airway Heights to North Fairchild line section of the Airway
Heights - Silver lake 115 kV line,
Installed a new capacitor bank at the Airway Heights substation; and
Reconductored selected portions of the Moscow area 115 kV system.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 99 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-3
Future Upgrades and Interconnections

Station Upgrades
As reported in the 2009 IRP, Avista planned to upgrade its Moscow, Noxon, Pine Creek
and Westside 230 kV substations. These stations have undersized transformers, do not
provide 21st century reliability, and are near the end of their useful lives. The Moscow
station upgrades, scheduled for completion in 2014, will result in a new facility with a
single 250 MVA 230/115 kV station using a double bus-double breaker configuration for
230 kV service. The 115 kV yard is in a breaker-and-a-half configuration. Over the next
five to 10 years, the three remaining stations will be upgraded. Beyond these, plans
exist for several new 115 kV capacitor banks throughout Avista’s transmission system in
the near future.

Transmission Upgrades
Avista plans to complete several 115 kV reconductor projects throughout its
transmission system over the next decade. These projects focus on replacing decades-
old small conductor with conductor capable of greater load-carrying capability and more
efficient (i.e., fewer electrical losses) service. A future IRP will discuss these savings
and timeline after further analysis is completed.

South Spokane 230 kV Reinforcement
Transmission studies continue to support a need for an additional 230 kV line to the
south and west of Spokane. Avista currently has no 230 kV source in these areas, and
instead relies on its 115 kV system for load service as well as bulk power flows through
the area. The project scope is under development, and preliminary studies indicate the
need for the following (or similar) projects:

 A new 230/115 kV station near Garden Springs. Property acquisition for the
Garden Springs station and preliminary geo-technical station design work has
commenced;
 Tap of the Benewah-Boulder 230 kV line southwest of the Liberty Lake area and
construction of a new 230 kV switching station (for later development of a
230/115 kV substation); alternatively, reconstruction of the 115 kV circuits
between Beacon and Ninth & Central, and the installation of a 230/115 kV station
at that site could be pursued;
 Connecting the Liberty Lake 230 kV station with the Garden Springs 230 kV
station; alternatively, connecting the Ninth & Central station to the Garden
Springs station;
 Construction of a new 230 kV line from Garden Springs to Westside; and
 Origination and termination of the 115 kV lines from the new Spokane 230/115
kV station(s).

The South Spokane 230 kV Reinforcement project will be scoped by the end of 2012
with planned energization by the end of 2018. The project will enter service in a staged
fashion beginning in 2014

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 100 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-4
Additional Work Required from the Avista Five and Ten-Year Plans
Following are examples of additional improvements to the Avista System in the next five
to ten years. Since load growth rates in the various areas of the system are unknown,
items presently on the list may or may not occur in this timeframe; more certainty is
gained as time passes.

West Plains 115 kV Reinforcement
Irvin 115 kV Project
Glenrose Tap – Ninth and Central 115 kV line
Beacon 230/115 kV Station Partial Rebuild
New Distribution Stations:
o Otis Orchards (2011)
o Hillyard (2013)
o Hawthorne (2013)
o North Moscow Additional Transformer (2013)
o Spokane Downtown West (2014)
o Greenacres (2014)

Canada/Northwest/California 500 kV Transmission Project (CNC) and Devils Gap
500/230 kV Interconnection
The Transmission Coordination Work Group (TCWG, see below) continues to evaluate
a new transmission line involving four major projects.

 500 kV high voltage alternating current facilities from Selkirk in southeast British
Columbia to the proposed Northeast Oregon (NEO) Station, with an intermediate
interconnection with Avista at a new Devils Gap Substation, located near
Spokane;
 500 kV high voltage AC or high voltage direct current facilities running from the
NEO Station to the Collinsville Substation in the San Francisco Bay Area;
 Interconnection near Cottonwood Substation in northern California (a direct
current segment);
 Voltage support at the interconnecting substations; and
 Remedial actions for project outages.

The Canada-Northwest-California (CNC) project would allow access to new renewable
resources in the Pacific Northwest, Canada, and, at times, the southwestern United
States. Immediate and future environmental and resource needs of Avista and other
Western interconnected utilities could be aided by this project. Further, Avista expects
the project will increase the utilization of its existing transmission facilities. Through its
participation in TCWG and other regional and sub-regional forums, Avista makes all
project information available to group members, including resource developers, load
serving entities, energy marketers, and independent transmission owners.

The CNC project continues to move forward with an altered set of ownership
assumptions. The ultimate project size has not been determined. In late 2010, the CNC
project was bifurcated into a northern section and a southern section. BC Hydro has
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 101 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-5
taken responsible for the northern segment, comprised of the 500 kV interconnection
between Selkirk and the proposed NEO station. The northern segment could be a
double circuit 500 kV AC line with 3,000 MW of transfer capability, or a single circuit 500
kV AC line with 1,500 MW of capacity. Preferred line routing for the northern segment
remains the ―eastern route‖, this would utilize the Avista Addy-Devils Gap 115 kV line
corridor. A 500 MVA bi-directional 500/230 kV phase shifted interconnection between
the CNC project and Avista’s transmission system remains the preferred option and
would be the major impact to Avista.

The scope of the southern portion of the project has been reduced from a nominal 3,000
MW of transfer capability to 2,000 MW. Much work remains to determine if the southern
portion should be an alternating current or a direct current line, and whether brownfield
development (replacement of existing transmission with higher voltage and/or higher
capacity facilities) can be accomplished while maintaining reliable system operation.
Pacific Gas and Electric (PG&E) is no longer leading the southern segment project; the
Western Area Power Administration (WAPA) has assumed its leadership.

Regional Transmission System
BPA owns and operates most of the regional transmission system in the Pacific
Northwest. The federal entity operates over 15,000 miles of transmission-level facilities
throughout the Pacific Northwest and owns the largest portion of the region’s high
voltage (230 kV or higher) transmission grid. Avista uses BPA transmission to transfer
output from its remote generation sources to Avista’s transmission system, including its
Colstrip units, Coyote Springs 2, Lancaster and its Washington Public Power Supply
System Washington Nuclear Plant No. 3 settlement contract. Avista also contracts with
BPA for Network Integration Transmission Service to transfer power to 10 delivery
points on the BPA system to serve portions of the Company’s retail load.

The Company participates in the BPA transmission and rate case processes, and in
BPA’s Business Practices Technical Forum, to ensure charges remain reasonable and
support system reliability and access. Avista also works with the BPA and other regional
utilities to coordinate major transmission facility outages.

Future development likely will require new transmission assets by federal and other
entities. BPA is developing several transmission projects in the Interstate 5 corridor, as
well as projects in southern Washington that are necessary for integration wind
generation resources located in the Columbia Gorge. Each project has the potential to
increase BPA transmission rates and thereby affect Avista’s costs.

FERC Planning Requirements and Processes
The Federal Energy Regulatory Commission (FERC) provides guidance to both regional
and local area transmission planning. This section describes several requirements and
processes of the federal regulator important to Avista’s transmission planning.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 102 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-6
Attachment K
FERC approved Attachment K to Avista’s Open Access Transmission Tariff (OATT).
The attachment satisfies nine transmission principles in FERC Order 890 ensuring open
planning processes, and formalizes coordination of local, regional, and sub-regional
transmission planning.

Avista regularly develops a biannual Local Planning Report (in coordination with Avista's
five- and ten-year Transmission Plans). Avista encourages participation of its
interconnected utilities, transmission customers, and other stakeholders in the Local
Planning Process.

The Company uses ColumbiaGrid to coordinate planning with sub-regional groups.
Regionally, Avista participates in several Western Electricity Coordinating Council
(WECC) processes and groups, including Regional Review processes, Transmission
Expansion Planning Policy Committee (TEPPC), Planning Coordination Committee
(PCC), and the newly formed Transmission Coordination Work Group (TCWG).
Participation in these efforts supports regional coordination of Avista's transmission
projects.

Western Electricity Coordinating Council
The Western Electricity Coordinating Council (WECC) coordinates and promotes
electric system reliability in the Western Interconnection. It also supports efficient and
competitive power markets, assures open and non-discriminatory transmission access
among its members, provides a forum for resolving transmission access or capacity
ownership disputes, and provides an environment for coordinating the operating and
planning activities of its members as set forth in WECC Bylaws. Avista participates in
WECC’s Planning, Operations, and Market Interface Committees, as well as various
sub groups and other processes such as the TCWG.

Northwest Power Pool
Avista is a member of the Northwest Power Pool (NWPP). Formed in 1942 when the
federal government directed utilities to coordinate operations in support of wartime
production, NWPP committees include the Operating Committee, the Pacific Northwest
Coordination Agreement (PNCA) Coordinating Group, and the Transmission Planning
Committee (TPC). The TPC exists as a forum addressing northwest electric planning
issues and concerns, including a structured interface with external stakeholders.

The NWPP serves as an electricity reliability forum, helping to coordinate present and
future industry restructuring, promoting member cooperation to achieve reliable system
operation, coordinating power system planning, and assisting the transmission planning
process. NWPP membership is voluntary and includes the major generating utilities
serving the Northwestern U.S., British Columbia and Alberta. Smaller, principally non-
generating, utilities participate in an indirect manner through their member systems,
such as the BPA.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 103 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-7
ColumbiaGrid
ColumbiaGrid formed on March 31, 2006 to develop sub-regional transmission plans,
assess transmission alternatives (including non-wires alternatives), provide a decision-
making forum, and to provide a cost-allocation methodology for new transmission
projects. This group formed in response to several FERC initiatives. Avista joined
ColumbiaGrid in early 2007. The ColumbiaGrid agreements help different organizations
and groups determine areas of transmission work, and establish agreements to carry
out the plans.

Northern Tier Transmission Group
The Northern Tier Transmission Group (NTTG) formed on August 10, 2007. NTTG
members include Deseret Power Electric Cooperative, Idaho Power, Northwestern
Energy, PacifiCorp, Portland General Electric, and Utah Associated Municipal Power
Systems. NTTG members coordinate with state governments to manage their
transmission system operations, products, business practices, and high-voltage
transmission network planning to meet and improve transmission delivery services.
Avista’s transmission network has a number of strong interconnections with three of the
six NTTG member systems. Due to the geographical and electrical positions of Avista’s
transmission network related to NTTG members, Avista is evaluating membership in
NTTG to foster collaborative relationships with our interconnected utilities.

Transmission Coordination Work Group
The Transmission Coordination Work Group (TCWG) is a joint effort of Avista, BPA,
Idaho Power, Pacific Gas and Electric, PacifiCorp, Portland General Electric, Sea
Breeze Pacific-RTS, and TransCanada to coordinate transmission project
developments expected to interconnect at or near a proposed Northeast Oregon station
near Boardman, Oregon. These projects follow WECC Regional Planning and Project
Rating Guidelines. Detailed information on projects presently under consideration is at
www.nwpp.org/tcwg.

Most of the projects developed through the TCWG transferred to their own Project
Review Groups, placed on hold, or terminated. The TCWG work effort has been
significantly reduced over the past year because of the number of terminated and on-
hold projects.

Avista Transmission Reliability and Operations
Avista plans and operates its transmission system pursuant to applicable criteria
established by the North American Electric Reliability Corporation (NERC), WECC and
NWPP. Through involvement in WECC and NWPP standing committees and sub-
committees, it participates in developing new and revised criteria, and coordinates
transmission system planning and operation with neighboring systems.

Mandatory reliability standards promulgated through FERC and NERC, subject Avista to
periodic performance audits through these regional organizations. Portions of Avista’s
transmission system are fully subscribed for retail load service. Transmission capacity
not reserved and scheduled to move power to satisfy long-term (greater than one year)
obligations is marketed on a short-term basis and used by Avista for short-term
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 104 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-8
resource optimization or by third parties seeking short-term transmission service
pursuant to FERC requirements under Orders 888, 889 and 890.

Transmission Construction Costs
The following sections provide an overview of Avista’s estimated resource integration
costs for the 2011 IRP. Integration points are divided into locations where
interconnection study work has been completed and additional points where new
resources might be interconnected. Rigorous analyses are not performed for off-system
alternatives because of the breadth of study needed for those estimates. Limited study
work has been completed, except for projects with existing generation interconnection
requests to Avista’s transmission group. Completing transmission studies without
detailed project parameters is nearly impossible (and any decisions based on such work
would be flawed) and it is therefore inappropriate to represent any figures as more than
preliminary. Approximate worst-case estimates were developed based on engineering
judgment for neighboring system impacts. Generation interconnection costs are for
locations within the Avista transmission system. Internal cost estimates are in 2011
dollars and using engineering judgment with a 50 percent margin for error. Construction
timelines are from the beginning of the permitting process to line energization.

Integration of Resources External to the Avista System
Avista’s load serving entity function must submit generation interconnection and
transmission service requests on third party transmission systems. The third party
determines transmission system integration and wheeling service costs for delivering
new resource power to Avista’s system.

At BPA’s present wheeling rate, integrating 300 MW (assuming the transmission service
were available from the off system resource to the Avista transmission system) would
cost about $4.4 million per year plus $2.5 million per year for line losses.

It is likely that the Company would invest $50 million for a 300 MW resource to increase
capacity to third-party transmission systems. These investments may not need to be
made at the time of interconnect, but will have to be upgraded in time to maintain
FERC’s market power requirements and maintain present levels of access to the energy
market. If Avista acquires a resource located on a third-party network, detailed studies
will need to be completed to understand system impacts.

Eastern Montana Resources
A regional study sponsored by the NWPP and Northwest Transmission Assessment
Committee (NTAC) found that enhancement of existing 500 kV and 230 kV facilities
would be required to integrate additional generation from Montana. Power transfer from
eastern Montana to the Northwest is affected by several constraints. A more detailed
study effort focusing on relieving constraints from central and eastern Montana
continues as a joint effort by Avista, BPA, NorthWestern Energy, PacifiCorp, and Puget
Sound Energy. Preliminary results indicate that perhaps as much as 480 MW of
additional transfer from Montana can be achieved, however engineering-level
construction cost estimates to fix constraints within the various transmission systems
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 105 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-9
have not yet been completed. It should also be noted that various facilities in the Avista
transmission system would need to be upgraded to achieve this additional transfer.

Integration of Resources on the Avista Transmission System
The Avista-LSE requested a number of generator interconnection studies in several
areas of the Avista transmission system for the 2011 IRP. The following project and cost
information was presented at the Third Technical Advisory Committee meeting on
December 2, 2010, these cost estimates are presented in Table 5.1.

Table 5.1: New Resource Integration Costs

Location Notes
Size
(MW)
Cost
($ millions)
West of Spokane, WA No transmission additions 4 0
West of Spokane, WA Requires new 115 kV line 75 15
West of Spokane, WA Requires two new 230 kV lines 254 30-55
Benewah, ID No transmission additions 300 5
Rosalia, WA No transmission additions 300 8
Rathdrum, ID Requires generation dropping 300 5
Rathdrum, ID Requires generation dropping 400 5
Othello, WA No transmission additions 17 0
Othello, WA Requires new 115 kV line and
substation1
100 13-25
Othello, WA Requires new 230 kV line and
substation
250 21-32
Sandpoint, ID Depends on BPA interconnection 50 2-5
Sandpoint, ID Cost prohibitive and not studied 100 N/A
Cabinet Gorge, ID 115 kV reconductor 60 2-10
Spokane, WA Monroe Street hydro project 20 3
Spokane, WA Monroe Street hydro project 60 3
Post Falls, ID Post Falls hydro project 14 1
Spokane, WA Upper Falls hydro project 14 1

After the completion of the IRP’s Preferred Resource Strategy and the preference for
nearly 500 MW of natural gas capacity in North Idaho. The Resource Planning group
requested further study work on specific transmission lines for a more detailed cost of
interconnection. This study is in Appendix E. The study shows that in most locations,
potential plants can be integrated at similar costs as presented in Table 5.1 as long as a
RAS system (generation dropping) is in place. The study further identifies the cost of
adding additional network facilities so a RAS system is no longer required.

1 Note that the 100 MW estimate is for 115 kV integration, and the 250 MW estimate is for 230 kV
integration, and does not include mitigation of contractual constraints on the Avista 230 kV system in the
area.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 106 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-10
Lancaster Integration
Avista has proposed and evaluated an interconnection with BPA at its Lancaster
Substation. Avista and BPA have determined that the preferred alternative is to loop the
Avista Boulder-Rathdrum 230 kV line into the BPA Lancaster 230 kV station. This
interconnection will allow Avista to eliminate or offset BPA wheeling charges for moving
the output from Lancaster to Avista’s system. Besides reduced transmission payments
to BPA by Avista, the interconnection benefit both Avista and the BPA by increasing
system reliability, decreasing losses, and delaying the need for additional transformation
at the BPA Bell Substation. The proposed plan of service also represents the best
option for service from Avista’s sole perspective. Studies also indicate that looping the
Boulder-Rathdrum 230 kV line into the Lancaster Substation may allow more transfer
capability across the combined transmission infrastructure of Avista and BPA. The
present Colstrip Upgrade Project study indicates that all of the upgrades (from AVA,
BPA, and NWE) could increase the Montana to Northwest path by as much as 800
MW—the associated projects include much more than the Lancaster loop-in work.
Construction on the Lancaster project could be completed by the end of 2012 or at
some point in 2013, depending on BPA’s construction schedule. Avista is working
closely with BPA to assure the timely construction of the BPA facilities required to
facilitate this interconnection.

Distribution Efficiencies
Avista delivers electrical energy from generators to customer meters through a network
of conductors (links) and stations (nodes). The network system is operated at different
voltages depending upon the distance the energy must travel to reduce current losses
across the system. A common rule to determine efficient energy delivery is one kV per
mile. For example, a 115 kV power system commonly transfers energy over a distance
of 115 miles while 13 kV power systems are generally limited to delivering energy 13
miles.

Avista’s categorizes its energy delivery systems between transmission and distribution
voltages. Avista’s transmission system operates at 230 kV and 115 kV nominal
voltages. Avista’s distribution system operates between 4.16 kV and 34.5 kV, but
typically at 13.2 kV in its urban service centers. In addition to voltages, the transmission
system operates distinctly from the distribution system. For example, the transmission
system is a network linking multiple sources with multiple loads, while the distribution
system configuration uses radial feeders to link a single source to multiple loads.

System Efficiencies Team
In 2008 an Avista system efficiencies team of operational, engineering and planning
staff developed a plan to evaluate potential energy savings from Transmission and
Distribution (T&D) system upgrades. The first phase summarized potential energy
savings from distribution feeder upgrades. The second phase, beginning in the summer
of 2009, combined transmission system topologies with ―right sizing‖ distribution feeders
to reduce system losses, improve system reliability, and meet future load growth.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 107 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-11
Distribution Feeders
Avista’s distribution system consists of approximately 330 feeders covering 30,000
square miles. The feeders range in length from three to 73 miles. For rural distribution,
feeder lengths vary widely to meet the electrical loads resulting from the startup and
shutdown business swings of the timber, mining and agriculture industries.

The system efficiencies team evaluated several efficiency programs across the urban
and rural distribution feeders. The programs consisted of the following system
enhancements:

 Conductor losses;
 Distribution Transformers;
 Secondary Districts; and
 Var compensation.

The energy losses, capital investments, and reductions in operations and maintenance
(O&M) costs resulting from the individual efficiency programs under consideration were
combined on a per feeder basis. This approach provided a means to rank and compare
the energy savings and net resource cost for each feeder.

Economic Analysis
Prior to the 2009 IRP an economic analysis was performed to determine the net
resource costs to upgrade each feeder for the four program areas listed above. The net
resource cost determines the avoided cost of a new energy resource levelized over the
asset’s life cycle expressed in dollars per megawatt. This economic value is calculated
by estimating the capital investment, energy savings, and avoidance of operations and
maintenance (O&M) and interim capital investments resulting from feeder upgrades.

The O&M avoided costs for upgrades were determined by modeling existing feeders in
the Availability Workbench program. This program is an expected value model
combining a weighted average time and material cost of equipment failure with the
probability of failure. The distribution feeder’s conductor, transformers, and ancillary
equipment were used to develop the failure model for each studied feeder. Customer,
material and labor costs incurred by outages, and equipment failure were the
parameters used to measure the economic risk of a failure. The results were calibrated
to the expected value model by industry indexes and Avista’s actual outage history.
Many of the projects found to be cost effective in the study are now a part of the grid
modernization project discussed below. There were 60 feeders remaining for potential
re-builds and based upon preliminary energy and O&M savings estimates. All appear
cost effective. However, these projects need further study to develop detailed cost and
energy savings estimates, further improved reliability and replacing aging infrastructure
may also contribute to the decision to proceed with rebuild projects. Based on the
preliminary cost and energy estimates shown in Figure 5.2, losses could be reduced by
6.1 aMW by the end of the IRP planning period.

Grid Modernization
Avista is investing in grid modernization technology with the aid of three federal grants
promoting the development of grid modernization applications. These grants require the
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 108 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-12
Company to invest in grid modernization training and grid improvement. The following is
a discussion of the programs, and the progress of the investment. Figure 5.2
summarizes projected energy savings for Grid Modernization (Smart Grid) and
Distribution Feeder Rebuild projects over the 20-year IRP planning period. Table 5.2
shows the projected loss savings for 2012 and 2013.
Figure 5.2: Cumulative Distribution Loss Savings from Grid Modernization and
Feeder Upgrades

Washington’s Energy Independence Act targets for energy efficiency capture first year
energy savings. Avista will capture the first year energy savings entirely in the year
when the assets are placed in service. The Evaluation, Measurement and Verification
process will focus on the 12-month period extending forward from the date assets are
place in service.
Table 5.2: Distribution Loss Energy Savings (MWh)

Location 2012 2013
Smart Grid 34,839 6,477
Distribution Feeders 1,626 4,351
Total 36,465 10,828

Smart Grid Workforce Training Grant
Avista received a three-year, $1.3 million government grant to invest in facility and
training programs to educate workers for developing, managing, and maintaining the
future grid. Workers are trained at the Jack Stewart Training Center, working in a model
neighborhood and substation to learn about grid modernization technology. Avista is
also developing a curriculum for local universities and an online portal to provide
0
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 109 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-13
training opportunities outside of the organization. Another goal of this grant is to share
best practices on Smart Grid training.

Smart Grid Investment Grant (SGIG)
The $20 million Smart Grid Investment Grant (SGIG) covers investment to the Spokane
area grid improvement project. This project includes upgrades for 59 circuits, 14
substations, and 110,000 electric customers. Avista is contributing $42 million dollars to
this project to automate the system. 42,000 MWh or 4.8 aMW of loss savings are
expected. Conservation Voltage Reduction (CVR) makes up 83 percent of the loss
savings. This project will enable Avista to remotely control and operate the distribution
system through a series of wireless controls and fiber communication between
switches, reclosers, capacitor banks, and voltage regulators. The Distribution
Management System will remotely operate the system and will be able to automatically
detect and restore faults.

Smart Grid Demonstration Project (SGDP)
Avista is a partner in the regional Smart Grid Demonstration Project (SGDP). Avista is
using an $18.9 million government grant to employ grid modernization technology in
Pullman, Washington, as part of the Pacific Northwest Smart Grid Demonstration
Project. Avista is contributing $14.9 million to the Pullman project and other parties are
contributing an additional $4.0 million. The partners are Itron, HP, Washington State
University, and Spirae. This project encompasses 13 circuits, three substations, and
includes network automation. The project involves replacement of 14,000 electric and
6,000 natural gas meters with digital meters with wireless communication. Customers
with these new meters will be able to use a web portal to track energy usage in near
real time. This project should reduce system losses by 6,763 MWh.

Feeder Rebuild Program
Beginning in 2012, Avista will begin rebuilding distribution feeders to capture energy
savings from reducing losses, increase reliability, and decrease future O&M costs. In
2012, the Company will begin work on three feeders; the feeders include BEA12F1 and
F&C12F2 (urban feeders located in Spokane) and a rural feeder in Wilbur, Washington
(WIL12F2).

As an example, an 11-mile section of the Wilbur feeder (WIL12F2) was chosen as one
of the initial feeder upgrades because of reliability and operational deficiencies. The
Wilbur feeder has several issues. The small diameter conductor sags at unacceptable
levels during frequent icing events in the area. The high impedance of this conductor
also increases the difficulty of determining where faults occur. The average age of the
transformers being replaces is over 50 years. Finally, this feeder is also difficult to repair
quickly because of its remote location. Over the last five years, the feeder has averaged
50 outages per year with a 400-minute average outage duration.
The 2012 feeder rebuilds will be completed between June and December 2012 and we
expect to reduce losses by 1,626 MWh annually. The schedule of feeders has yet to be
determined for 2013, but will likely include five or six feeder upgrades for approximately
3,325 MWh of expected loss savings annually. These estimates range between plus or
minus 30 percent depending on construction scheduling, feeder selection, load levels,
and other factors. The ultimate scope and timing of the feeder rebuild programs will
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 110 of 1069
Chapter 5 – Transmission & Distribution

Avista Corp 2011 Electric IRP

5-14
depend on the actual results of the first several feeder rebuild projects and on the
availability of resources and operational needs of the Company.

Transmission Topologies and Distribution Feeder Sizing
Avista is planning a new modeling system that will incorporate transmissions topology,
station locations and load growth. Historically, Avista’s power grid was designed and
built to adhere to reliability and capacity guidelines resulting in the lowest upfront cost.
This approach was reasonable considering the low electricity costs of that time. As the
cost of energy increases, life cycle economic analyses are warranted to evaluate power
system losses corresponding to different power grid configurations.

The new and comprehensive analysis will review several different transmission
topologies to determine the most efficient configuration for moving bulk power through
and by Avista’s system. The transmission topologies will consider the efficiency
between star network, hub and loop, southern loop and southern source. Avista’s load
service will be incorporated in this analysis by determining ideal substation placement
and feeder sizes as well as forecasted load growth. The comprehensive analysis will
evaluate many of the items listed below.

 Develop a performance criteria to determine system measures;
 Develop a base case to measure existing system performance;
 Develop a methodology to determine a full build out load case;
 Identify reasonable transmission topologies for evaluation;
 Identify reasonable guidelines for substation placement;
 Identify reasonable guidelines for distribution feeder sizes; and
 Bound the analysis to ensure the system remains reliable, compliant, and
operationally flexible.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 111 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-1
6. Generation Resource Options

Introduction
There are many generating resource options available to meet future resource deficits.
Avista can upgrade existing resources, build new facilities, or contract with other energy
companies for future delivery. This section describes the resources considered to meet
future resource needs. The new resources described in this chapter are mostly generic.
Actual resources may differ in size, cost, and operating characteristics due to siting or
engineering requirements.

Assumptions
For the Preferred Resource Strategy (PRS) analysis, Avista only considers
commercially available resources with well-known cost, availability and generation
profiles. These resources include gas-fired combined cycle combustion turbines
(CCCT), simple cycle combustion turbines (SCCT), large-scale wind, and certain solar
technologies proven on a large-scale commercial basis. Several other resource options
described later in the chapter were not included the PRS analysis, but their costs were
estimated for comparative analysis.

Levelized costs referred to throughout this section are at the generation busbar. The
nominal discount rate used in the analyses is 6.8 percent. Nominal levelized costs result
from discounting nominal cash flows at the rate of general inflation.

Renewable resources eligible for federal tax incentives receive such incentives based
on the current federal law. Wind benefits end in 2012; solar tax benefits end in 2016,
and all other renewable benefits end in 2013. The levelized costs in this chapter
assume maximum available energy for each year instead of expected generation. For
example, wind generation assumes 31 percent availability, CCCT generation assumes
90 percent availability, and SCCT generation assumes 92 percent availability. The
following are definitions for the levelized cost components used in this chapter:

Section Highlights
Only resources with well-defined costs and operating histories are in the PRS
analysis.
Wind and solar resources represent renewable options available to the
Company; future RFPs might identify competing renewable technologies.
Renewable resource costs assume present state and federal incentive levels,
but no extensions.
For the first time, thermal generation upgrades are included as resource
options in the IRP.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 112 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-2
 Capital Recovery and Taxes: Includes depreciation, return on capital, income
taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
generation asset investment.
 Allowance for Funds Used During Construction (AFUDC): The cost of money for
construction payments before the utility can recover costs of prudently acquired
generation resources.
 Federal Tax Incentives: The estimated federal tax incentive (per MWh), whether
in the form of a production tax credit (PTC), a cash grant, or an investment tax
credit (ITC), attributable to certain generation options.
 Fuel Costs: The cost of fuels such as natural gas, coal, or wood per the efficiency
of the generator. Additional details on fuel prices are in the Market Modeling
section.
 Fuel Transport: The cost to transport fuel to the plant, including pipeline capacity
charges.
 Greenhouse Gas Emissions Adder: Cost of carbon dioxide (greenhouse gas)
emissions based on Wood Mackenzie forecast.
 Fixed Operations and Maintenance (O&M): Costs related to operating the plant
such as labor, parts, and other maintenance services (pipeline capacity costs are
included for CCCT resources) that are not based on generation levels.
 Variable O&M: Costs per MWh related to incremental generation.
 Interconnection Capital Recovery: Includes depreciation, return on capital,
income taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
transmission asset investments needed to interconnect the generator.
 Excise Taxes and Other Overheads: Includes miscellaneous charges for non-
capital expenses.

At the end of this section, various tables show Incremental capacity, heat rates,
generation capital costs, fixed O&M, variable costs, and peak credits.1 Figure 6.2 shows
the levelized costs of different resource types in comparison. All costs shown in this
section are in nominal dollars unless otherwise noted. Further information on the plant
assumptions used in this section is in the Northwest Power and Conservation Council’s
(NPCC) Sixth Power Plan.

1 Peak credit is the amount of capacity a resource contributes at the time of system peak load.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 113 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-3
Gas-Fired Combined Cycle Combustion Turbine (CCCT)
Gas-fired CCCT plants provide a reliable source of both capacity and energy for a
relatively inexpensive capital investment. The main disadvantage is generation cost
volatility due to a reliance on natural gas.

CCCTs in this IRP are of a “one-on-one” (1x1) configuration, using both water- and air-
cooling technologies. The 1x1 configuration consists of a single gas turbine, a single
heat recovery steam generator (HRSG), and a duct burner to gain more generation from
the HRSG. These plants have nameplate ratings between 250 MW and 300 MW each.
A “2x1” CCCT plant configuration is possible with two turbines and one HRSG,
generating up to 600 MW. The most likely CCCT configuration for Avista is a 270 MW
air-cooled plant located in the Idaho portion of Avista’s service territory. Potential sites
for a future combined cycle plant would likely be on the Avista transmission system to
avoid third-party wheeling rates. Another advantage of siting a CCCT resource in
Avista’s service territory is access to a low cost natural gas pipeline and fuel sources.
Within Avista’s area, siting decisions then come down to choosing the state to locate a
new plant. Most of Avista’s load is in Washington, but the state’s natural gas excise tax
and carbon dioxide mitigation requirements place a gas-fired plant at an economic
disadvantage relative to siting the same plant in an adjoining state. Siting a CCCT in
Idaho economically benefits ratepayers with a lower sales tax rate, the absence of a
natural gas excise tax, and no fees for carbon dioxide mitigation.

Cost and operational estimates for CCCTs modeled in the IRP use data from the
NPCC’s Sixth Power Plan, but adjusted to reflect air-cooled technology costs by
Avista’s engineering staff. The heat rate modeled for an air-cooled CCCT resource is
6,925 Btu/kWh in 2012. The projected CCCT heat rate falls by 0.5 percent annually to
reflect an allowance for anticipated technological improvements. The plants include
seven percent of rated capacity as duct firing at a heat rate of 9,690 Btu/kWh. If Avista
were able to site a water-cooled plant, the heat rate would likely be two percent lower
and net plant output might increase by five MW.

The IRP models forced outages at six percent per year, with 21 days of annual plant
maintenance. CCCT plants are capable of backing down to 65 percent of nameplate
capacity, and ramping from zero to full load in four hours. Carbon dioxide emissions are
117 pounds per decatherm of fuel burned. The maximum capability of each plant is
highly dependent on ambient temperature and plant elevation. For modeling, winter
capability is likely to increase by 4 percent and summer capability is likely to decrease
by 6 percent, though these estimates are highly dependent upon ambient temperatures.

The capital cost used for this IRP for an air-cooled CCCT located in Idaho on Avista’s
transmission system with AFUDC is $1,323 per kW. Fixed O&M is $16 per kW-year.
Table 6.1 shows the overnight-levelized cost for an air-cooled CCCT resource in
nominal dollars per MWh.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 114 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-4
Table 6.1: CCCT (Air Cooled) Levelized Costs

Item Nominal $/MWh
Capital recovery and taxes 20.25
AFUDC 2.69
Federal Tax Incentives 0.00
Fuel Costs 48.81
Fuel Transport 5.18
Greenhouse Gas Emissions Adder 13.65
Fixed O&M 2.67
Variable O&M 2.35
Interconnection Capital Recovery 0.31
Excise taxes and Other Overheads 3.16
Total Cost 99.07

Gas-Fired Combustion Turbines and Reciprocating Engines
Gas-fired combustion turbines (CTs) and reciprocating engines, or peaking resources,
provide low-cost capacity and are capable of providing energy as needed. Technology
advances allow the plants to start and ramp quickly, enabling them to provide regulation
services and reserves for load following and for variable resources such as wind
generation.

The IRP models four peaking resource options: Frame (GE 7EA) and hybrid aero-
derivative (GE LMS 100), Reciprocating Engines (Wartsila 20V34), and Aeroderivative
(GE LM 6000). The different peaking technologies range in their abilities to follow load,
their costs, their generating capabilities, and their energy-conversion efficiencies. Cost
and operational estimates rely on the Northwest Planning and Conservation Council’s
Sixth Power Plan. Table 6.2 compares some of the peaking resource operating and cost
characteristics. All plants assume the same 0.5 percent annual real dollar cost decrease
and forced outage and maintenance rates. The levelized cost for each of the
technologies is in Table 6.3.

Table 6.2: Simple Cycle Plant Cost and Operational Characteristics

Item Frame Hybrid
Reciprocating
Engine
Aero-
Derivative
Capital Cost with AFUDC ($/kW) 679 1,272 1,308 1,186
Fixed O&M ($/kW- yr) 12.70 9.20 15.00 15.00
Heat Rate (Btu/kWh) 11,841 8,782 8,762 9,276
Variable O&M ($/MWh) $1.13 $5.63 $11.25 $4.50
Segment Size (MW) 83 94 99 46

The lowest cost resource in Table 6.3 is the hybrid CT technology. However, this
comparison can be misleading, as a peaking resource does not operate at its theoretical
maximum operating levels. Peaking resources generally operate a small percentage of
the time. Therefore, a lower capacity cost resource may be more appropriate than a
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 115 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-5
lower per unit cost resource when considering the number of expected operating hours
in the broader IRP modeling process.

Table 6.3: Simple Cycle Plant Levelized Costs per MWh

Item Frame Hybrid
Reciprocating
Engine
Aero-
derivative
Capital Recovery and Taxes 10.33 19.37 19.38 18.06
AFUDC 0.89 1.67 1.67 1.56
Federal Tax Incentives 0.00 0.00 0.00 0.00
Fuel Costs 81.33 60.32 60.18 63.72
Fuel Transport 0.00 0.00 0.00 0.00
Greenhouse Gas Emissions Adder 22.75 16.87 16.84 17.83
Fixed O&M 2.00 1.46 2.30 2.37
Variable O&M 1.38 6.91 13.82 5.53
Interconnection Capital Recovery 0.44 0.44 0.43 0.44
Excise Taxes and Other Overheads 4.67 3.72 4.05 3.89
Total Cost 123.81 110.76 118.66 113.39

Wind
Concerns over the environmental impact of carbon-based generation technologies have
increased demand for wind generation. Governments are promoting wind generation
through a combination of tax credits, renewable portfolio standards, and climate change
legislation. The 2009 American Recovery and Reinvestment Act extended the PTC for
wind through December 31, 2012, and provided an option for wind generation owners to
select a 30 percent investment tax credit (ITC) or cash grant instead of the PTC.

The IRP includes two wind generation resources: on-system and off-system. Both
resources have the same capital costs and wind pattern, but differ in the cost of
transmission to deliver the energy to Avista’s system. On-system projects must pay only
transmission interconnection costs, whereas off-system projects must pay both
interconnection and third party wheeling costs.

Wind resources benefit from having no emissions profile or fuel costs, but they are not
dispatchable, and have high capital and labor costs relative to other resource options.
Wind capital costs in 2012, including AFUDC and transmission interconnection, are
expected to be $1,850 per kW with annual fixed O&M costs of $51 per kW-yr (including
costs due to intermittent generation). These estimates come from Avista’s experience in
the wind market at the time of the IRP. The capacity factors in the Northwest are likely
to vary depending upon the location. Northwest wind has a 31.2 percent average
capacity factor; on-system wind projects have a 29.75 percent capacity. A statistical
method, based on regional wind studies, derives a range of annual capacity factors
depending on the wind regime in each year (see stochastic modeling assumptions for
more details.

Levelized costs, using these expected capacity factors and capital and operating costs
are in Table 6.4. These wind generation cost estimates assume the use of the federal
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 116 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-6
cash grant for any project brought online by the IRP models before 2013 and assume
Avista system interconnection cost of approximately $150 per kW. Actual wind resource
cost will vary depending on a project’s capacity factor, interconnection point, and the tax
incentive eligibility. Further, this plan assumes that any wind resources selected in the
PRS include the 20 percent renewable energy credit (REC) apprenticeship adder for
Washington State eligible renewable resources. This adder applies only in the state of
Washington for compliance in meeting its Energy Independence Act (I-937), requiring
15 percent of the construction labor to be apprentice through a state-certified
apprenticeship program to qualify. The costs shown below do not reflect the
consumption of (i.e., wind integration) or lack of ancillary services generated by wind
relative to other generation technologies.

Table 6.4: Northwest Wind Project Levelized Costs per MWh

Item On-System Off-System
Off-System
Montana
Capital Recovery and Taxes 77.59 73.98 58.40
AFUDC 8.19 7.80 6.16
Federal Tax Incentives (2012 only) -23.93 -22.82 -18.01
Fuel Costs - - -
Fuel Transport - - -
Greenhouse Gas Emissions Adder - - -
Fixed O&M 27.59 26.31 22.37
Variable O&M 2.76 2.76 2.76
Interconnection Capital Recovery 7.99 18.67 26.78
Excise Taxes and Other Overheads 1.66 2.07 2.25
Total Cost (without tax incentive) 125.78 131.60 118.72
Total Cost (with tax incentive) 101.85 108.78 100.71

Solar
Solar generation technology costs have fallen substantially in the last several years
owing to help from renewable portfolio standards and government tax incentives, both
inside and outside of the United States. Solar costs in this IRP are 27 percent lower
than in the 2009 IRP. Even with these large cost reductions, solar still is uneconomic
when compared to other generation resources because of its low capacity factor and
still-high capital cost. Solar does provide predictable on-peak generation that generally
complements the loads of summer-peaking utilities.

Utility-scale photovoltaic generation can be optimally located for the best solar radiation.
Solar thermal can produce a higher capacity factor than photovoltaic projects (up to 30
percent) and can store energy for several hours. Capital costs in the IRP, including
AFUDC, for solar generation technologies are $5,802 per kW for photovoltaic and
$5,538 for solar-thermal or concentrating solar projects. A well-placed utility-scale
photovoltaic system located in the Pacific Northwest would achieve a capacity factor of
less than 20 percent. Two solar technologies were studied for this IRP (photovoltaic and
solar-thermal), but only utility-scale photovoltaic was included as an option for the PRS.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 117 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-7
Avista does not believe that solar-thermal is an economically viable option in Avista’s
service territory given our modest solar resource.

The levelized costs of solar resources, including federal incentives, are in Table 6.5.
Even with declining prices, solar will continue to struggle as a cost-competitive resource
in the Northwest until technology improves capacity factors, installation costs decline at
a more rapid pace, or government entities create further policies or tax incentives to
make this resource more attractive. One advantage solar has in the state of Washington
is if the total plant is less than five megawatts it can generate two RECs that qualify for
the Washington State Energy Independence Act for every megawatt hour of generation.

Table 6.5: Solar Nominal Levelized Cost ($/MWh)

Item Photovoltaic Concentrating
Capital Recovery and Taxes 370.14 201.85
AFUDC 29.49 22.44
Federal Tax Incentives (117.60) (64.58)
Fuel Costs - -
Fuel Transport - -
Greenhouse Gas Emissions Adder - -
Fixed O&M 39.73 30.00
Variable O&M - 1.38
Interconnection Capital Recovery 1.67 9.75
Excise Taxes and Other Overheads 1.79 1.78
Total Cost (without tax incentive) 442.82 267.20
Total Cost (with tax incentive) 325.22 202.62

Coal
The coal generation industry is at a crossroads. In many states, like Washington, new
coal-fired generation is unlikely due to emissions performance standards.2 In other parts
of the country, coal remains a viable option, but the risks associated with future carbon
legislation make investments in this technology potentially subject to significant upward
price pressures. Avista assumes it will not build any new coal-fired generation resources
due to the risk of future national carbon mitigation legislation and the effective
prohibition in Washington state law. Technologies reducing or capturing greenhouse
gas emissions in coal-fired resources might enable coal to become a viable technology
in the future, but the technology is not commercially available. Although Avista will not
pursue coal in this plan, three coal technologies are shown to illustrate their costs: super
critical pulverized, integrated gasification combined cycle (IGCC), and IGCC with
sequestration. IGCC plants gasify coal, thereby creating a more efficient use of the fuel
lowering carbon emissions and removing other toxic substances before combustion.
Sequestration technologies, if they become commercially available, might potentially
sequester 90 percent of carbon dioxide (CO2) emissions, effectively reducing CO2
2 The Washington State legislature passed Senate Bill 6001 in 2007, effectively prohibiting in-state
electric utilities from developing coal-fired facilities that do not sequester emissions or purchasing long-
term contracts from coal-fired facilities.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 118 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-8
emissions from 205 pounds per MMBtu to 20.5 pounds per MMBtu. Table 6.6 shows the
costs, heat rates, and CO2 emissions of the three coal-fired technologies based on
estimates from the NPCC’s Sixth Power plan and adjusted for Avista’s projected
inflation rates. Table 6.7 shows the nominal levelized cost per MWh based on the
capital costs and plant efficiencies shown in Table 6.6.

Table 6.6: Coal Capital Costs (2012$)

Technology
Capital Cost
($/kW includes
AFUDC)
Heat Rate
(Btu/kWh)
CO2
(lbs/MMBtu)
Super-Critical 3,583 8,910 205
IGCC 4,001 8,594 205
IGCC with Sequestration 5,334 10,652 25

Table 6.7: Coal Project Levelized Cost per MWh

Item
Super-
Critical IGCC
IGCC w/
Sequestration
Capital Recovery and Taxes 56.82 64.70 86.27
AFUDC 9.66 13.06 17.41
Federal Tax Incentives 0.00 0.00 0.00
Fuel Costs 14.28 13.77 17.07
Fuel Transport 0.00 0.00 0.00
Greenhouse Gas Emissions Adder 30.00 28.93 4.30
Fixed O&M 11.87 12.10 12.10
Variable O&M 3.80 8.70 11.74
Interconnection Capital Recovery 10.31 10.46 4.79
Excise taxes and Other Overheads 3.04 3.20 2.16
Total Cost 139.79 154.94 155.86

Other Generation Resource Options
A thorough IRP considers generation resources that are not generally available in large
quantities or those not commercially or economically ready for utility-scale development,
but may be over the 20-year IRP planning horizon. This is particularly true for some
emerging technologies that are attractive from an environmental perspective, but are
currently higher-cost than other resources. Avista analyzed the following resources for
this IRP using estimates from the NPCC’s Sixth Power Plan but did not select them for
the Preferred Resource Strategy: biomass, geothermal, co-generation, nuclear, landfill
gas, and anaerobic digesters. It is possible that these resources could compete with
those assumed in the IRP. If so, Avista’s RFP processes will identify them and their
selection will displace resources otherwise included in the IRP strategy. The expected
cost of these resource options per MWh is in Table 6.8 and Table 6.9.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 119 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-9
Woody Biomass
Avista’s Kettle Falls Generation Station is a 50 MW wood-fired plant Avista built and has
operated since 1983. The viability of another Avista biomass projects depends
substantially on the availability and cost of the fuel supply. Many announced biomass
projects fail because of problems securing long-term fuel sources. Where an RFP
identifies a potential project, Avista will consider it for a future acquisition.

Geothermal
Northwest utilities have developed an increased interest in geothermal energy over the
past several years. Geothermal energy provides renewable capacity and energy with
minimal carbon dioxide emissions (zero to 200 pounds per MWh). The federal
government has extended production tax credits to this technology through December
31, 2013. Geothermal energy struggles due to high upfront development costs and risks
stemming from drilling several holes thousand feet below the earth’s crust; each hole
can cost over $3 million. Geothermal costs are low once drilling ends, but the risk
capital required to locate and prove a viable site is significant. Costs shown in this
section do not account for dry-hole risk associated with sites that do not prove to be
viable resources after drilling has taken place.

Landfill Gas
The Northwest has successfully developed landfill gas resources. The Spokane area
had a project, but it was retired after the fuel source depreciated to an unsustainable
level. Based upon costs from the NPCC, landfill gas resources are economically
promising, but are limited in their size, quantity, and location.

Anaerobic Digesters (Manure/Wastewater Treatment)
Like landfill gas, the number of anaerobic digesters is increasing in the Northwest.
These plants typically capture methane from agricultural waste, such as manure or plant
residuals, and burn the gas in reciprocating engines to power electricity generators.
These facilities tend to be significantly smaller than utility-scale generation projects (less
than five MW). A survey of Avista’s service territory found no large-scale livestock
operations capable of implementing this technology.

Wastewater treatment facilities can host anaerobic digesters. Digesters installed when a
facility is constructed helps the economics of a project greatly, though costs range
greatly depending on the system configuration. Retrofits to existing wastewater
treatment facilities are possible, but tend to have higher costs. Many of these projects
offset energy needs of the facility, so there may be little, if any, surplus generation
capability.

Small Cogeneration
Avista has relatively few industrial customers capable of developing cost-effective
cogeneration projects. If an interested customer was inclined to develop a small
cogeneration project, it could provide benefits including reduced transmission and
distribution losses, shared fuel/capital/emissions costs, and credit toward Washington’s
I-937 targets. The PRS does not include small cogeneration; where a customer pursues
this resource, Avista will consider it along with other generation options.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 120 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-10
Nuclear
Nuclear plants are not a resource option in the IRP given the uncertainty of their
economics, the apparent lack of regional political support for the technology, U.S. policy
implications, and the negative experience Avista had with its participation in WNP-3 in
the 1980s. Like coal plants, nuclear resources could be in Avista’s future because other
utilities in the Western Interconnect may be able to incorporate nuclear power in their
resource mix and offer Avista an ownership share. Given these considerations, Avista
does not include any nuclear generation in its Preferred Resource Strategy. The viability
of nuclear power could change as national policy priorities focus attention on de-
carbonizing the nation’s energy supply. Nuclear capital costs are difficult to forecast, as
there have been no new nuclear facilities built in the United States since the 1980s.
Projected costs are from industry studies and recent nuclear plant license proposals.

Table 6.8: Other Resource Options Levelized Costs

Landfill
Gas
Manure
Digester
Waste
Water
Treatment
Capital Recovery and Taxes 31.56 67.15 63.40
AFUDC 2.45 4.66 4.88
Federal Tax Incentives -8.49 -8.49 -8.49
Fuel Costs 32.66 0.00 0.00
Fuel Transport 0.00 0.00 0.00
Greenhouse Gas Emissions Adder 0.00 0.00 0.00
Fixed O&M 4.87 8.42 7.07
Variable O&M 26.25 33.16 41.45
Interconnection Capital Recovery 4.54 4.54 0.34
Excise Taxes and Other Overheads 2.96 2.00 2.11
Total Cost 96.80 111.45 110.76

Table 6.9: Other Resource Options Levelized Costs ($/MWh)

Small
Co-Gen
Wood
Biomass Geothermal Nuclear
Capital Recovery and Taxes 53.91 57.59 65.86 97.88
AFUDC 5.36 6.02 11.39 27.26
Federal Tax Incentives 0.00 -8.49 -16.98 -16.98
Fuel Costs 30.60 53.59 0.00 10.36
Fuel Transport 3.19 0.00 0.00 0.00
Greenhouse Gas Emissions Adder 8.56 0.00 4.63 0.00
Fixed O&M 0.00 34.80 32.16 16.85
Variable O&M 11.05 5.11 6.22 1.38
Interconnection Capital Recovery 0.36 4.65 4.49 4.55
Excise Taxes and Other Overheads 2.33 4.25 2.06 1.43
Total Cost 115.36 157.52 109.83 142.72

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 121 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-11
New Resources Cost Summary
Avista has several resource alternatives to select from for this IRP. Each provides
differing benefits, costs, and risks. The role of the IRP is to identify the relevant
characteristics and choose a set of resources that are actionable, meet customer’s
energy and capacity needs, balance renewable energy requirements, and minimize
customer costs. Figure 6.1 shows the comparative cost per MWh of each of the new
resource alternatives. Tables 6.13 and 6.14 provide detailed assumptions for each type
of resource. The ultimate resource selection goes beyond simple levelized cost
analyses and considers the capacity contribution (or lack thereof for wind and solar) of
each resource, among other items discussed in the IRP.

Figure 6.1: New Resource Levelized Costs
$0 $50 $100 $150 $200 $250 $300 $350
Solar Photovoltaic
Solar Thermal
Wood Biomass
Coal (IGCC w/ Seq)
Nuclear
Coal (IGCC)
Manure Digester
Waste Water Treatment
Coal (Super-Critical)
Wind Off System
Small Co-Gen
Geothermal
Reciprocating Engine
Frame SCCT
Wind Montana
Wind On System
Landfill Gas
Aero SCCT
Hybrid SCCT
CCCT (1x1) w/ duct burner (air)
CCCT (1x1) w/ duct burner (water)
dollars per MWh
Total Cost
Greenhouse Gas Adder
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 122 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-12
Table 6.10: New Resource Levelized Costs Considered in PRS Analysis

Resource
Size
(MW)
Heat
Rate
(Btu/
kWh)
Capital
Cost
($/kW)
Fixed
O&M
($/kW-yr)
Variable
O&M
($/MWh)
Peak
Credit
(Winter/
Summer)
CCCT (water cooled) 275 6,722 1,261 16.1 2.14 104/96
CCCT (air cooled) 270 6,856 1,324 16.1 1.91 104/96
Frame CT 83 11,841 708 12.7 1.13 104/96
Hybrid CT 94 8,782 1,326 9.2 5.63 104/96
Reciprocating Engines 99 8,762 1,364 15.0 11.25 100/100
Aero CT 46 9,276 1,237 15.0 4.50 104/96
Wind (on-system) 40 n/a 1,896 51.4 2.25 0/0
Wind (off-system) 40 n/a 1,896 51.4 2.25 0/0
Solar (photovoltaic) 5 n/a 6,092 46.8 0.00 5/60

Table 6.11: New Resource Levelized Costs Not Considered in PRS Analysis

Resource
Size
(MW)
Heat
Rate
(Btu/
kWh)
Capital
Cost
($/kW)
Fixed
O&M
($/kW-yr)
Variable
O&M
($/MWh)
Peak
Credit
(Winter/
Summer)
Pulverized Coal 300 8,910 3,583 69.0 3.09 100/100
IGCC Coal 300 8,594 4,001 69.0 7.09 105/95
IGCC Coal w/ Seq. 250 10,652 5,334 69.0 9.56 100/100
Solar (thermal) 25 n/a 5,646 69.0 1.13 5/100
Wind (off-system MT) 40 n/a 1,760 51.4 2.25 0/0
Woody Biomass 25 13,500 4,170 207.0 4.16 100/100
Geothermal 15 n/a 5,017 201.3 5.06 110/90
Landfill Gas 3.2 10,600 2,285 29.9 21.38 100/100
Manure Digester 0.85 10,250 4,862 51.8 27.01 100/100
Wastewater Treatment 0.85 10,250 4,862 46.0 33.76 100/100
Small Co-Generation 5 4,456 3,922 0.0 9.00 104/96
Nuclear 500 10,400 6,522 103.5 1.13 100/100

Hydroelectric Project Upgrades
Avista continues to upgrade many of its hydroelectric facilities. The latest hydroelectric
upgrade added nine MW to the Noxon Rapids Development in April 2011. Upgraded
Noxon Rapids Unit 4 will enter service in April 2012. Figure 6.1 shows the history of
upgrades to Avista’s hydroelectric system in additional average megawatts by year and
cumulatively. Avista will have added 40.1 aMW of incremental hydroelectric energy
between 1992 and 2013.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 123 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-13
Figure 6.2: Historical and Planned Hydro Upgrades

Following upgrades at Noxon Rapids, Avista expects to pursue an upgrade at Nine Mile
and annual upgrades to the Little Falls project over a four-year period. The Little Falls
upgrades will include new turbine runners, generators, and other electrical equipment.
The upgrade at Nine Mile could be a new powerhouse or a replacing the current units.
Several other potential hydroelectric upgrades might add capacity and energy at the
Long Lake, Cabinet Gorge, Post Falls, and Monroe Street projects. These upgrades are
not included in the portfolio analysis and no estimated costs are in this IRP because
further study is required. Such studies are part of the IRP’s Action Plan. Table 6.8
shows the hydroelectric upgrade studies. Large hydro upgrades can help meet Avista’s
renewable energy goals under I-937, benefit from federal tax incentives, and help
mitigate dissolved gases.

Table 6.12: Hydro Upgrade Potential

Plant
Potential
Capacity
(MW)
Potential
Energy
(aMW)
Upper Falls 2 1
Long Lake Second Powerhouse 60 - 120 18 - 20
Cabinet Gorge Second Powerhouse 50 7
Post Falls New Powerhouse 19 4
Monroe Street Second Powerhouse 38 16
0
10
20
30
40
50
0
2
4
6
8
10
19
9
2

-
Mo
n
r
o
e

S
t
r
e
e
t

U
n
i
t

1
19
9
4

-
Ni
n
e

M
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3

&

4
19
9
4

-
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1
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-
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4
19
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6

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1
19
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7

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2
19
9
9

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3
20
0
1

-
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3
20
0
1

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2
20
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4
20
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9

-
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1
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2
20
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2

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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 124 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-14
Upper Falls
The Upper Falls hydroelectric upgrade would consist of replacing the single unit’s
turbine runner and modifying the existing draft tube to improve efficiency. Initial costs
estimates are $7 million or $3,500 per kW, for an additional two MW of capacity and
8,760 MWh of energy. This upgrade would require FERC licensing changes and help
meet Avista’s I-937 renewable energy goals.

Long Lake Second Powerhouse
Avista studied a second powerhouse at Long Lake about 20 years ago using a small
arch dam located on the south end of the project site. See Figure 6.3 for a concept of
the project. The potential cost of this resource could exceed $120 million and provide an
additional 158,000 to 178,000 MWh of energy per year and 60 to 120 MW of added
capacity. This project would be a major undertaking and would take several years to
complete. It would require major changes to the Spokane River license, but could help
reduce total dissolved gas concerns by reducing spill at the project. The incremental
capacity would also help meet future winter peak loads, but may not contribute greatly
to summer peak needs. The incremental energy might qualify under I-937.

Figure 6.3: Long Lake Second Powerhouse Concept Drawing

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 125 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-15
Cabinet Gorge Second Powerhouse
Avista is exploring the addition of a second powerhouse at the Cabinet Gorge project
site to mitigate total dissolved gas. A new powerhouse would benefit from an existing
diversion tube around the dam. The potential cost of this resource could be as high as
$115 million. The new powerhouse could provide 57,000 MWh of additional energy per
year, and 50 MW of additional capacity. This project would be a major engineering
project, take several years to complete, and require major changes to the Clark Fork
River FERC license. As with the other potential hydroelectric upgrade projects, this
project might help Avista meet its I-937 renewable energy goals.

Post Falls Refurbishment
The Post Falls hydroelectric project is 105 years old. An upgrade to this project includes
a total rebuild of the powerhouse and equipment while leaving the exterior intact. The
project would remove the existing horizontal units, replacing them with higher efficiency
and higher capacity vertical units. The cost of this upgrade could be as high as $75
million. It would add 33,000 MWh of energy each year and provide an additional 19 MW
of capacity. Like the other potential hydroelectric projects, this would require a
reopening of the Spokane River FERC license and might help meet Avista’s I-937
renewable energy goals.

Monroe Street Second Power House
Avista replaced the powerhouse at its Monroe Street project on the Spokane River in
1992. An upgrade option would include the addition of a new powerhouse to capture
additional flows and be a major undertaking requiring substantial cooperation with the
city because of disruption in the Riverfront Park and downtown Spokane area during
construction. This project would require dredging the river on the western edge of the
park and creating a tunnel between city hall and the Monroe street substation. The
expected cost for this project would be $95 million, and it could create an additional
142,000 MWh of energy per year and 37.5 MW of incremental capacity. The
incremental generation of the upgraded facility might help meet Avista’s I-937
renewable energy goals.

Thermal Resource Upgrades
Several upgrade opportunities exist in Avista’s thermal fleet that would add capacity
and/or increase operating efficiency. Avista plans an economic viability study for each
option prior to the 2013 IRP. The following is a list of potential upgrades to the
Rathdrum and Coyote Springs 2 projects that the Avista may consider. Table 6.9 is a
summary of the nominal levelized costs of each of the upgrade options for the
Rathdrum CT and Table 6.10 provides nominal levelized costs for the Coyote Springs 2
upgrade options.

Rathdrum CT to CCCT Conversion
The Rathdrum CT has two GE 7EA units in simple cycle configuration built in 1994 with
an approximate 160 MW of combined output used to serve customers in peak load
conditions. It is possible to convert this peaking facility to a combined cycle plant by
adding between 78 and 91 MW of steam-turbine capacity (depending upon
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 126 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-16
temperature) and increasing its operating efficiency from a heat rate of 11,612 Btu/kWh,
in its existing configuration, to a heat rate of about 7,986 Btu/kWh. The capital cost for
this upgrade is $81.5 million. Two major issues challenge this conversion. The first is
cooling water. Avista does not have water rights adequate to cool the plant with water.
Therefore, it is likely that air-cooling at the plant is necessary at higher cost. The second
major issue is noise. Major residential development now exists at the plant site. Given
these concerns, this option is not in the PRS.

Rathdrum CT Water Demineralizer
Another potential upgrade at Rathdrum is to add a water demineralizer to allow inlet
fogging in the summer. This upgrade would increase plant capacity by 17.6 MW and
increase its operating efficiency by 0.5 percent on hot summer days. The upgrade will
cost approximately $1 million.

Table 6.13: Rathdrum CT Upgrade Options ($/MWh)

Rathdrum CT:
Convert to
CCCT
(Air Cooled)
Rathdrum CT:
Convert to
CCCT (Water
Cooled)
Rathdrum CT:
Add
Demineralizer
Capital recovery and taxes 18.62 15.39 4.92
AFUDC 1.94 1.61 0.08
Federal Tax Incentives 0.00 0.00 0.00
Fuel Costs 54.31 53.25 80.89
Fuel Transport 5.53 5.42 8.06
Greenhouse Gas emissions adder 15.19 14.90 22.63
Fixed O&M 2.45 2.45 0.00
Variable O&M 1.62 1.87 1.24
Interconnection capital recovery 0.54 0.54 0.00
Other Emissions 0.00 0.00 0.00
Excise taxes and other overheads 3.45 3.39 4.88
Total Cost 103.64 98.80 122.72

Coyote Springs 2 Inlet Chiller
There are two potential inlet chiller options for increasing summer capacity at the
Coyote Springs 2 CCCT plant in Boardman, Oregon. One option is to add an inlet chiller
to cool the air going into the machine; the second option is to add a thermal unit in
addition to a chiller to optimize chiller operations. Avista estimates this upgrade to add
30 MW of capacity on a 100-degree day at a cost of $10 million. Adding the thermal
storage technology capacity in conjunction with an inlet chiller would increase plant
capacity by an additional 2.2 MW for an additional $1.0 million.

Coyote Springs 2 Cold Day Controls
Another upgrade option at the Coyote Springs 2 plant is to install an upgraded CT
control system to increase its operating performance on cold days. This software
upgrade could increase capacity by 17.6 MW on a zero-degree day at an estimated cost
of $4.5 million.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 127 of 1069
Chapter 6- Generation Resource Options
Avista Corp 2011 Electric IRP 6-17

Coyote Springs 2 Advanced Hot Gas Path Components
Coyote Springs 2 could benefit from the installation of advanced hot gas path
components. This upgrade could add approximately 8 MW of capacity around the year
and increase efficiency by one percent. The estimated cost for this upgrade is $18
million with additional annual plant maintenance costs of $3.9 million.

Coyote Springs 2 Cooling Optimization Hardware
Adding cooling optimization hardware to Coyote Springs may add 2.6 MW of capacity
around the year and improve plant efficiency by 0.5 percent. The estimated cost of this
project is $7.2 million.

Table 6.14: Coyote Springs 2 Upgrade Options ($/MWh)

Inlet
Chiller
Inlet
Chiller &
Thermal
Storage
Cold Day
Controls
Enhanced
Hot Gas
Path
Comp.
Optional
Cooling
Package
Capital recovery and taxes 53.23 55.79 20.20 17.41 47.12
AFUDC 0.91 0.95 0.17 0.30 0.80
Federal Tax Incentives - - - - -
Fuel Costs 46.42 46.42 46.42 45.91 46.19
Fuel Transport 4.53 4.53 4.53 4.67 4.70
Greenhouse Gas emissions adder 12.99 12.99 12.99 12.84 12.92
Fixed O&M - - - 36.10 -
Variable O&M - - - - -
Interconnection capital recovery 4.32 4.32 4.32 4.44 4.44
Other Emissions - - - - -
Excise taxes and other overheads 2.95 2.96 2.96 4.50 2.95
Total Cost 125.35 127.96 91.60 126.18 119.13

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 128 of 1069

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 129 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-1
7. Market Analysis

Introduction
This section describes the electricity and natural gas market environment developed for
the 2011 IRP. Contained in this chapter are risks Avista considers when meeting
customer demands at lowest reasonable cost. The analytical foundation for the 2011
IRP is a fundamentals-based electricity model of the entire Western Interconnect. The
market analysis compares potential resource options on their net value when operated
in the wholesale marketplace, rather than on the simple summation of their installation,
operation, maintenance, and fuel costs. The Preferred Resource Strategy (PRS)
analysis uses these net values when selecting future resource portfolios.

Understanding market conditions in the geographic areas of the Western Interconnect is
important, because regional markets are highly correlated because of large
transmission linkages between load centers. This IRP builds on prior analytical work by
maintaining the relationships between the various sub-markets within the Western
Interconnect, and the changing values of company-owned and contracted-for resources.
The backbone of the analysis is AURORAxmp, an electric market model that dispatches
resources to loads across the Western Interconnect with given fuel prices, hydroelectric
conditions, and transmission and resource constraints. The model’s primary outputs are
electricity prices at key market hubs (e.g., Mid-Columbia), resource dispatch costs and
values, and greenhouse gas emissions.

Marketplace
AURORAxmp is a fundamentals-based modeling tool used by Avista to simulate the
Western Interconnect electricity market. The Western Interconnect includes the states
west of the Rocky Mountains, the Canadian provinces of British Columbia and Alberta,
and the Baja region of Mexico as shown in Figure 7.1. The modeled area has an
installed resource base of approximately 240,000 MW.

Section Highlights
Gas and wind resources dominate new generation additions in the West.
Shale gas lowers gas and electricity price forecasts from the previous IRP.
A growing Northwest wind fleet reduces springtime market prices below zero
in some hours.
Federal greenhouse gas policy is uncertain; the IRP quantifies this uncertainty
by modeling four different mitigation regimes.
The Expected Case reduces Western Interconnect greenhouse gas emissions
by 28 percent (18 percent from current levels) relative to a case without a
carbon mitigation regime.
Carbon mitigation policy increases Western Interconnect costs by $3.5 billion
annually.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 130 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-2
Figure 7.1: NERC Interconnection Map

The Western Interconnect is separated from interconnects to the east and ERCOT
except by eight inverter stations. The Western Interconnect follows operation and
reliability guidelines administered by the Western Electricity Coordinating Council
(WECC).

The Western Interconnect electric system is divided into 16 AURORAxmp modeling
zones based on load concentrations and transmission constraints. After extensive study
in the 2009 IRP, Avista models the Northwest region as a single zone because this
configuration dispatches resources in a manner most reflective of historical operations.
Table 7.1 describes the specific zones modeled in this IRP.

Table 7.1: AURORAXMP Zones

Northwest- OR/WA/ID/MT Southern Idaho
Eastern Montana Wyoming
Northern California Southern California
Central California Arizona
Colorado New Mexico
British Columbia Alberta
North Nevada South Nevada
Utah Baja, Mexico

Fundamentals-based electricity models range in their abilities to emulate power system
operations accurately. Some models account for every bus and transmission line, while
other models utilize regions or zones. An IRP requires regional price and plant dispatch
information but does not require detailed modeling at the bus level.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 131 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-3
Western Interconnect Loads
The 2011 IRP relies on a load forecast for each zone of the Western Interconnect.
Avista uses external sources to quantify load growth estimates across the west. These
load estimates include impacts of increasing energy efficiency and demand destruction
caused by potential emissions legislation and the associated price increases expected
to reduce loads over time from their present trajectory.

Specific regional load growth levels are in Table 7.2. Avista projects that overall
Western Interconnect loads rise 1.65 percent annually over the next 20 years, from
103,840 aMW in 2012 to 141,654 aMW in 2031. Included in this forecast are rising plug-
in electric vehicle (PHEV) loads. Load growth rates without PHEV would be 1.57
percent. Absent conservation efforts, Western Interconnect loads are 9,000 aMW higher
in 2031. Figure 7.2 illustrates the load forecast and the impacts of new conservation and
PHEVs. The Northwest grows more slowly than the Western Interconnect at large.
Loads rise one percent per year over the IRP timeframe.

Figure 7.2: 20-Year Annual Average Western Interconnect Energy

Transmission
The IRP reflects various regional transmission projects announced over the past several
years. Many of these projects move distant renewable resources to load centers in
support of state-level renewable portfolio standards (RPS). Transmission upgrades
included in the IRP are in Table 7.2. Transmission upgrades within AURORAxmp zones
were not included explicitly in the model, as they do not affect power transactions
between zones.

-
25,000
50,000
75,000
100,000
125,000
150,000
175,000
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
av
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r
a
g
e

m
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g
a
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t
s
New Conservation
PHEV
Net Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 132 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-4
Table 7.2: Western Interconnect Transmission Upgrades Included in Analysis

Project From To
Year
Available
Capacity
MW
Canada – PNW Project British Columbia Northwest 2018 3,000
PNW – California Project Northwest California 2018 3,000
Eastern Nevada Intertie North Nevada South Nevada 2015 1,600
Gateway South Wyoming Utah 2015 3,000
Gateway Central Idaho Utah 2015 1,320
Gateway West Wyoming Idaho 2016 1,500
SunZia/Navajo Transmission Arizona New Mexico 2016 3,000
Wyoming – Colorado Intertie Wyoming Colorado 2013 900
Hemingway to Boardman Idaho Northwest 2019 1,500

New Resource Additions
An estimate for new resource capacity in the Western Interconnect is forecasted as part
of the long-term electric market price forecast. It accounts for load growth and various
other mandates. These additions meet capacity, energy, ancillary services, and
renewable portfolio mandates. To meet capacity requirements, gas-fired CCCT or
SCCT, solar, wind, coal IGCC, coal IGCC with sequestration, and nuclear were options
were considered.1 For the first time, Avista assumes that no new pulverized coal
additions in the Western Interconnect over the forecast horizon.

Many states have created RPS requirements promoting renewable generation to curb
greenhouse gas emissions, provide jobs, and to diversify the energy mix of the United
States. RPS legislation generally requires utilities to meet a portion of their load with
qualified renewable resources. No federal RPS mandate exists presently; therefore,
each state defines their RPS obligations differently. AURORAxmp cannot model RPS
levels explicitly. Instead, Avista input RPS requirements into the model at levels
satisfying state laws. Renewable resource portfolios adequate to meet Western
Interconnect RPS obligations were input using work by the Northwest Power and
Conservation Council (NPCC); these percentages formed the basis for RPS shortfalls in
each state. Beyond the manually input RPS resources, the model selected no additional
renewables.

Figure 7.3 illustrates new capacity and RPS additions made in the modeling process.
Wind and solar facilities meet most renewable energy requirements.. Geothermal,
biomass, and hydroelectric resources provide a more limited contribution to RPS needs.
Renewable resource choices are modeled to differ by state depending on the
requirements of state laws and the availability of renewable resources in a region. For
example, the Southwest will meet RPS requirements with solar and wind given policy
choices by those states. The Northwest will use a combination of wind and hydroelectric
upgrades because the economic costs of these resources are the lowest. Rocky
1 Wind receives a five percent capacity credit on a regional basis; it receives no capacity credit where
selected to meet Avista requirements.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 133 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-5
Mountain states will predominately use wind to meet RPS requirements, again due to
the fact that wind is the least-cost renewable resource modeled in the IRP.

Figure 7.3: New Resource Added (Nameplate Capacity)
Fuel Prices and Conditions
Fuel cost and availability are some of the most important drivers of resource values.
Some resources, including geothermal and biomass, have limited fuel options or
sources, while coal and natural gas have more fuel sources. Hydro and wind use free
fuel sources, but are highly dependent on weather.

Natural Gas
The fuel of choice for new base load and peaking capability continues to be natural gas.
Natural gas is subject to price volatility, though increasing unconventional sources may
reduce future volatility. Avista uses forward market prices and a combination of two
forecasts from prominent energy industry consultant to develop its natural gas price
forecast for this IRP.2 The forecast uses an equal weighting of the consultant forecasts
and forward prices in 2012.3 After 2012, the weighting of forward prices fell by 10
percent each year through 2016. After 2016, the forecast includes a 50/50 weighting of
the two consultant forecasts. For example, in 2015 the price forecast is a weighted
average of the market (20 percent), Consultant 1 (40 percent) and Consultant 2 (40
percent). The long-term forecasts include impacts of potential national carbon
legislation. Carbon legislation will increase demand for natural gas as generation shifts
away from coal. Figure 7.4 shows the price forecast for Henry Hub; the levelized
nominal price is $7.30 per Dth. The forecast without carbon legislation is $6.78 per Dth.
2 Consultant forecasts as of December 2010. 3 The 50 percent weighting applies to the average of the two consultant forecasts.
-
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
Natural Gas Peakers
Natural Gas CCCT
Hydro
Geothermal
Biomass
Solar
Wind
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 134 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-6

Figure 7.4: Henry Hub Natural Gas Price Forecast

The forecast from Consultant 1 assumes a timely and moderate economic recovery and
aggressive long term demand growth from the power sector in part due to an improved
competitive position relative to coal. The forecast includes a modest federal carbon
price of $14 per metric ton beginning 2016 and rising to $25/metric ton by 2025. This in
turn results in accelerated coal retirements pressuring prices early in the forecast. A
brief price respite occurs following carbon legislation but prices resume their build as
competition for capital, equipment and labor from strong recovery in oil demand drive up
gas drilling costs and supply growth from shale gas moderates. An Alaskan gas pipeline
around 2026 produces a brief gas glut but is quickly absorbed and the uptrend in prices
resumes.

The forecast from Consultant 2 assumes a more gradual and modest economic
recovery including a more moderate rebound in power demand early in the forecast.
Their outlook reflects an expectation of significant low cost supplies from shale gas
resources that quickly respond to rising demand. The improved predictability of shale
gas volumes and costs prompt active hedging by producers when prices escalate
counteracting the trend and resulting in more stable pricing. This forecast does not
include carbon legislation or an Alaskan natural gas pipeline.

Price differences across North America depend on demand at the trading hubs and the
pipeline constraints between them. Many pipeline projects are in the works in the
Northwest and the west to access historically cheaper gas supplies located in the Rocky
Mountains. Table 7.3 presents western gas basin differentials from Henry Hub prices.
Prices converge over the course of the study as new pipelines and new sources of gas
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
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s

p
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Expected Case Consultant 1 Consultant 2 Market
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 135 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-7
come online. To illustrate the seasonality of natural gas prices, monthly Stanfield price
shapes in Table 7.4 show various forecast years.

Table 7.3: Natural Gas Price Basin Differentials from Henry Hub

Basin 2012 2015 2020 2025 2030
Stanfield 93.4% 94.4% 90.3% 92.6% 90.6%
Malin 94.7% 95.7% 92.5% 94.9% 92.9%
Sumas 93.7% 94.6% 88.5% 90.5% 88.3%
AECO 89.1% 90.6% 86.3% 88.1% 85.8%
Rockies 93.6% 94.9% 90.6% 89.4% 87.2%
Southern CA 97.5% 99.3% 99.3% 100.0% 102.7%
Stanfield 93.4% 94.4% 90.3% 92.6% 90.6%

Table 7.4: Monthly Price Differentials for Stanfield

Month 2012 2015 2020 2025 2030
Jan 94.4% 95.9% 92.2% 94.7% 92.5%
Feb 94.4% 96.1% 92.0% 94.7% 92.5%
Mar 94.0% 95.6% 92.0% 94.3% 93.9%
Apr 92.6% 94.1% 89.4% 91.3% 90.0%
May 92.2% 93.1% 88.2% 90.4% 88.8%
Jun 92.3% 93.1% 88.2% 90.5% 88.5%
Jul 92.6% 92.9% 87.8% 90.0% 88.0%
Aug 92.7% 93.1% 88.0% 90.0% 88.3%
Sep 93.0% 93.9% 89.7% 92.1% 89.2%
Oct 93.3% 94.8% 90.6% 93.6% 90.4%
Nov 94.4% 95.0% 92.5% 95.3% 92.7%
Dec 94.9% 95.0% 92.7% 94.9% 92.5%

Unconventional Natural Gas Supplies
Shale natural gas production has game-changing impacts on the natural gas industry,
dramatically revising the amount of economical natural gas production. Shale gas often
is lower in cost than conventional natural gas production because of economies of
scale, near elimination of exploration risks and standardized, sophisticated production
techniques that streamline costs and minimize the time from drilling to market delivery.
Shale gas could continue to greatly alter the natural gas marketplace, holding down
both price and volatility over the long run as production quickly responds to changing
market conditions. This in turn leads to numerous ripple effects, including longer-term
bilateral hedging transactions, new financing structures including cost index pricing,
and/or vertical integration by utilities choosing to limit their exposure to natural gas price
increases and volatility through the acquisition of shale-gas reserves as illustrated by
the recent purchase of reserves by Northwest Natural Gas Company. See Figure 7.5 for
the projected change in contribution of shale to other sources of natural gas between
2009 and 2035.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 136 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-8
Figure 7.5: Shale Gas Production Forecast4

Shale gas is not free of controversy. Concerns include water, air, noise, and seismic
environmental impacts arising from unconventional extraction techniques. Water issues
include availability, chemical mixing, groundwater contamination, and disposal. Air
quality concerns stem from methane leaks during production and processing. Mitigating
excessive noise in urban drilling and elevated seismic activity near drilling sites are also
fomenting apprehension. State and federal agencies are reviewing the environmental
impacts of this new production method. As a result, unconventional natural gas
production in some areas has stopped. Increased environmental protections might
increase costs and environmental uncertainty could precipitate increased price volatility.

Shale gas production influences the U.S. liquid natural gas (LNG) market. It has broken
the link between North American natural gas global LNG prices. Numerous planned re-
gasification terminals are on hold or cancelled. Some facilities now seek approvals to
become LNG exporters rather than importers. These changes appear to affect gas
storage and transportation infrastructure. For example, the Kitimat LNG export terminal
in northern British Columbia, if built, will export significant LNG quantities to Asian
markets. These exports will affect overall market conditions for natural gas in the United
States and the Pacific Northwest.

Coal
As discussed earlier in this chapter, there are no new coal plants built for the Western
Interconnect. Therefore, the coal price forecasts affect only existing coal facilities. Each
plant’s historical fuel costs escalate by rates contained in a consultant’s study. The
average annual price increase over the IRP timeframe is 1.4 percent. For the Colstrip
facility, where Avista has access to project-specific information, Avista did not rely on
the consultant study. Instead, it used an escalation rate based on existing contracts.

Woody Biomass
The future price and availability of woody biomass (or hog fuel) is critical to
understanding the viability of new wood-fired facilities. Hog fuel availability is highly
4 Source: Energy Information Administration (EIA)
Shale Gas,
16%
Other
Sources,
84%
2009
Shale Gas,
47%Other
Sources,
53%
2035
Source: EIA
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 137 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-9
dependent on overall lumber demand. Avista has operated its Kettle Falls wood-fired
generator since 1983. When it was constructed, hog fuel was a waste product from area
sawmills that procured at a near-zero cost. The plant had surplus fuel even into the mid-
2000s, but has struggled since then to procure enough reasonably priced fuel because
of the impacts of a recession on the housing market, and the resultant decrease in
lumber demand. The IRP projects biomass prices in the west to extend from historical
levels at a rate of three percent per year to reflect ongoing tight market conditions.

Hydroelectric
The Northwest and British Columbia have substantial hydroelectric generation capacity.
A favorable characteristic of hydroelectric power is its ability to provide near-
instantaneous generation up to and potentially beyond its nameplate rating. This
characteristic is particularly valuable for meeting peak load demands, following general
intra-day load trends, shaping energy for sale during higher-valued peak hours, and
integrating variable generation resources. The key drawback to hydroelectricity is its
output variability a month-to-month and year-to-year.

This IRP uses the results of the Northwest Power Pool’s (NWPP) 2009-10 Headwater
Benefits Study to model regional hydro availability. The NWPP study provides energy
levels for each hydroelectric facility by month over a 70-year hydrological record
spanning the years 1928 to 1999. British Columbia’s hydroelectric plants are modeled
using data from the Canadian government5.

Many of the analyses in the IRP use an average of the 70-year hydroelectric record;
whereas stochastic studies randomly draw from the 70-year record (see Risk Analysis
later in this section), as the historical distribution of hydroelectric generation is not
normally distributed. AURORAxmp maps each hydroelectric plant to a load zone.

For Avista hydroelectric plants, proprietary software provides a more detailed
representation of operating characteristics and capabilities. Figure 7.6 shows average
hydroelectric energy (in red) of 18,172 aMW in Washington, Oregon, Idaho, Western
Montana, and British Columbia. The chart also show the range in potential energy used
in the stochastic study, with a 10th percentile water year of 14,395 aMW (-21 percent),
and a 90th percentile water year of 21,629 aMW (+40 percent).

5 Statistics Canada, www.statcan.gc.ca
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 138 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-10
Figure 7.6: Northwest Expected Energy

AURORAxmp represents hydroelectric plants using annual and monthly capacity
factors, minimum and maximum generation levels, and sustained peaking generation
capabilities. The model’s objective, subject to constraints, is to move hydroelectric
generation into peak hours to follow daily load changes; this maximizes the value of the
system consistent with actual operations.

Wind
Additional wind resources are necessary to satisfy renewable portfolio standards. These
additions mean significant competition for the remaining higher-quality wind sites. The
capacity factors in Figure 7.7 present average generation for the entire area, not for
specific projects. The IRP uses capacity factors from a review of the Bonneville Power
Administration (BPA) and the National Renewable Energy Laboratory (NREL) data.

0%
2%
4%
6%
8%
10%
12%
13
,
0
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14
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average megawatts
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 139 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-11
Figure 7.7: Regional Wind Expected Capacity Factors

Greenhouse Gas Emissions
Greenhouse gas regulation is one the greatest fundamental risks facing the electricity
marketplace today because of the industry’s heavy reliance on carbon-emitting thermal
power generation plants. Reducing carbon emissions at existing power plants, and the
construction of low- and non-carbon-emitting technologies, changes the resource mix
over time. No federal regulations presently constrain greenhouse emissions, but federal
legislation is still expected. In the interim, several western states and Canadian
provinces are promoting the Western Climate Initiative as an alternative to federal
legislation. The goal is to develop a multi-jurisdictional greenhouse gas policy.

To simulate greenhouse gas regulation, Avista developed four policy models and their
assumed financial impact on the energy marketplace. Each policy represents a potential
path governments could take over the next several years. The policies received
weighting factors, with the weighted average price of the policies forming the Expected
Case. The four greenhouse gas policies used in this IRP are in Table 7.5:

32.0 33.5 34.5
30.7
37.2 38.5
28.8 29.0
32.3
0
10
20
30
40
50
NW BC AB CA MT WY SW UT CO
ca
p
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f
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(
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)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 140 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-12
Table 7.5: Monthly Price Differentials for Stanfield

Strategy
Weight
(%) Details
Regional
Greenhouse
Gas Policies
30 – Greenhouse gas reductions in California, Oregon,
Washington, and New Mexico between 2014 and 2019.
– About a 10 percent reduction below 2005 levels by 2020.
– Beginning in 2020, shift to National Climate Policy with
15 percent below 2005 levels by 2030.
National
Climate
Policy
30 – Federal legislation only applies beginning in 2015
– About 15 percent below 2005 levels by 2020 and about
35 percent below 2005 levels by 2030.
National
Carbon Tax
30 – Federal legislation only applies.
– $33 per short ton, then 5 percent per year escalation for
the remainder of the study.
– Begins in 2015.
No
Greenhouse
Gas
Reductions
10 – No carbon reduction program.
– State-level emission performance standards apply and
no new coal-plants added in the Western United States.

Figure 7.8 shows the expected price of greenhouse gas emission for each policy
described in Table 7.5 and the weighted average price comprising of the Expected
Case. The carbon policy in each stochastic study comes from the distribution of the four
cases described above.

Figure 7.8: Price of Greenhouse Gas Credits in each Carbon Policy

$0
$20
$40
$60
$80
$100
$120
$140
20
1
2
20
1
3
20
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National Climate Policy
Delayed National Climate Policy
National GHG Tax
No GHG Reductions
Expected Case
Regional GHG Policy
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 141 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-13
Risk Analysis
To account for the uncertainty of future electric prices, a stochastic study is preformed
using the variables discussed earlier in this chapter. It is better to represent the
electricity price forecast as a range rather than a point estimate. Point estimates are
unlikely to forecast any of the underlying assumptions perfectly, whereas stochastic
price forecasts develop a more robust resource strategy. For example, fuel price
volatility and carbon risk directly affect natural gas-fired resources but not wind
resources. Wind resources, on the other hand, are subject to varying output on an
hourly, daily, monthly, and annual basis. In prior IRP’s Avista modeled 250 to 300
stochastic iterations or scenarios. This IRP developed 500 iterations to provide a more
robust results distribution to better illustrate potential tail outcomes. The increased
number of studies will affect the overall results of the IRP, but should assist in
explaining the results better, especially at the tails. The next several pages discuss
input variables driving market prices, and describe the methodology and the range in
inputs used in the modeling process.

Greenhouse Gas Prices
Without established federal legislation and no formal rules for western carbon markets,
the expected price of carbon emission is difficult to determine without resorting to a
macroeconomic model. Even with carbon rules in place, prices in a cap and trade
program reflect the tradeoff and interaction between natural gas and coal prices and the
ultimate maximum emissions level allowed by the program. Further, it is likely that
certain states might stop pursuing cap and trade programs because of recent
successes in shutting down northwest coal-fired facilitates. As discussed earlier, four
possible legislative outcomes reflect the uncertainty surrounding future legislation. Each
was included in the stochastic analysis based on its weighting.

The price of carbon mitigation will vary over time, as the natural gas price affects the
cost efficiency of displacing coal-fired generation. When natural gas prices rise, so too
must carbon prices. To account for this relationship, once the carbon policy is randomly
selected based for each scenario the resultant carbon price is adjusted up or down to
reflect the natural gas price forecast in a manner to attain the required carbon mitigation
goal. An example of this adjustment is in Figure 7.9 for the year 2020. The predominant
market prices are between $40 and $49 per short ton of carbon. The distribution
reflected the Carbon Tax policy strategy by approximately 100 of these iterations has a
price of $42.12 per short ton of carbon.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 142 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-14
Figure 7.9: Distribution of Annual Average Carbon Prices for 2020

Natural Gas
Natural gas prices are among the most highly volatile of any traded commodity. Daily
AECO prices ranged between $0.78 and $12.92 per Dth between 2002 and 2010.
Average AECO monthly prices since December 1999 are in Figure 7.10. Prices
retreated from their 2008 highs to a low of $2.69 per Dth in July 2009, but prices have
stabilized in the $3 to $4 range over the past year. This stabilization likely is a result of
both waning demand due to the U.S. recession and shale gas discoveries.

0%
5%
10%
15%
20%
25%
30%
35%
$0
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 143 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-15
Figure 7.10: Historical AECO Natural Gas Prices
There are several valid methods to stochastically model natural gas prices. For this IRP,
Avista uses a new method to represent the price history our industry has witnessed.
The mean prices discussed above are the starting point. Prices then vary using
historical month-to-month volatility using a lognormal distribution. The lognormal
distribution’s standard deviation differs monthly depending on historical month-to-month
changes.

The Stanfield hub natural gas price distribution is in Figure 7.11 for 2012, 2020, and
2030. Mean prices in 2012 are $4.89 per Dth and the median level is $4.80 per Dth. The
90th percentile is $5.49 per Dth and the TailVar90, or average of the highest 10 percent
of the iterations, is $5.92 per Dth. Figure 7.12 illustrates the range of gas prices for each
year of the price forecast. Stanfield prices are black bars; white bars represent the
range between the 10th and 90th percentiles; triangles represent TailVar90.

$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
19
9
9
20
0
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20
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20
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2
20
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 144 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-16
Figure 7.11: Stanfield Annual Average Natural Gas Price Distribution

Figure 7.12: Stanfield Natural Gas Distributions

0%
10%
20%
30%
40%
50%
60%
$0
.
0
0
$1
.
0
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2012
2020
2030
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20
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2
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3
20
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4
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5
20
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6
20
1
7
20
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8
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 145 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-17
Load
Several factors drive load uncertainty. The largest short-run driver run is weather. Over
the long-run economic conditions, such as the recent economic downturn, tend to have
a more significant effect on the load forecast. Underlying IRP loads increase at the
levels discussed earlier in this chapter, but risk analyses emulate the varying of weather
conditions and resultant load impacts.

To model weather variation, Avista continues to use a method it adopted for its 2003
IRP. FERC Form 714 data for the years 2005 through 2009 for the Western
Interconnect form the basis for the analysis. Correlations between the Northwest and
other Western Interconnect load areas represent how loads move across the larger
system. This method avoids oversimplifying the Western Interconnect load picture.
Absent the use of correlation, stochastic models merely offset changes in one variable
with changes in another, thereby virtually eliminating the possibility of modeling
correlated excursions. Given the high degree of interdependency across the Western
Interconnect created by significant intertie connections, the additional accuracy in
modeling loads in this matter is crucial for understanding variation in wholesale
electricity market prices. It is also crucial for understanding the value of resources used
to meet variation (i.e., peaking generation).

Tables 7.6 and 7.7 present the load correlations. Statistics are relative to the Northwest
load area (Oregon, Washington, and North Idaho). ―NotSig‖ in the table indicates that no
statistically valid correlation exists in the evaluated load data. ―Mix‖ indicates the
relationship was not consistent across the 2005 to 2009 period. For regions and periods
with NotSig and Mix results, no correlation exists. Tables 7.8 and 7.9 provide the
coefficient of determination (standard deviation divided by the average) values for each
zone. The weather adjustments are consistent for each area, except for shoulder
months where loads tend to diverge from one another.

Table 7.6: January through June Area Correlations

Jan Feb Mar Apr May Jun
Alberta 74% 29% 70% 64% 18% 65%
Arizona 73% 75% 74% 8% Not Sig 8%
Avista 90% 87% 82% 80% 60% 42%
British Columbia 84% 84% 75% 46% Not Sig Mix
Colorado Mix Mix Mix Mix Not Sig Not Sig
Montana 82% 76% 69% 55% 33% 28%
New Mexico 8% Not Sig Not Sig Not Sig 16% Not Sig
North California 34% 36% 8% Not Sig 34% 8%
North Nevada 73% 65% Not Sig 8% 25% 27%
South California 74% 45% 69% 31% 10% 44%
South Idaho 87% 86% 65% 40% 66% 28%
South Nevada 67% 83% 37% Not Sig Mix 16%
Utah 25% Not Sig 8% Not Sig 17% Not Sig
Wyoming 67% 54% 72% 36% 41% 18%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 146 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-18
Table 7.7: July through December Area Correlations

Jul Aug Sep Oct Nov Dec
Alberta 39% 45% 68% 55% 66% 66%
Arizona 9% 26% 9% Mix Mix 55%
Avista 60% 54% 19% 78% 88% 89%
British Columbia 8% Mix Mix 9% 72% 77%
Colorado Mix Mix Mix 54% 71% 49%
Montana Mix Not Sig 27% 53% 81% 86%
New Mexico 25% 27% 43% 17% 35% Not Sig
North California Not Sig Mix 63% Not Sig 26% 25%
North Nevada 29% 48% Not Sig 8% 74% 67%
South California 26% 27% 18% Not Sig Mix 54%
South Idaho 44% 47% Not Sig 46% 84% 83%
South Nevada 16% 18% Not Sig Mix Mix 64%
Utah Not Sig 16% 42% 27% 53% 17%
Wyoming 8% 9% 9% 8% Not Sig 53%

Table 7.8: Area Load Coefficient of Determination (Std Dev/Mean)

Jan Feb Mar Apr May Jun
Alberta 2.7% 2.4% 2.8% 2.6% 2.9% 3.2%
Arizona 5.5% 4.2% 3.4% 6.1% 10.2% 9.5%
Avista 6.7% 5.3% 6.3% 5.6% 5.3% 6.4%
Baja Mexico 9.5% 7.9% 8.5% 9.2% 10.5% 7.6%
British Columbia 5.0% 3.9% 4.5% 5.2% 4.6% 4.0%
North California 5.1% 5.1% 5.0% 5.6% 8.7% 9.5%
Colorado 4.5% 4.2% 4.6% 4.0% 5.4% 8.4%
South Idaho 5.4% 5.7% 5.4% 6.0% 10.2% 13.9%
Montana 5.3% 4.1% 4.0% 4.4% 4.0% 5.9%
Northern Nevada 2.6% 3.0% 2.9% 2.8% 4.8% 5.7%
Southern Nevada 4.8% 3.6% 3.3% 6.6% 13.0% 11.2%
New Mexico 4.5% 4.1% 4.3% 4.5% 7.4% 6.9%
Pacific Northwest 6.6% 5.9% 5.9% 5.7% 4.9% 4.9%
South California 6.0% 5.6% 6.0% 7.0% 8.6% 8.8%
Utah 4.1% 4.3% 4.5% 4.4% 6.3% 9.0%
Wyoming 7.0% 6.7% 6.5% 5.9% 5.0% 8.3%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 147 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-19
Table 7.9: Area Load Coefficient of Determination (Std Dev/Mean)

Jul Aug Sep Oct Nov Dec
Alberta 3.1% 3.2% 2.8% 2.7% 2.6% 3.3%
Arizona 7.0% 6.5% 8.4% 10.0% 4.7% 5.3%
Avista 6.9% 7.2% 5.8% 5.4% 6.6% 7.6%
Baja Mexico 6.4% 6.3% 11.6% 9.9% 7.6% 10.2%
British Columbia 4.7% 4.1% 4.4% 5.0% 6.2% 6.2%
North California 9.6% 7.9% 8.4% 5.3% 5.6% 5.6%
Colorado 7.2% 6.8% 5.8% 4.0% 5.1% 5.0%
South Idaho 5.9% 6.9% 10.5% 4.7% 6.8% 7.1%
Montana 5.1% 5.6% 3.7% 4.0% 5.0% 5.7%
Northern Nevada 5.1% 4.2% 4.9% 2.7% 3.6% 3.5%
Southern Nevada 6.9% 6.3% 12.0% 7.8% 3.8% 4.4%
New Mexico 6.0% 5.7% 5.8% 5.3% 5.0% 4.9%
Pacific Northwest 6.5% 5.2% 4.6% 5.3% 7.0% 8.6%
South California 7.7% 7.8% 10.3% 7.4% 6.8% 6.4%
Utah 5.1% 6.2% 6.7% 4.1% 4.9% 4.4%
Wyoming 8.3% 9.1% 6.1% 5.3% 7.1% 7.6%

Hydroelectric
Hydroelectric generation is historically the most commonly modeled stochastic variable
in the Northwest because it has a large impact on regional electricity prices. The IRP
uses a 70-year hydro record starting with the 1928-29 water year. A randomly drawn
water year is selected from the record using a ―bootstrapping‖ method, meaning that
each water year is used approximately 143 times in the study (500 scenarios x 20 years
/ 70 water year records). There is some debate in the Northwest over whether the
hydroelectric record has year-to-year correlation. Avista’s preliminary work in this area
has not found significant year-over-year correlation; the 70-year water record shows a
modest 41 percent correlation. Low correlation does not necessarily mean that the
correlation is zero. Further study of year-to-year correlation is an action item coming out
of this planning cycle.

Wind
Wind has the most volatile short-term generation profile of any resource presently
available to utilities. Storage, apart from some integration with hydroelectric projects, is
not a financially viable. This makes it necessary to capture wind volatility in the power
supply model to determine its value and impacts on the wholesale power markets.
Accurately modeling wind resources requires hourly and intra-hour generation shapes.
For regional market modeling, the representation is similar to how AURORAxmp models
hydroelectric resources. A single wind generation shape represents all wind resources
in each load area. This shape is smoother than it would be for individual wind plant, but
it closely represents the diversity that a large number of wind farms located across a
zone would create.

This simplified wind methodology works well for forecasting electricity prices across a
large market, but it does not accurately represent the volatility of specific wind resources
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 148 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-20
Avista might select as part of its Preferred Resource Strategy. Therefore individual wind
farm shapes form the basis of resource options for Avista.

Ten potential 8,760-hour wind shapes represent each geographic region or facility.
Each year contains a wind shape drawn from the ten representations, as is done with
the hydro record. The IRP relies on two data sources for the wind shapes. The first is
BPA balancing area wind data. The second is NREL-modeled data between 2004 and
2006.

Avista believes that an accurate representation of a wind shape across the West
requires meeting several conditions:

1. The data is correlated between areas and reflective of history.
2. Data within load areas needs to be auto-correlated (each hour correlated to each
other).
3. The average and standard deviation of each load area’s wind capacity factor
needs to be consistent with the expected amount of energy for a particular area
in the year and in each month.
4. The relationship between on- and off-peak wind energy needs to be consistent
with historic wind conditions. For example, more energy in off-peak hours than
on-peak hours where this has been experience historically.
5. Capacity factors for a diversified wind region should never be greater than about
90 percent due to turbine outages and wind diversity within-area.

Absent meeting these conditions, it is unlikely that any wind study provides an adequate
level of accuracy for planning efforts. The methodology developed for this IRP attempts
to keep the five requirements by first using a regression model of the historic data for
each region. The independent variables used in the analysis were month, hour type
(night or day), and generation levels from the prior two hours. To reflect correlation
between regions, a capacity factor adjustment reflects historic regional correlation using
an assumed normal distribution with the historic correlation as the mean. After this
adjustment, a capacity factor adjustment takes account of those hours with generation
levels exceeding a 90 percent capacity factor. The resulting capacity factors for each
region are in Table 7.10. A Northwest region example of an 8,760-hour wind generation
profile is in Figure 7.13. This example, shown in blue, has a 33 percent capacity factor.
Figure 7.14 shows actual 2010 generation recorded by BPA Transmission; in 2010, the
average wind fleet in BPA’s balancing authority had a 27.5 percent capacity factor.

Table 7.10: Expected Capacity factor by Region

Region
Capacity
Factor Region
Capacity
Factor
Northwest 32.0% Southwest 28.9%
California 30.9% Utah 28.8%
Montana 37.2% Colorado 32.2%
Wyoming 38.5% British Columbia 33.4%
Eastern Washington 30.7% Alberta 34.5%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 149 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-21
Figure 7.13: Wind Model Output for the Northwest Region

Figure 7.14: 2010 Actual Wind Output BPA Balancing Authority6
There is speculation that a correlation exists between wind and hydro, especially
outside of the winter months where storm events bring both rain to the river system and
wind to the wind farms. This IRP does not correlate wind and hydro due to a lack of
historical data to test this hypothesis. Where correlation exists, it would be optimal to
run the model 70 historical wind years with matching historical water years. A continual
study of this relationship is an action item for this plan.

Forced Outages
In most deterministic market modeling studies, plant forced outages are represented by
a simple average reduction to maximum capability. This over simplification generally
represents expected values well; however, in stochastic modeling, it is better to
represent the system more accurately by randomly placing non-hydro units out of
service based on a mean time to repair and an average forced outage rate. Internal
6 Chart data is from the BPA at: http://transmission.bpa.gov/Business/Operations/Wind/default.aspx.
0%
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 150 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-22
studies show that this level of modeling detail is necessary only for large natural gas-
fired (greater than 100 MW), coal, and nuclear plants. Forced outage rates and the
mean time to repair data come from analyzing the North American Electric Reliability
Corporation’s Generating Availability Data System (GADS) database.

Other Variables
Coal, hog fuel, fuel oil, and variable O&M variables are modeled stochastically. These
included either normal or lognormal distributions in the study. Due to their moderate
affects on market prices, their details are not discussed here but are in Appendix A.

Market Price Forecast
An optimal resource portfolio cannot ignore the extrinsic value inherent in its resource
choices. The 2011 IRP simulation compares each resource’s expected hourly output
using forecasted Mid-Columbia hourly prices over 500 iterations of Monte Carlo-style
scenario analysis.

Hourly electricity prices are either the operating cost of the marginal unit in the
Northwest or the economic cost to move power into or out of the Northwest. A forecast
of available future resources helps create an electricity market price projection. The IRP
uses regional planning margins to set minimum capacity requirements, rather than a
summation of the capacity needs of individual utilities in the region. Western regions
can have resource surpluses even where some utilities may be in deficit. This
imbalance can be due in part to ownership of regional generation by independent power
producers, and possible differences in planning methodologies used by utilities in the
region.

AURORAxmp assigns market values to each resource alternative available to the PRS,
but the AURORAxmp model does not itself select PRS resources. Several market price
forecasts determine the value and volatility of a resource portfolio. As Avista does not
know what will happen in the future, it relies on risk analysis to help determine an
optimal resource strategy. Risk analysis uses several market price forecasts with
different assumptions than the expected case or changes the underlying statistics of a
study. The modeling splits alternate cases are into stochastic and deterministic studies.

A stochastic study uses Monte Carlo analysis to quantify the variability in future market
prices. These analyses include 500 iterations of varying natural gas prices, loads,
hydroelectric generation, thermal outages, wind generation shapes, and greenhouse
gas emissions prices. Four stochastic studies—an Expected Case, one case without
greenhouse gas limitations, a high natural gas volatility case, and an early coal plant
retirement case are used. The remaining studies were deterministic scenario analyses.

Mid-Columbia Price Forecast
The Mid-Columbia is Avista’s primary electricity trading hub. The Western Interconnect
also has trading hubs on the California/Oregon Border (COB), Four Corners, Palo
Verde, SP15 (southern California), NP15 (northern California) and Mead. The Mid-
Columbia market is usually least cost because of low cost hydroelectric generation,
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 151 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-23
though other markets can at times be less expensive when Rocky Mountain area
natural gas prices are low and gas-fired generation is setting marginal power prices.

Fundamentals-based market analysis is critical to understanding the market
environment. The Expected Case includes two studies. The first is a deterministic
market view using expected levels for the key assumptions discussed in the first part of
this chapter. The second is a risk or stochastic study with 500 unique scenarios based
on different underlining assumptions for gas prices, load, greenhouse gas emissions
prices, wind generation, hydroelectric generation, forced outages, and others. Each
study simulates the entire Western Interconnect hourly between 2012 and 2031. The
analysis used 18 central processing units (CPUs) linked to a SQL server to simulate the
studies, creating over 45 GB of data requiring 2,000 hours of computing time.

The resultant average market prices developed from the stochastic model are similar to
the results from the deterministic model. Figure 7.15 shows the stochastic market price
results as the horizontal bar and the vertical bars represent the 10th and 90th percentile
for annual average prices. The triangle represents the Tail Var 90. The nominal
levelized price for the 20-year expected prices is $70.50 per MWh. The deterministic
prices are $0.87 per MWh lower than the stochastic prices presented in Figure 7.15.

Figure 7.15: Mid-Columbia Electric Price Forecast Range
The annual averages of the stochastic case on-peak, off-peak and levelized prices are
in Table 7.10. The Mid-Columbia market price averages $70.50 per MWh over the next
20 years. The 2009 IRP annual average nominal price was $93.74 per MWh. Spreads
between on- and off-peak prices are $11.48 per MWh over 20 years.

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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 152 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-24
Table 7.11: Annual Average Mid-Columbia Electric Prices ($/MWh)

Year
On
Peak
Off
Peak Flat
2012 40.87 36.51 44.16
2013 46.13 41.19 49.84
2014 49.11 43.62 53.23
2015 59.86 54.08 64.19
2016 63.25 57.12 67.84
2017 64.53 58.65 68.96
2018 66.55 60.33 71.21
2019 68.26 62.03 72.92
2020 71.05 64.56 75.91
2021 74.88 68.30 79.81
2022 80.49 73.65 85.62
2023 86.28 79.24 91.59
2024 91.26 83.55 97.04
2025 93.71 85.18 100.10
2026 91.35 83.08 97.54
2027 91.37 83.17 97.52
2028 98.30 89.92 104.63
2029 102.25 93.52 108.80
2030 107.56 97.77 114.89
2031 110.55 99.90 118.53
Nominal Levelized 70.50 63.94 75.42

Greenhouse Gas Emission Levels
Greenhouse gas levels increase over the study period absent social policies intended to
reverse the trend. The compliance costs of meeting potential greenhouse gas mitigation
discussed earlier in this chapter provide price signals to encourage reductions in
greenhouse gas emissions. Figure 7.16 shows the expected greenhouse gas emissions
from the 500 market forecast simulations. The average level of greenhouse gas
emissions from electric generation decrease by 11.2 percent over the 20-year study.
The figure also includes the 10th and 90th percentile statistics of the dataset. As
discussed earlier, ten percent of the cases assume no future carbon mitigation policies;
in these cases the incremental emissions are partly offset by now-expected coal plant
retirements7, low natural gas prices, and increased in wind generation that make coal
resources uncompetitive in some months of the forecast.

7 Recently announced retirements included in the 2011 IRP are 1,561 MW in Colorado, 585 MW in
Oregon, and 172 MW in Utah. The 2011 IRP analyses occurred prior to the announcement of the future
closure of the 1,376 MW Centralia Coal Plant in Washington State. Its closure should further carbon
emission reductions beyond those projected in this plan.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 153 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-25
Figure 7.16: Western States Greenhouse Gas Emissions

Resource Dispatch
State-level RPS goals and greenhouse gas legislation will change resource dispatch
decisions and affect future power prices. The Northwest already is witnessing the
market-changing effects of a 5,000+ MW wind fleet. Figure 7.17 illustrates that natural
gas fuels 23 percent of total generation in 2012, and 41 percent in 2031. Coal
generation decreases from 30 percent of Western Interconnect generation in 2012 to 13
percent in 2031. Solar and wind increase from 5 percent in 2012 to 13 percent in 2031.
New renewable generation sources offset coal generation reductions, but natural gas-
fired resources meet load growth.

Public policy changes to encourage renewable energy development and reduce
greenhouse gas emissions have the potential to change the electricity marketplace. On
its present trajectory, policy changes are likely to move the generation fleet toward its
potentially most volatile contributor—natural gas. These policies will displace low-cost
coal-fired generation with higher-cost renewables and gas-fired generation having lower
capacity factors (wind) and higher marginal costs (natural gas). If history is our guide,
regulated utilities will recover their costs from stranded coal plants, requiring customers
to pay even more. Further, wholesale prices likely will increase with the effects of the
changing resource dispatch driven by carbon emission limitations. New environmental
policy driven investment, combined with higher market prices, will necessarily lead to
retail rates that are higher than they would be absent greenhouse reduction policies.

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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 154 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-26
Figure 7.17: Base Case Western Interconnect Resource Mix

Scenario Analysis
Scenario analysis evaluates the impact of specific changes in underlying assumptions
on the market. Four stochastic studies were performed to help understand potential
market price changes and to examine the potential risk to Avista’s PRS if certain
assumptions were changed. The scenarios studied used 500 iterations to model the
effects of unconstrained carbon emissions, doubling of natural gas price volatility, and
the early retirement of coal plants. In addition to the stochastic market scenarios,
deterministic scenarios explained the impacts of low natural gas prices, high natural gas
prices, and high wind penetration. Prior IPRs used market scenarios to stress test the
PRS. Since the PRS accounts for a range of possible outcomes in its risk analysis, the
market scenario section is more limited in this IRP. Additional scenarios illustrate the
impacts potential policies might have on the industry, and how Avista could respond.

Unconstrained Carbon Emissions
The Unconstrained Carbon Emissions scenario is necessary to quantify projected
greenhouse gas policy costs. The first study is a deterministic scenario. A second
stochastic study models 500 individual iterations of varying natural gas prices, loads,
wind generation, forced outages, and hydroelectric conditions. The assumptions are
similar to the Expected Case with a few notable exceptions. First, natural gas prices are
lower because of less demand for natural gas caused by the continued use of coal-fired
generation. Without carbon legislation, natural gas prices are $0.52 per Dth lower
levelized over 20 years, a 7.1 percent decrease.

Without projected greenhouse gas mitigation, Mid-Columbia market prices are lower
and the total cost to serve customers is lower. The average of the 500 simulations finds
Hydro
Nuclear
Other
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WindSolar
Natural Gas
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 155 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-27
wholesale market prices $17.64 per MWh lower, on a nominal levelized basis,
compared to the Expected Case; this represents a 33.4 percent market price increase
for greenhouse gas emissions mitigation (Figure 7.18). The total cost of fuel in the
Western Interconnect with greenhouse gas mitigation is 7.65 percent higher than
without the greenhouse gas mitigation.

Figure 7.18: Mid-Columbia Prices Comparison with and without Carbon Legislation

Figure 7.19 illustrates the difference between greenhouse gas emissions with and
without the emissions costs included in the Expected Case. Based on the model results
and assumptions, emissions would be 8.5 percent higher in 2020 and 21.5 percent
higher in 2031 without the assumed greenhouse gas penalty. Increased greenhouse
gas emissions from higher coal-fired dispatch levels are the cause (see Figure 7.20).
The Expected Case, which includes greenhouse gas costs, reduces coal dispatch by 36
percent compared to the unconstrained greenhouse gas scenario, while natural gas
generation production increases by 19 percent.

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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 156 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-28
Figure 7.19: Western U.S. Carbon Emissions Comparison

Figure 7.20: Unconstrained Carbon Scenario Resource Dispatch

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Hydro
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Natural Gas Solar
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Hydro
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 157 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-29
Alternative Greenhouse Gas Mitigation Methods
As part of the development of the Expected Case’s four greenhouse gas policies,
market simulations were conducted to calculate the price of greenhouse gas required to
meet the reduction goal. Figure 7.8, shown earlier, illustrates the prices required to meet
the goals. Figure 7.21 illustrates the corresponding forecasted electric market prices at
Mid-Columbia on an average annual basis. The Expected Case line is the average of
the 500 simulations and the other lines represent the deterministic study results for each
greenhouse gas policy modeled. The values shown in Figure 7.22 are discounted and
levelized over the 20-year study period to represent the average price of power.

Figure 7.21: Average Annual Mid-Columbia Electric Prices for Alternative Greenhouse
Gas Policies

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National Cap & Trade
National Carbon Tax
Regional Carbon Policy
No Carbon Policy
Expected Case
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 158 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-30
Figure 7.22: Nominal Levelized Mid-Columbia Electric Prices for Alternative Greenhouse
Gas Policies
Figure 7.23 shows the annual expected greenhouse gas emissions levels for each of
the policies in. The four potential outcomes represent a range of futures under different
forms of greenhouse gas emissions legislation.

Figure 7.23: Annual Greenhouse Gas Emissions for Alternative Greenhouse Gas Policies

$70.50
$77.94
$72.34
$65.37
$50.18
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 159 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-31
Mandatory Coal Retirement
Proposed federal greenhouse gas cap and trade legislation is not law. The
Environmental Protection Agency and other organizations have pursued alternative
methods to reduce greenhouse gases from electric generation through regulatory
means. More details surrounding these policy alternatives are in the Planning
Environment chapter. The goal of this scenario is to illustrate the affect on electricity
market prices and system fuel costs where a policy is put in place requiring all coal
plants to retire at the end of 40 years of life, or to be phased out by 2020 if the plant is
already over 40 years old. The study uses 500 iterations as conducted on other studies.

In Figure 7.24 the average annual prices for this scenario are compared to the Expected
Case. The resulting prices levelized are $57.01 per MWh, 19 percent lower than the
Expected Case and 27 percent lower than the National Cap and Trade Strategy. The
surprising fact about this greenhouse gas policy is that Mid-Columbia prices are only 7.3
percent higher than the no carbon penalty case and the policy still achieves substantial
greenhouse gas reductions as shown in Figure 7.25. The driver of these results is that
natural gas-fired units face no carbon costs. Without the emissions adder to natural gas,
the marginal price of power remains as a natural gas-fired plant, and the increase in
power cost is more driven by the increased demand driving natural gas prices higher
and the inclusion of less low cost base load capacity in shoulder months. Although
lower market prices make this greenhouse gas strategy appealing, it does have a
negative consequence.

In Table 7.12 annual incremental costs of each potential strategy are compared and the
Early Coal Plant Retirement strategy is $3.2 billion more costly for the Western
Interconnect as compared to the National Cap and Trade strategy. This increase results
from the forced addition of new resources to replace coal plants rather than letting coal
plants remain on line, but instead dispatching them much less frequently, thus avoiding
new capital investment. One thing to keep in mind, is this a 20 year study of the western
interconnect. A longer-term national model may illustrate different results. Taking into
account national economics may also change opinions on the results as well. In the
end, any greenhouse reduction strategy needs to be a low cost solution that does not
affect the electricity marketplace in a negative manner.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 160 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-32
Figure 7.24: Average Annual Mid-Columbia Price Comparison of Greenhouse Gas
Policies

Figure 7.25: Expected Greenhouse Gas Emissions Comparison

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7
20
2
8
20
2
9
20
3
0
20
3
1
mi
l
l
i
o
n
s

o
f

s
h
o
r
t

t
o
n
s
Coal Mandatory Retirement
Expected Case
National Cap & Trade
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 161 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-33
Table 7.12: Impacts of Greenhouse Gas Mitigation Policies in the West

Market Scenario
Change to
GHG
Emissions
by 2031
Added
Levelized
Cost per
Year
(Billions)
Unconstrained Greenhouse Gas Case 14% 0.0
Expected Case -18% 3.5
Coal Mandatory Retirement -22% 8.1
National Cap & Trade -29% 4.9

High and Low Natural Gas Price Scenarios
The High and Low Natural Gas Price scenarios illustrate Mid-Columbia electric prices
for differing natural gas prices. These scenarios maintain carbon emissions at the same
level as the Expected Case to determine carbon prices at lower natural gas prices.
Figure 7.4, located earlier in the chapter, shows the low and high natural gas price
forecasts used in this scenario as Consultant 1 and Consultant 2 prices. Using these
prices, the resulting greenhouse gas price forecast assuming a cap and trade
mechanism that achieves the same reductions as the Expected Case is in Figure 7.26.
The natural gas prices in this scenario are approximately plus or minus 20 percent
compared to the Expected Case, but greenhouse gas prices must increase or decrease,
respectively, by approximately 31 percent to achieve the same greenhouse gas levels
as the Expected Case. The Mid-Columbia market price forecasts for the high and low
natural gas price cases are in Figure 7.27. The nominal levelized electric price for the
low gas price case is $57.00 per MWh and $82.17 per MWh for the high gas price case.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 162 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-34
Figure 7.26: Natural Gas Price Scenario’s Greenhouse Gas Emission Prices

Figure 7.27: Natural Gas Price Scenario’s Mid-Columbia Price Forecasts

$0
$20
$40
$60
$80
$100
$120
20
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do
l
l
a
r
s

p
e
r

s
h
o
r
t

t
o
n
Low Natural Gas Prices
High Natural Gas Prices
Expected Case
$0
$20
$40
$60
$80
$100
$120
$140
$160
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
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20
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2
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9
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3
1
do
l
l
a
r
s

p
e
r

M
W
h
High Natural Gas Prices
Expected Case
Low Natural Gas Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 163 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-35
Wind Proliferation and Negative Pricing
Avista uses the IRP process to identify and understand the impacts of potential market
changes, rather than only focusing on Avista’s PRS. In past IRPs, Avista has studied
the market impacts of electric cars and the addition of large amounts of solar generation
to the grid. For this IRP, the non-PRS study focuses on the growing penetration of wind
generation in the Northwest. 2015 was chosen as the period for this study and includes
four sensitivities; the sensitivity included 100 iterations of potential outcomes.

The sensitivities in this case range from 7,000 MW to 17,000 MW (additions of between
zero MW and 10,000 MW to the Expected Case wind penetration forecast) of total wind
capacity in the Northwest. Currently, there is approximately 5,000 MW in the four
northwest states and the Expected Case includes approximately 7,000 MW of wind by
2015. The key results of this study include the change in market prices, the amount of
negative price episodes, and the overall effect of additional wind generation on the
margins of existing Avista facilities.

The first major change to the power market by high wind penetration is the change to
wholesale market prices. Based on the average of the 100 iterations of each case,
Figure 7.28 illustrates the percent change to Mid-Columbia average monthly prices in
cases that increase wind capacity by 2,000, 5,000, and 10,000 MW above the Expected
Case forecast. The major price changes occur in the second quarter of the year. On
average, market price changes are 2 percent lower than the Expected Case with 2,000
MW of additional wind by 2015, 7 percent lower with 5,000 MW, and 11 percent lower
with 10,000 MW.

Figure 7.28: Wind Sensitivity Mid-Columbia Price Changes

-45%
-40%
-35%
-30%
-25%
-20%
-15%
-10%
-5%
0%
Ja
n
Fe
b
Ma
r
Ap
r
Ma
y
Ju
n
Ju
l
Au
g
Se
p
Oc
t
No
v
De
c
An
n
u
a
l
pe
r
c
e
n
t

c
h
a
n
g
e
+ 2,000 MW
+ 5,000 MW
+ 10,000 MW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 164 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-36
The reduction in overall wholesale prices comes substantially from negative prices.
Negative pricing can occur when resources must operate irrespective of the price
offered in the wholesale marketplace, and when a resource receives economic benefit
for generation beyond market prices (tax credits and RECs). In some markets negative
prices occur when certain base-load generation resources (e.g., nuclear plants) in total
exceed nighttime loads but must be operated to ensure their availability during the next
day’s peak demand periods. Negative pricing is an issue today in the Northwest when
the region’s hydroelectric system is experiencing high flow condition (generally during
spring runoff) and when there is no wind generation curtailment.

Many hydroelectric facilities must generate electricity and not spill water under varying
licensing requirements. This situation compounds when generation resources, such as
wind, receive federal production tax and renewable energy credits. Wind facilities in the
Expected Case contribute to 193 hours of negative prices, or 2.2 percent of the hours,
as shown in Figure 7.29. With 2,000 MW of additional wind capacity, the frequency of
negative pricing increases to 3.2 percent. With 5,000 MW, prices fall by 6.1 percent.
And with 10,000 MW, prices fall by 9.7 percent.

Figure 7.29: Wind Sensitivity Negative Pricing
The final item reviewed as part of this high wind penetration study is the effect to the
profitability of non-wind and hydro resources and total power supply costs. Figure 7.30
shows that Avista’s coal-fired, combined cycle natural gas-fired, and hydroelectric
revenues decline, but that the value of gas-fired peaking resources will increase. The
estimated impact of increased wind penetration to Avista net power supply cost is a net
increase between 0.03 percent and 0.37 percent.

-
200
400
600
800
1,000
1,200
1,400
1,600
Expected Case + 2,000 MW + 5,000 MW + 10,000 MW
nu
m
b
e
r

o
f

h
o
u
r
s
10th percentile
Avg
Median
90th percentile
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 165 of 1069
Chapter 7- Market Analysis
Avista Corp 2011 Electric IRP 7-37
Figure 7.30: Change to Resource Revenues

Market Analysis Summary
Market analysis is a key component of the IRP. The market is where Avista trades its
electricity surpluses and deficits. It is difficult to examine all potential resources
evaluated by Avista for possible inclusion in the PRS without a firm understanding of the
marketplace and how public policy and changes to resource and cost assumptions
affect the market. As prices have declined since the 2009 IRP, and have the potential to
fall farther, the market price forecasts could have an effect on the cost to bring new
resources on to the Avista system and their potential rate effects.

New legislation and regulations affecting the electric system are on the horizon.
Regardless of policies to decrease greenhouse gas emissions, make generation
greener, promote energy independence or affect reliability—power costs will increase
because new capacity and transmission resources are needed to replace aging
infrastructure and serve new load growth. Greenhouse gas emissions and RPS
legislation will diversify fuel supplies, but will also increase demand for natural gas-fired
resources. Policymakers and the public will need to determine if the ultimate benefits of
these types of legislation outweigh the increased costs.

-40%
-20%
0%
20%
40%
60%
80%
100%
120%
Hydro
Portfolio
Colstrip Coyote
Springs 2
Boulder Park Rathdrum CT
pe
r
c
e
n
t

c
h
a
n
g
e
+ 2,000 MW
+ 5,000 MW
+ 10,000 MW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 166 of 1069

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 167 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-1

8. Preferred Resource Strategy

Introduction
The Preferred Resource Strategy (PRS) chapter describes potential costs and financial
risks of the Company’s resource acquisition strategy. It details the planning and
resource decision methodologies, describes strategy, considers climate change policy,
and shows how the strategy may evolve if certain expected future conditions change.

The 2011 PRS describes a reasonable low-cost plan along the efficient frontier of
potential resource portfolios accounting for fuel supply risk, price risk, and greenhouse
gas mitigation. Major changes from the 2009 plan include reduced amounts of wind
generation and the introduction of natural gas-fired peaking resources. The plan
includes less wind because of lower expected retail loads resulting from the present
economic downturn and increased conservation acquisition. Expected wind generation
needs are lower due to a modest change in the modeling method used to represent
annual variability from RPS-qualifying resources. The selection of gas-fired peaking
resources resulted from a lower natural gas price forecast, lower retail loads, and the
need for more flexible generation resources to manage the variability associated with
renewable generation.

Supply-Side Resource Acquisitions
Avista began its shift away from coal-fired resources with the sale of its 210 MW share
of the Centralia coal plant in 2001 and its replacement with natural gas-fired projects
(see Figure 8.1). After the Centralia sale, Avista acquired 32 MW of gas-fired peaking
capacity and 287 MW of intermediate load gas-fired capacity. In addition, Avista
contracted for 35 MW of wind capacity from the Stateline Wind Project and added 42
MW of new capacity to its hydroelectric fleet through project upgrades. Avista gained
control of the output for the 270 MW Lancaster Generating Facility through a long-term
Section Highlights
A newly signed contract for the Palouse Wind project located near Spokane,
Washington will fulfill Avista’s RPS obligations through 2019.
Avista’s first load-driven acquisition is a gas-fired peaking plant in 2019; total
gas-fired acquisition is 756 MW over the IRP timeframe.
The 2011 plan splits natural gas-fired generation between simple- and
combined-cycle plants in anticipation of a growing need for system flexibility to
integrate variable resources.
Efficiency improvements, both on the customer and utility sides of the meter,
are at the highest expected level in our planning history.
Total capital needs for generation resources in the PRS are $1.7 billion.
Conservation and system efficiency spending will increase over time; a total of
$1.4 billion will acquire 310 aMW over 20 years.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 168 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-2

tolling arrangement on January 1, 2010. The Company plans to upgrade its Nine Mile
Falls project. The upgrade could involve replacement with in-kind equipment or a new
powerhouse. Avista plans to complete the last turbine runner upgrade at Noxon Rapids
in 2012, adding seven MW (1 aMW) to the project’s capability.

Figure 8.1: Resource Acquisition History

Resource Selection Process
Avista uses several decision support systems to develop its resource strategy. The PRS
relies on results from the PRiSM model whose objective function is to meet resource
deficits while accounting for overall cost, risk, renewable energy requirements, and
other constraints. The AURORAxmp model, discussed in detail in the Market Analysis
chapter, calculates the operating margin (value) of every resource option considered in
each of 500 potential future outcomes. PRiSM evaluates resource values by combining
operating margins with capital and fixed operating costs. From an efficient frontier,
Avista selects a resource mix meeting all capacity, energy, RPS, and other
requirements.

PRiSM
Avista staff developed the PRiSM model in 2002 to support PRS selection. PRiSM uses
a linear programming routine to support complex decision making with multiple
objectives. Linear programming tools provide optimal values for variables, given system
constraints.

1,100
1,300
1,500
1,700
1,900
2,100
2,300
2,500
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
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0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
me
g
a
w
a
t
t

c
a
p
a
c
i
t
y
Ra
t
h
d
r
u
m
Ce
n
t
r
a
l
i
a

S
a
l
e
BP

&

K
F
C
T
1/
2

C
S
2
St
a
t
e
l
i
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e
Hydro Upgrades
La
n
c
a
s
t
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r
1/
2

C
S
2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 169 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-3

Overview of the PRiSM Model
The PRiSM model requires a number of inputs:
1. Expected Future Deficiencies
o Summer 18-hour capacity
o Winter 18-hour capacity
o Annual energy
o I-937 RPS Requirements
2. Costs to Serve Future Retail Loads
3. Existing Resource Contributions
o Operating margins
o Carbon emission levels
4. Resource Options
o Fixed operating costs
o Return on capital
o Interest expense
o Taxes
o Generation levels
o Emission levels
5. Limitations
o Market reliance (surplus/deficit limits on energy, capacity and RPS)
o Resources available to meet future deficits
o Resource retirement limits (function disabled for 2011 IRP)
o Capital expenditure limits (function disabled for 2011 IRP)
o Emission levels (function disabled for 2011 IRP)

PRiSM uses these inputs to develop an optimal resource mix over time at varying levels
of cost and resultant risk levels. It weights the first decade more heavily than the later
years to highlight the importance of near-term decisions. A simplified view of the PRiSM
linear programming objective function is below.

PRiSM Objective Function

Minimize: (X1 * NPV2012-2022) + (X2 * NPV2012-2031) + (X3 * NPV2012-2061)

Where: X1 = Weight of net costs over the first 10 years (75 percent)
X2 = Weight of net costs over 20 years of the plan (20 percent)
X3 = Weight of net costs over the next 50 years (5 percent)
NPV is the net present value of total cost (existing resource marginal
costs, all future resource fixed and variable costs, and all future
conservation costs and the net short-term market sales/purchases).

An efficient frontier captures the optimal mix of resources, given varying levels of cost
and risk. Figure 8.2 illustrates the efficient frontier concept. The optimal point on the
efficient frontier curve depends on the level of risk Avista and its customers are willing to
accept. Environmental legislation, cost, regulation, and the availability of commercially
ready technologies greatly limit utility-scale resource options. The model does not meet
deficits with market purchases, or allow the construction of resources in any increment
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 170 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-4

needed.1 Instead, the model uses market purchases to fill short-term gaps and
constructs resources in block sizes equal to the actual project capacities.

Figure 8.2: Conceptual Efficient Frontier Curve

Constraints
As discussed earlier in this chapter, reflecting real-world constraints in the model is
necessary to create a realistic representation of the future. Some constraints are
physical and others are societal. The major resource constraints are capacity and
energy needs, Washington’s RPS, and the greenhouse gas emissions performance
standard.

The PRiSM model is limited to choosing resources by type and by size. It can select
from combined- and simple-cycle natural gas-fired combustion turbines, wind, and
upgrades to existing thermal resources, and conservation. Sequestered and non-
sequestered coal plants are not an option in this IRP because of Washington’s
emissions performance standard. Detailed hydroelectric upgrade potentials were not
available during PRS development and are not included as resource options.

Washington’s RPS fundamentally changed how the Company meets future loads.
Before the addition of an RPS obligation, the efficient frontier contained a least-cost
strategy on one axis and the least-risk strategy on the other axis, and all of the points in
between. Next, management used the efficient frontier to determine where they wanted
to be on the cost-risk continuum. The least cost strategy typically consisted of gas-fired
1 Market reliance, as identified in Section 2, is determined prior to PRiSM’s optimization.
cost
ri
s
k
Least Cost
Least Risk
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 171 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-5

peaking resources. Portfolios with less risk generally replaced some of the gas-fired
peaking resources with wind generation, other renewables, combined cycle gas-fired
plants, or coal-fired resources. Past IRPs identified resource strategies that included all
of these risk-reducing resources.

Added environmental and legislative constraints greatly reduce the ability to reduce
future costs and/or risks and require the procurement of renewable generation
resources that previously were included for risk-mitigation. Because significant levels of
renewable generation are required under Washington law, the 2011 IRP strategy simply
complies with environmental and legislative constraints.

Resource Deficiencies
Avista no longer uses a one-hour peak planning methodology, instead using the peak
planning methodology recommended by the Northwest Power and Conservation
Council – three-day, 18-hour (6 hours each day) peak events occurring both in the
summer and winter. This method better emulates the Northwest and Avista’s actual
ability to meet short-term peak events with hydroelectric facilities. Avista accounts for
the regional view of surplus power and includes a pro-rata share of regional surpluses
when available. Finally, the peak planning methodology includes other operating
reserves and a planning margin.

Even with the new peak planning methodology, Avista currently projects having
adequate resources between owned and contractually controlled generation to meet
annual physical energy and capacity needs until 2016.2 See Figure 8.3 for Avista’s
physical resource positions for annual energy, summer capacity, and winter capacity.
This figure accounts for the effects of new energy efficiency programs on the load
forecast. Absent energy efficiency, our resource position would be deficient earlier. The
first capacity deficit is short-lived because a 150 MW capacity sale contract ends in
2016. Avista likely will address the 2016 capacity deficit with market purchases as 2016
approaches; therefore, the first long-term capacity deficit begins in the summer of 2019.

Avista’s resource portfolio has 281 MW of natural gas-fired peaking plants available to
serve winter loads and 201 MW available in the summer. For long-term planning, these
resources are available to generate energy at their full capabilities. Operationally, less
expensive wholesale marketplace purchases may displace Avista’s available resources.
On an annual average basis, our loads and resources fall out of balance in 2020 for
energy; the first quarterly energy deficit is in the first quarter of 2013.

PRiSM selects new resources to fill capacity and energy deficits, although the model
may over- or under-build where economics support it. Because of acquisitions driven by
capacity RPS compliance, large energy surpluses result. See Figure 8.3.

2 See Chapter 2 for further details on this peak planning methodology.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 172 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-6

Figure 8.3: Physical Resource Positions (Includes Conservation)

Renewable Portfolio Standards
Washington voters approved the Energy Independence Act through Initiative 937 (I-937)
in the November 2006 general election. I-937 requires utilities with over 25,000
customers to meet three percent of retail load from qualified renewable resources by
2012, nine percent by 2016, and 15 percent by 2020. The initiative also requires utilities
to acquire all cost-effective conservation and energy efficiency measures. The
Company has been participating in the UTC’s Renewable Portfolio Standard Workgroup
at the Washington Commission.

Avista expects to meet or exceed its renewable energy requirements between 2012 and
2015 through a combination of qualifying hydroelectric upgrades, the Palouse Wind
project, and a REC purchase. Projected REC positions are in Figure 8.43. I-937 includes
the flexibility to use RECs from the current year, from the previous year, or from the
following year for compliance. REC contingency reserves will be “banked” each year to
account for compliance variability driven by loads and hydroelectric and wind generation
variation. Projected requirements and new resources used to meet future RPS
obligations are in Table 8.31.

3 Figure 8.4 does not show the expected RECs from the Palouse Wind contract, which was signed after
the modeling for the 2011 was completed.
-1000
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/

a
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e
r
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Winter Capacity
Summer Capacity
Energy
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 173 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-7

Figure 8.4: REC Requirements vs. Qualifying RECs for Washington State RPS

Preferred Resource Strategy
The 2011 PRS consists of existing thermal resource upgrades, wind, conservation, and
natural gas-fired simple and combined cycle gas turbines. The first resource acquisition
is approximately 42 aMW of wind by the end of 2012 to take advantage of federal tax
incentives.4

Avista will rebuild distribution feeders over the next twenty years. The PRS includes 27
MW of peak capacity savings and 13 aMW of energy savings from smart grid and
distribution feeder initiatives. More discussion on this topic is included in the distribution
upgrades section of the Transmission and Distribution chapter.

The PRiSM model selected an 83 MW simple cycle combustion turbine as its first large
capacity addition by the end of 2018. Another 83 MW simple cycle combustion turbine
follows by the end of 2020. Also in the 2018 to 20 period, existing thermal unit upgrades
add 4 MW of capacity. The PRS adds 43 aMW of additional wind by the end of 2019-20
to meet the 15 percent renewable energy goal.

The PRS includes a 270 MW natural gas-fired combined-cycle combustion turbine
(CCCT) in 2023, and another 270 MW CCCT in 2026, to meet projected capacity
deficits created by the expiration of the Lancaster tolling agreement. Following this need
is a 46 MW simple cycle turbine. In total, the PRS adds 1,024 MW of new generation
capacity by the end of the IRP forecast. Table 8.1 presents the 2011 PRS resource
types, timing and sizes.

4 Avista met this requirement through a 2011 RFP process that selected the Palouse Wind Project.
0
20
40
60
80
100
120
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1
2
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3
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4
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1
5
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1
6
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7
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8
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9
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2
1
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2
2
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3
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4
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5
20
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6
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3
0
20
3
1
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Qualifying Resources Budgeted Resources Purchased RECs Used Bank Requirement
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 174 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-8

Table 8.1: 2011 Preferred Resource Strategy

Resource By the
End of
Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 120 35
SCCT 2018 83 75
Existing Thermal Resource Upgrades 2019 4 3
NW Wind 2019-2020 120 35
SCCT 2020 83 75
CCCT 2023 270 237
CCCT 2026 270 237
SCCT 2029 46 42
Total 996 739
Efficiency Improvements By the
End of
Year
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2012-2031 28 13
Energy Efficiency 2012-2031 419 310
Total 447 323

Table 8.2 shows the 2009 Preferred Resource Strategy. The major differences in the
2011 plan are a reduction in the quantity of wind resources and a switch to a
combination of simple and combined cycle resources from only combined cycle gas-
fired resources.

Table 8.2: 2009 Preferred Resource Strategy

Resource By the
End of
Year
Nameplate
(MW)
Energy
(aMW)
Northwest Wind 2012 150 48
Little Falls Unit Upgrades 2013-2016 3 1
Northwest Wind 2019 150 50
Combined-Cycle Combustion Turbine 2019 250 225
Upper Falls 2020 2 1
Northwest Wind 2022 50 17
Combined-Cycle Combustion Turbine 2024 250 225
Combined-Cycle Combustion Turbine 2027 250 225
Total 1,105 792
Efficiency Improvements By the
End of
Year
Peak
Reduction
(MW)
Energy
(aMW)
Distribution Efficiencies 2010-2015 5 3
Energy Efficiency 2010-2029 339 226
Total 344 229

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 175 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-9

Energy Efficiency
Energy efficiency is an integral part of the PRS analytical process. Energy efficiency is
also a critical component of I-937, where utilities are required to obtain all cost effective
conservation. Avista developed avoided energy costs and compared those figures
against a conservation supply curve developed by Global Energy Partners. The 20-year
forecast of energy efficiency acquisitions is in Figure 8.5. Avista plans to acquire 133
aMW of energy efficiency over the next 10 years and 310 aMW over 20 years. These
acquisitions will reduce system peak, shaving 207 MW from by 2022, and 419 MW in
2031. Please refer to Chapter 3 for a more detailed discussion of energy efficiency
resources.

Figure 8.5: Energy Efficiency Annual Expected Acquisition

Palouse Wind
On February 22, 2011, Avista issued a request for proposals (RFP) for I-937-qualifying
renewable energy. Following the RFP, Avista selected the Palouse Wind project located
between Rosalia and Oakesdale, Washington. The project will have a maximum
capability of approximately 100 MW and an expected annual average energy output of
40 aMW. The contract is a 30-year power purchase agreement with a purchase option
after year 10. The project should be on-line in the second half of 2012. This new
resource is not included in the PRS as it was under contract negotiation during the
development of this plan, this resource meets the PRS Northwest Wind resource need
in 2012.

Reardan Wind Project
Avista purchased development rights for a wind site located in its service territory near
Reardan, Washington, from Energy Northwest in 2008. The fully permitted site has
several years of meteorological data and is ready for construction. This wind site is
0
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Annual
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 176 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-10

competitive to higher capacity factor sites, as the project does not require any third-
party transmission and is located near Avista work crews.5 This site could supply
between 50 MW and 100 MW of wind generation. With the acquisition of the Palouse
Wind project, development at Reardan is not likely prior to 2018-19.

Little Falls Hydro Upgrades
The 2009 PRS included 0.9 aMW of incremental energy from upgrades to the Little
Falls project between 2013 and 2016. When preparing this plan, Avista expected in-kind
turbine replacements and no incremental energy. Additional study and modeling
identified up to three aMW of incremental energy that will qualify for Washington’s
Energy Independence Act. Final decisions about the upgrades are still pending.
Analysis around this option continues and an update will be in the 2013 IRP.

Distribution Feeder Upgrades
Distribution feeder upgrades were in the PRS for the first time in the 2009 IRP. The
feeder upgrade process began with an upgrade to the Ninth & Central Streets feeder in
Spokane. The decision to rebuild a feeder considers energy savings, operation and
maintenance savings, the age of existing equipment, reliability indexes, and the number
of customers on the feeder. Based on analyses performed for this IRP, Avista likely will
rebuild many of its distribution feeders, limited to five or six per year due to financial and
staffing limitations. Feeder rebuild projects will begin in 2012 or 2013 and the Company
will allocate resources after prioritizing the projects. Savings are subject to change after
further detailed cost analyses and rebuild schedules are completed and more
information is provided in Chapter 5.

Simple Cycle Combustion Turbines
Avista plans to identify potential sites for new gas-fired generation capacity within its
service territory ahead of an anticipated 2019 need. Avista’s service territory has areas
with different combinations of benefits and costs. Locations in Washington would have
higher generation costs because of natural gas fuel taxes and carbon mitigation fees.
However, the potential benefits of a Washington location, including proximity to natural
gas pipelines and Avista’s transmission system; lower project elevations that provide
higher on-peak capacity contributions per investment dollar; and water to cool the
facility, might outweigh the costs. In Idaho, lower taxes and fees decrease the cost of a
potential facility, but there are fewer locations to site a facility near natural gas pipelines,
fewer low cost transmission interconnections, and fewer sites with adequate cooling
water. The identification and procurement of a natural gas project site option is an
Action Item for this IRP.

Loads and Resources Positions
Conservation acquisitions identified in this IRP reduce the load forecast, as shown in
Figure 8.6. The red line illustrates the Company’s load obligation absent energy
efficiency programs. Absent conservation, Avista would need new resources in 2018
rather than 2020.
5 Higher capacity factor wind sites are generally located outside of Avista’s service territory.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 177 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-11

Figure 8.6: Annual Average Load and Resource Balance

The first winter peak deficit without the conservation resource would occur in 2020, but
the deficit does not occur until 2022 with the acquisition of new energy efficiency
measures (see Figure 8.7). Avista expects to have modest short-term resource deficits
prior to 2022 and intends to meet these deficiencies with market purchases rather than
acquiring a resource prior to a sustained need. An analysis of regional loads and
resources support the Company’s position that existing regional capacity should be
available to support a robust short-term wholesale market in the timeframe required. A
capacity resource could replace market purchases, without a significant impact on the
long-term portfolio cost, if conditions change and the Company determines that it cannot
depend on the regional market surplus during this period.

The summer peak load and resource position shows a capacity need prior to the first
winter need. Avista’s peak loads are lower in summer than in the winter, but the impacts
on hydroelectric and thermal generation capacity in the summer, due to lower flow
conditions and high temperatures, are greater than the load differences. As shown in
Figure 8.8, summer resource deficits occur in 2013 without conservation and in 2016
(short-term) and 2019 (long-term) with conservation measures. The Company plans to
fill the short-term summer capacity deficit in 2016 with market purchases. Beginning in
2022, summer deficits no longer drive Avista’s capacity needs due to the expiration of
the WNP-3 contract in 2019.

-
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New Simple Cycle CC
New Combined Cycle CC
Distribution Efficiency
Other
New Wind
Existing Resources
Load w/o DSM + Cont.
Load w DSM + Cont.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 178 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-12

Figure 8.7: Winter Peak Load and Resource Balance

Figure 8.8: Summer Peak Load and Resource Balance

Under Washington regulation (WAC 480-107-15), utilities having generation capacity
deficits within three years of an IRP filing must also file a proposed Request for
Proposals (RFP) with the Washington Utilities and Transportation Commission (UTC).
The RFP is due to the UTC no later than 135 days after the IRP filing. After UTC
approval, bids to meet the anticipated capacity shortfall must be solicited within 30 days.

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New Simple Cycle CC New Combined Cycle CC
Distribution Efficiency Other
New Wind Market
Existing Resources Load w/o DSM + Cont.
Load w DSM + Cont.
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New Simple Cycle CC New Combined Cycle CC
Distribution Efficiency Other
New Wind Market
Existing Resources Load w/o DSM + Cont.
Load w DSM + Cont.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 179 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-13

Tables 8.28 and 8.29, shown later in this section, detail Avista’s capacity position over
the IRP timeframe. With a portion of loads met by Avista’s share of the regional capacity
surplus, Avista does not require winter capacity until 2022. A summer capacity
deficiency does not occur until 2016. Simplified summaries are below in Tables 8.3 and
8.4. They show Avista does not require capacity in the next three years; therefore an
RFP is not required under WAC 480-107-15.

Table 8.3: Avista Medium-Term Winter Capacity Tabulation

2012 2013 2014
Load Obligations 1,890 1,912 1,892
Reserves Planning 371 356 358
Total Obligations 2,261 2,268 2,250

Utility Resources 2,192 2,267 2,277
NW Market Share 737 656 565
Total Resources 2,929 2,923 2,842

Net Position 668 655 592

Table 8.4: Avista Medium-Term Summer Capacity Tabulation

2012 2013 2014
Load Obligations 1,743 1,756 1,785
Reserves Planning 227 322 238
Total Obligations 1,970 2,078 2,023

Utility Resources 1,960 1,880 1,962
NW Market Availability 275 221 178
Total Resources 2,235 2,101 2,140

Net Position 265 23 117

Greenhouse Gas Emissions
The Market Analysis chapter discusses how greenhouse gas emissions from electric
generation in the Western Interconnect decrease due to the addition of carbon emission
penalties. Avista’s greenhouse gas emissions should fall because of anticipated carbon
reduction policies. Greenhouse gas policies will affect higher-cost coal facilities before
affecting low operating cost facilities, such as Colstrip. New or underutilized natural gas-
fired resources located closer to west coast load centers will replace the coal-fired
facilities. Figure 8.9 presents expected greenhouse gas emissions with the addition of
PRS resources. Overall Company greenhouse gas emissions should fall starting in
2020 as Colstrip output decreases and natural gas-fired generation increases. The 2024
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 180 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-14

increase in emissions shown in Figure 8.9 comes from a new CCCT resource. These
emission estimates do not include emissions produced from purchased power or
include a reduction in emissions for off-system sales. The Company expects its
greenhouse gas emissions intensity from owned and controlled generation to fall from
0.36 short tons per MWh to 0.24 short tons per MWh with the current resource mix and
the generation identified in the PRS6.

Figure 8.9: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
Greenhouse gas policy has a clear impact on Avista’s future resource mix. Absent
carbon policy, cumulative greenhouse gas emissions over the 20-year IRP timeframe
would be 18 percent higher, with the difference growing each year of the forecast. By
2031, annual emissions would be 29 percent higher without carbon mitigation. The gray
area illustrates these differences in Figure 8.9.

Efficient Frontier Analysis
Efficient frontier analysis is the backbone of the Preferred Resource Strategy. PRiSM
helps develop the efficient frontier by simulating the costs and risks of several different
resource portfolios. The analysis illustrates the relative performance of potential
portfolios to each other on a cost and risk basis. Thought of a different way, the curve
represents the least-cost strategy at each risk level. The PRS analyses examined the
following portfolios, as detailed here and in Figure 8.10:

 Market Only: All resource deficits met with spot market purchases.
 Capacity Only: Only capacity deficits met with new resources. Energy and RPS
requirements ignored.

6 Greenhouse gas emissions are not included for the Kettle Falls plant because biomass is a carbon
neutral resource.
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GHG Reduction due to Legislation
New Resources
Existing Resources
Tons per MWh of Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 181 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-15

 Least Cost: All capacity, energy and RPS requirements met with new least-cost
resources. This portfolio ignores power supply expense volatility in favor of
lowest cost resources.
 Least Risk: All capacity, energy and RPS requirements met with least-risk
resources. This portfolio ignores the overall cost of the selected portfolio in favor
of minimizing risk.
 Efficient Frontier: All capacity, energy and RPS requirements met with sets of
intermediate portfolios between the least risk and least cost options.
 Preferred Resource Strategy: All capacity, energy and RPS requirements met
while recognizing both the overall cost and risk inherent in the portfolio.

Figure 8.10 presents the Efficient Frontier. The x-axis is the levelized nominal cost per
year for power supply costs and the y-axis is the levelized standard deviation of power
supply costs.

Figure 8.10: Expected Case Efficient Frontier

The Market Only portfolio is least cost from a long-term financial perspective, but it has
the highest level of risk. The strategy fails to meet capacity, energy, and RPS
requirements with Company-controlled assets.

The Capacity Only strategy meets capacity requirements by adding gas-fired peaking
plants, but wholesale market purchases displace them in most hours. This strategy
$60
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$450 $500 $550 $600 $650 $700
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 182 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-16

does not meet RPS requirements and does not decrease power supply cost volatility,
except at the tail of the distribution. The Least Cost strategy meets capacity, energy and
RPS requirements at the lowest possible cost by adding gas-fired peaking plants and
minimum levels of wind generation to meet Washington State RPS requirements. The
Least Risk strategy substantially replaces gas-fired peaking plants with gas-fired
combined-cycle combustion turbines, increases the quantity of wind resources, and
adds solar resources to the mix.

All portfolios along the efficient frontier are the least cost portfolio for a given level of risk
and portfolio constraints. The decision to select a particular portfolio along the efficient
frontier curve focuses on volatility reductions gained by spending more capital. Avista
management determines the ultimate selection of the PRS over other potential resource
strategies in an effort to balance overall long-term customer costs with the risks of year-
over-year expense variability. The PRS includes 1.2 percent more costs on average and
4.5 percent less volatility compared to the Least Cost portfolio.

Avoided Costs
The efficient frontier methodology can determine the avoided cost of new resource
additions. There are two avoided cost calculations for this IRP; one for energy efficiency
and one for new generation resources.

Avoided Cost of Conservation
Three portfolios are required to estimate the supply-side cost components necessary to
estimate the avoided cost for conservation. The differences between each portfolio sum
to the avoided cost of conservation:

 Market Only: This resource portfolio includes no new resource additions and the
incremental cost of new power supply is the cost to buy power from the short-
term market. The price difference between the Expected Case and the
Unconstrained Carbon scenario is the greenhouse gas policy cost.
 Capacity Only: This resource portfolio builds new resource capacity to meet
resource deficits to meet peak load. The difference between the Market Only and
Capacity Only strategies equals the capacity value of the new resources. This
estimate typically shows the incremental cost divided by the incremental kilowatts
of installed capacity. For this example the $/kW adder is translated to $/MWh
assuming a flat energy delivery.
 Pre-Preferred Resource Strategy: This resource portfolio is similar to the PRS
resource mix assuming the Company does not pursue the conservation
resource.

Table 8.5 shows the 20-year levelized avoided cost of conservation. The avoided cost
for conservation includes value only for those periods realizing avoided costs. For
example, the avoided costs of conservation programs only include a capacity value in
the years where the Company is short capacity. Further, the market component (Energy
Forecast) applies to each conservation program depending upon the timing of energy
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 183 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-17

delivery. For example, an air conditioning program receives an energy value depending
upon prices in the summer months when actual energy savings occur.

Table 8.5: Nominal Levelized Avoided Costs ($/MWh)

2012-2031
Energy Forecast 52.86
Carbon Adder Forecast 17.64
Capacity Value 10.51
Risk Premium 7.38
Total 88.39

I-937 requires that the avoided costs used for conservation include additional items
beyond the actual cost of avoided energy and capacity. Avoided costs increase by 10
percent to bias the IRP toward a preference for conservation. Additionally, reduced
transmission and distribution losses, and operations and maintenance are also
included. The following formula identifies the costs included in the avoided cost for
energy efficiency measures.

{(E + PC + R) * (1 + P)} * (1 + L) + DC * (1 + L)

Where:
E = Market energy price. The price calculated with AURORAxmp is $70.50
per MWh and includes projected greenhouse gas costs.
PC = New resource capacity savings. This value is calculated using
PRiSM and is estimated to be $10.51 per MWh.
R = Risk premium to account for RPS and rate volatility reductions. This
PRiSM-calculated value is $7.38 per MWh.
P = Power Act preference premium. This is the additional 10 percent
premium given as a preference towards energy efficiency measures.
L = Transmission and distribution losses. This component is 6.1 percent
based on Avista’s estimated system average losses.
DC = Distribution capacity savings. This value is approximately $10/kW-
year or $1.14 per MWh.

The following calculation shows the estimated levelized avoided cost for a theoretical
conservation program that reduces load by one megawatt each hour of the year:

{[(52.86 + 17.64 + 10.51 + 7.38) * (1 + 10%)] * (1 + 6.1%) + [1.14 * (1 + 6.1%)]}
= $104.37 per MWh

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 184 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-18

Preferred Resource Strategy Avoided Costs
An avoided cost calculation for supply-side resources is developed using conservation
avoided cost estimates and methods, and final PRS data. However, the avoided cost
values for generation resources represent a portfolio including conservation measures
and excluding greenhouse gas emission adders.7 The risk component of the avoided
cost includes renewable energy credits and the difference in cost between combined
and simple cycle CTs to reduce Avista’s market risk. See Table 8.6 for the prices per
MWh. The 20-year levelized cost equates to $84.64 per MWh.

Table 8.6: Preferred Resource Strategy Avoided Cost ($/MWh)

Year Energy Capacity Risk Total
2012 41.19 0.00 0.00 41.19
2013 46.58 0.00 15.20 61.78
2014 49.73 0.00 16.21 65.93
2015 46.76 0.00 17.28 64.04
2016 48.20 0.00 18.42 66.62
2017 51.15 0.00 19.64 70.79
2018 52.91 0.00 20.94 73.85
2019 52.97 16.16 22.33 91.46
2020 53.25 17.52 23.81 94.58
2021 54.45 17.00 25.39 96.83
2022 56.15 16.71 27.07 99.93
2023 57.82 17.18 28.86 103.86
2024 56.89 17.24 30.77 104.90
2025 56.80 17.16 32.81 106.77
2026 58.82 17.42 34.98 111.23
2027 60.36 17.72 37.30 115.38
2028 63.08 18.86 39.77 121.71
2029 64.51 18.54 42.41 125.45
2030 66.29 18.21 45.21 129.71
2031 68.89 17.70 48.21 134.79

New Resource Avoided Costs
Avoided costs are updated as new information becomes available, including changes to
market prices, loads and resources. As such, Table 8.7 represents avoided costs after
the acquisition of the Palouse Wind project. The updated avoided cost schedule is
significantly lower than the preliminary value due substantially to the elimination of the
risk premium. The risk premium is not included in the updated avoided cost table for
three reasons. First, the largest component of the risk premium is the value of meeting
environmental mandates. The risk premium reflects those resources meeting
Washington state renewable performance standard, but there is no guarantee that a
new resource will meet the requirements. Further, Avista’s regulatory commissions have

7 No further greenhouse gas mitigation policies beyond current state and federal regulations are included.
As such, the resource avoided cost calculation does not include this adder. Only when state or federally
imposed greenhouse gas costs are assessed on electric generation will the carbon adder be included in
avoided costs.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 185 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-19

not ruled that environmental benefits (i.e., renewable energy credits) from Public Utility
Regulatory Policy Act of 1978 (PURPA) resources are owned by the purchasing utility.
Similarly, the remaining portion of reduced risk is from the benefits of a combined-cycle
combustion turbine relative to a simple-cycle combustion turbine. As with
environmental attributes, there is no guarantee that a PURPA or other resource will
include this benefit. Quantifying the risk benefits requires resource-specific evaluations
through Avista’s IRP models is part of a negotiated PURPA contract. The updated 20-
year levelized avoided cost is $61.46 per MWh.

Table 8.7: Updated Annual Avoided Costs ($/MWh)

Year Energy Capacity Total
2012 41.19 0.00 41.19
2013 46.58 0.00 46.58
2014 49.73 0.00 49.73
2015 46.76 0.00 46.76
2016 48.20 0.00 48.20
2017 51.15 0.00 51.15
2018 52.91 0.00 52.91
2019 52.97 16.16 69.13
2020 53.25 17.52 70.77
2021 54.45 17.00 71.44
2022 56.15 16.71 72.86
2023 57.82 17.18 75.00
2024 56.89 17.24 74.12
2025 56.80 17.16 73.96
2026 58.82 17.42 76.24
2027 60.36 17.72 78.08
2028 63.08 18.86 81.94
2029 64.51 18.54 83.05
2030 66.29 18.21 84.50
2031 68.89 17.70 86.59

Preferred Resource Strategy
Earlier in this chapter, the PRS and summary levelized costs and risk were illustrated
and compared to portfolios along the efficient frontier. This section provides more detail
about the PRS, the associated financial risks of the PRS, the cost of its resultant
emissions, and an index of resultant power supply expenses.

Capital Spending Requirements
One of the major assumptions in this IRP is that Avista finances and owns all new
resources. Using this assumption, and the resources identified in the PRS, the first
capital addition to rate base is in 2013 for distribution feeder upgrades, followed by
additional capital needs for PRS wind development8. Wind or other generation

8 Avista acquired the Palouse Wind Project through a Purchase Power Agreement and this capital
addition is no longer needed.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 186 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-20

resources acquired via a power purchase agreement may reduce expected PRS capital
spending. Distribution feeder upgrades may begin in 2012 depending upon operational
availability of resources needed for the work, but 2013 will be the first full year of
commercial operations.

The capital cash flows in Table 8.8 include allowance for funds used during construction
(AFUDC) and account for tax incentives and sales taxes. Costs in Table 8.7 are shown
when capital would be placed in rate base, rather than when capital is actually spent.
The present value of the required investment is just over $0.84 billion and the nominal
total capital expense is $1.7 billion over the IRP timeframe.

Table 8.8: PRS Rate Base Additions from Capital Expenditures
(Millions of Dollars)9

Year Investment Year Investment
2012 0 2022 6
2013 243 2023 6
2014 6 2024 448
2015 6 2025 0
2016 6 2026 0
2017 4 2027 461
2018 7 2028 0
2019 77 2029 0
2020 90 2030 74
2021 251 2031 0
2012-21 Total 690 2022-31 Totals 994

Annual Power Supply Expenses and Volatility
The PRS variance analysis tracks fuel, variable O&M, emissions, and market
transaction costs for the existing resource portfolio. These costs are captured for each
of the 500 iterations of the Expected Case risk analysis. In addition to existing portfolio
costs, new resource capital, fuel, O&M, emissions, and other costs are tracked to
provide a range of potential costs to serve future loads. Figure 8.11 shows expected
PRS costs modeled through 2031 as the white circle (Nominal). In 2012, costs are
expected to be $26 per MWh. The 80 percent confidence interval, represented as the
black bar, ranges between $22 and $31 per MWh. The black diamonds in the figure
represent the TailVar 90 risk level, or the average of the top 10 percent of the worst
outcomes; the 2010 TailVar cost is $32 per MWh, or $6 per MWh above the expected
value.

Power supply costs increase with natural gas and greenhouse gas price increases.
Uncertainty increases over time and the confidence interval band expands. The white
boxes in Figure 8.11 represent the cost per MWh without greenhouse gas costs. For
example, in 2020 the average system costs would be 8.8 percent lower without carbon

9 By acquiring a PPA for the Palouse Wind project, the Company forgoes the large capital investment
shown in 2013.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 187 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-21

mitigation. The expected levelized cost for the expected case is $48.59 per MWh and
$43.73 per MWh (10 percent lower) without greenhouse gas costs.

Figure 8.11: Power Supply Expense Range

A common question regarding IRPs is what will be the change to power supply costs
over the time horizon of the plan. Figure 8.12 illustrates expected power supply cost
changes compared to historical power supply costs under the Preferred Resource
Strategy. It shows that power supply costs, on a per-MWh basis have increased 4.1
percent per year over inflation between 2002 and 2010. This 4.1 percent annual growth
rate increase is in Figure 8.12 as a linear black line. By 2021, absent greenhouse gas
emissions costs, power supply costs are expected to be 32 percent higher than 2010,
but up to 41 percent higher with the addition of greenhouse gas emissions costs for an
annual growth rate of 2.6 percent and 3.8 percent respectively.

$0
$20
$40
$60
$80
$100
$120
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
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1
9
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2
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2
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$
p
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M
W
h
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 188 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-22

Figure 8.12: Real Power Supply Expected Rate Growth Index $/MWh (2012 = 100)

Natural Gas Price Risk
The Market Analysis chapter showed the results of high and low natural gas price
forecasts. The PRS includes 752 MW of natural gas-fired resources and exposes
Avista’s customers to increasing levels of natural gas price risk. This section uses
natural gas price forecast scenarios, including changes to expected greenhouse gas
prices, to explain the range of costs resulting from the PRS. Figure 8.13 shows the total
portfolio cost range using different natural gas scenarios compared to the expected cost
of the PRS. The low natural gas price scenario reduces expected costs by 19.5 percent
and the high gas price scenario increases costs by 8.7 percent on a present value
basis. Lower natural gas prices have greater effect on prices than higher prices as the
Using stochastic model results, rather than the deterministic scenarios, illustrates risk
exposure to the wholesale market. The 5th and 95th percentiles reflect variability from
natural gas and other variables. The low natural gas price scenario is reflective of a low
cost future, but the high natural gas price scenario does not reflect the potential cost
excursions that could affect the PRS that is not natural gas price related.

0
20
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200
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(
2
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=

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)
Historical Energy Crisis
Expected Case Forecast Unconstrained Carbon Forecast
Linear (Historical)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 189 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-23

Figure 8.13: Power Supply Cost Sensitivities

Greenhouse Gas Costs
Avista anticipates some form of federal greenhouse gas policy, although the exact
nature, timing and scope are unknown. As described in the Market Analysis chapter,
four potential greenhouse gas policies are modeled to estimate marginal electricity
costs. The estimate of greenhouse gas emission costs depends on the number of free
allowances provided by the government. Figure 8.14 illustrates the range of total annual
greenhouse gas costs as the percent of free credits allocated to Avista are changed.
For example, if no credits are allocated to Avista in 2022, Avista’s cost to serve
customers will be $91 million ($162 million in total) higher than the Expected Case
where 80 percent of the credits are free and mitigation costs $71 million.

A reduction in output from the Colstrip generators, increased natural gas prices and
increased wholesale electricity prices drive most of the greenhouse gas policy cost
increases. In the marketplace, low marginal cost coal-fired plants dispatch less, or even
turn off, and higher marginal cost natural gas-fired resources replaces their output. The
cost of natural gas resources is higher than it would be absent greenhouse gas costs
because of increased demand for gas-fired resources. These additional costs represent
up to 11 percent of total power supply expenses in the Expected Case.

-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
20
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2
20
1
3
20
1
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20
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5th Percentile
95th Percentile
High Gas Price Scenario
Low Gas Price Scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 190 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-24

Figure 8.14: Greenhouse Gas Related Power Supply Expense

Efficient Frontier Comparison of Greenhouse Gas Policies
Three stochastic market studies studied the cost of different greenhouse gas policies: 1)
the Expected Case, 2) Unconstrained Carbon, and 3) Mandatory Coal Retirement.
These three stochastic market forecasts were than assumed to be potential markets in
PRiSM and an efficient frontier for each market future was created, as shown in Figure
8.15. Table 8.9 provides more details about the study results. The PRS portfolio is the
same in the Expected Case and the Unconstrained Carbon Case, but the Mandatory
Coal Retirement Case retires Colstrip Unit 3 in 2023 and Unit 4 in 2026, replacing them
with a CCCT. Colstrip decommissioning costs is not included in figures.

$0
$50
$100
$150
$200
$250
$300
$350
20
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Base Case (Declining 80%)
100% Allocation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 191 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-25

Figure 8.15: Efficient Frontier Comparison

Table 8.9: Preferred Portfolio Cost and Risk Comparison (Millions $)

Expected
Case
Unconstrained
Carbon
Coal
Retirement
2012-2022 Cost NPV 3,094 2,886 2,937
2012-2031 Cost NPV 5,735 5,168 5,458
2022 Expected Cost 636 564 576
2022 Stdev 91 68 71
2022 Stdev/Cost 14% 12% 0
2022 CO2 Emissions (000’s) 2,894 3,498 3,752
2031 CO2 Emissions (000’s) 2,972 4,177 3,560

Portfolio Scenarios
The efficient frontier analysis creates resource portfolios for alternative levels of risk and
cost. Avista’s management selected the PRS to balance costs and risk inherent in our
resource portfolio. The following list of portfolios shows details of alternatives to the
PRS, either along the efficient frontier or “hand-picked” so that the costs of these
choices could be considered. Figure 8.16 illustrates the levelized cost percent change
and the levelized annual standard deviation percent change for each of the portfolios in
comparison to the PRS.

$50
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$60
$65
$70
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$450 $500 $550 $600 $650 $700
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Expected Case Unconstrained CO2 Case Mandatory Coal Retirement Future
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 192 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-26

Figure 8.16: Efficient Frontier Comparison

The Technical Advisory Committee requested Avista to show the efficient frontier and
other portfolios using Tail Var 90 rather than standard deviation as a measure of risk
(Figure 8.17). The TAC wanted to know if we measured risk differently would the
Company draw a different conclusion on its resource choice. The result of this study
shows using Tail Var 90 changes the magnitude of risk as compared to the standard
deviation, but the PRS remains the Company’s best choice. Using Tail Var 90 magnifies
the risk savings of moving from Simple Cycle CTs to Combined Cycle CTs, as the
standard deviation method shows a 5 percent reduction in risk for 2 percent more in
cost, while the Tail Var 90 method shows a 15 percent risk reduction for the same cost
increase.

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annual 20 yr levelized cost percent change as compared to PRS
National RES
125% of AC for DSM
CCCT/Wind/Solar post '20
150%of AC for DSM
No DSM PRS "like"
PRS-but no Wind
Pay75%of AC for DSM
PRS No Appr. RECPRS
Efficient Frontier
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 193 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-27

Figure 8.17: Efficient Frontier Comparison with Tail Var90

The following section describes the resources selected in each of the portfolios
designated in Figure 8.16. Table 8.10 summarizes the PRS.

Table 8.10: Preferred Resource Strategy

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 166 0 46 166 212
CCCT (Nameplate) 0 0 270 270 0 540
Thermal Upgrades 0 4 0 0 4 4
Wind (Energy) 35 36 0 0 71 71
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

-25%
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
25%
-15%-10%-5%0%5%10%15%
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R
S
annual 20 yr levelized cost percent change as compared to PRS
Efficient Frontier
PRS
No DSM PRS "like"
PRS-but no Wind
Pay 75%of AC for DSM 125% of AC for DSM
150%of AC for DSM
CCCT/Wind/Solar post '20
National RES
PRS NoAppr. REC
CCCT/Wind (09 IRP)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 194 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-28

Least Cost Portfolio
The Least Cost portfolio is the PRiSM model’s resulting portfolio that meets capacity,
energy and RPS needs at the least expected cost. This portfolio is a combination of
wind and natural gas-fired SCCT generation. Table 8.11 illustrates the generation
resources added in the Least Cost portfolio.

Table 8.11: Least Cost Portfolio

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 83 249 415 83 747
CCCT (Nameplate) 0 0 0 0 0 0
Thermal Upgrades 0 0 0 0 0 0
Wind (Energy) 35 24 12 0 59 71
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

Least Risk Portfolio
The Least Risk portfolio is the portfolio selected by the PRiSM model meeting all
capacity, energy and RPS needs at the least expected risk. PRiSM measures risk using
levelized annual power supply cost variance. This portfolio is a combination of wind,
solar, natural gas-fired SCCT and CCCT generation resources. Table 8.12 illustrates
the resources added in the Least Risk portfolio.

Table 8.12: Least Risk Portfolio

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 0 3 184 0 187
CCCT (Nameplate) 0 270 270 0 270 540
Thermal Upgrades 0 3 14 0 3 17
Wind (Energy) 61 37 0 0 98 98
Solar (Energy) 25 27 6 6 52 64
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

50/50Cost and Risk Midpoint Portfolio
The 50/50 Cost and Risk Midpoint portfolio is the PRiSM model’s portfolio selection that
meets capacity, energy and RPS needs at the midpoint between the least risk and least
cost resource portfolios. This resource portfolio is a combination of wind, solar and
natural gas-fired SCCT and CCCT generation. Table 8.13 illustrates the resources
added in this portfolio.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 195 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-29

Table 8.13: 50/50 Cost and Risk Midpoint Portfolio

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 83 0 94 83 177
CCCT (Nameplate) 0 0 270 270 0 540
Thermal Upgrades 0 0 4 0 0 4
Wind (Energy) 35 23 23 12 58 93
Solar (Energy) 0 0 0 9 0 9
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

75/25 Cost and Risk Portfolio
The 75/25 Cost and Risk portfolio is the PRiSM model’s portfolio selection that meets
capacity, energy and RPS needs at the midpoint between the least cost portfolio and
the 50/50 portfolio. This portfolio is similar to the PRS with a combination of wind and
natural gas-fired SCCT generation. Table 8.14 illustrates the resources added under the
75/25 Cost and Risk portfolio.

Table 8.14: 75/25 Cost Risk Portfolio

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 83 249 0 83 332
CCCT (Nameplate) 0 0 0 540 0 540
Thermal Upgrades 0 0 0 0 0 0
Wind (Energy) 35 23 12 12 58 82
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

25/75 Cost and Risk Portfolio
The 25/75 Cost Risk portfolio is the PRiSM model’s portfolio selection meeting capacity,
energy and RPS needs at the midpoint between the Least Risk portfolio and the 50/50
Cost and Risk portfolio. The 25/75 Cost and Risk portfolio includes a combination of
wind, solar, and natural gas-fired SCCT and CCCT generation. Table 8.15 illustrates the
resources added in the 25/75 Cost and Risk portfolio.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 196 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-30

Table 8.15: 25/75 Cost Risk Portfolio

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 83 0 0 83 83
CCCT (Nameplate) 0 0 540 270 0 810
Thermal Upgrades 0 0 4 0 0 4
Wind (Energy) 35 23 37 0 58 95
Solar (Energy) 0 0 0 5 0 5
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

PRS without Apprentice Credits
The PRS without Apprentice Credits portfolio represents a resource strategy that
assumes the Company is unable to contract for apprentice labor for new wind resources
and therefore the acquisitions do not qualify for the 20 percent REC credit adder in I-
937. This portfolio is a similar to the PRS, but includes 25 aMW of additional wind
energy. Where wind resources have an average capacity factor of 31 percent, Avista
would need to procure an additional 80 MW of nameplate wind capacity. Table 8.16
illustrates the PRS without Apprenticeship Credits portfolio resource additions.

Table 8.16: PRS without Apprentice Credits

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 166 0 46 166 212
CCCT (Nameplate) 0 0 270 270 0 540
Thermal Upgrades 0 4 0 0 4 4
Wind (Energy) 35 49 12 0 84 96
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

2009 IRP Portfolio
The PRS from the 2009 IRP included 350 MW of wind generation and 750 MW of gas-
fired CCCT generation. The 2009 IRP Portfolio emulates the 2009 PRS with 2011 IRP
adjustments for lower load projections and lower natural gas and market electricity
prices. Table 8.17 illustrates the resource additions under the 2009 IRP Portfolio.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 197 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-31

Table 8.17: 2009 IRP Portfolio

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 0 0 0 0 0
CCCT (Nameplate) 0 270 270 270 270 810
Thermal Upgrades 0 0 0 0 0 0
Wind (Energy) 44 44 15 0 87 102
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

PRS without Wind Portfolio
The PRS without Wind Portfolio illustrates the cost of wind additions to the PRS. This
portfolio is the same as the 2011 PRS, but excludes the qualified renewable generation
required by the Energy Independence Act. Table 8.18 illustrates the resources added
under the PRS without Wind Portfolio.

Table 8.18: PRS without Wind Portfolio

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 166 0 46 166 212
CCCT (Nameplate) 0 0 270 270 0 540
Thermal Upgrades 0 4 0 0 4 4
Wind (Energy) 0 0 0 0 0 0
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

CCCT with Solar after 2015 Portfolio
The CCCT with Solar after 2015 Portfolio illustrates the additional cost of using solar,
rather than wind, to meet Washington’s I-937 requirements. Table 8.19 shows the
resources added under the CCCT with Solar after 2015 Portfolio.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 198 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-32

Table 8.19: CCCT with Solar after 2015 Portfolio

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 0 0 0 0 0
CCCT (Nameplate) 0 0 270 540 0 810
Thermal Upgrades 0 7 3 0 10 10
Wind (Energy) 36 0 0 0 36 36
Solar (Energy) 0 26 7 0 26 33
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

National Renewable Energy Standard Portfolio
There have been several attempts to implement a federal renewable energy standard.
The National Renewable Energy Standard Portfolio illustrates changes to the PRS
needed to meet renewable requirements at the national level. Depending on the
legislation, Avista may be required to secure an additional 106 aMW10 to cover the
Company’s retail loads in the Idaho service territory. The actual level of wind required
under a federal renewable energy standard would depend upon how the legislation
treats our existing renewable resources and how it considers hydroelectric generation.11
The portfolio assumes that hydroelectric netting would be included and that the federal
law would not supersede state law. We did not model a national energy standard, as
proposed by President Obama, because the PRS most likely would meet the standard
because Avista is already subject to Washington’s emission performance standards.
Table 8.20 illustrates the resources added under the National Renewable Energy
Standard portfolio.

Table 8.20: National Renewable Energy Standard

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 166 0 46 166 212
CCCT (Nameplate) 0 0 270 270 0 540
Thermal Upgrades 0 4 0 0 4 4
Wind (Energy) 47 47 35 49 93 177
Solar (Energy) 0 0 0 1 0 1
Conservation (Energy) 57 75 91 87 133 310
Dist. Feeders (Energy) 8 3 2 1 11 13

10 106 aMW is equal to 341 MW of nameplate capacity wind generation at a 31 percent capacity factor. 11 Proposed federal legislation has allowed utilities to “net” hydroelectric generation against retail loads
prior to calculating RPS obligations.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 199 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-33

PRS without Conservation Portfolio
The PRS without Conservation Portfolio illustrates the benefits of conservation. This
portfolio meets capacity, energy and RPS needs in a similar manner as the PRS. Table
8.21 illustrates the resources added under the PRS without Conservation Portfolio.

Table 8.21: PRS without Conservation

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 83 212 83 97 295 475
CCCT (Nameplate) 0 0 270 545 0 815
Thermal Upgrades 7 0 0 3 7 10
Wind (Energy) 35 36 23 0 71 94
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 0 0 0 0 0 0
Dist. Feeders (Energy) 8 3 2 1 11 13

PRS Conservation Avoided Costs 25% Lower Portfolio
The PRS Conservation Avoided Costs 25% Lower Portfolio illustrates resulting changes
to cost and risk if avoided costs for conservation was set at the avoided cost of
generation resources, or if natural gas prices included in this IRP are too high. This
portfolio represents conservation estimates without discretionary adders. Table 8.22
illustrates the resources added under this portfolio.

Table 8.22: PRS Conservation Avoided Costs 25% Lower

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 166 83 0 166 249
CCCT (Nameplate) 0 0 270 270 0 540
Thermal Upgrades 0 0 4 0 0 4
Wind (Energy) 35 24 23 0 59 82
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 54 61 75 76 115 266
Dist. Feeders (Energy) 8 3 2 1 11 13

PRS Conservation Avoided Costs 25% Higher Portfolio
The PRS Conservation Avoided Costs 25% Higher Portfolio illustrates the resource
changes that would occur if Avista spent additional dollars toward the acquisition of
additional conservation. This portfolio represents the added conservation at a spending
level of an additional 25 percent and the resulting offset in supply-side resources. Table
8.23 illustrates the resources added under this portfolio.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 200 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-34

Table 8.23: PRS Conservation Avoided Costs 25% Higher

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 166 83 0 166 415
CCCT (Nameplate) 0 0 0 270 0 270
Thermal Upgrades 0 4 4 0 4 7
Wind (Energy) 35 23 12 0 58 70
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 61 83 95 94 144 334
Dist. Feeders (Energy) 8 3 2 1 11 13

PRS Conservation Avoided Costs 50% Higher Portfolio
The PRS Conservation Avoided Costs 50% Higher Portfolio illustrates the resource
changes that would occur if Avista spent an additional 50 percent on the acquisition of
conservation resources. Table 8.24 illustrates the resources obtained in this portfolio.

Table 8.24: PRS Conservation Avoided Costs 50% Higher

Resource 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 46 0 83 46 129
CCCT (Nameplate) 0 0 270 270 0 540
Thermal Upgrades 0 0 4 0 0 4
Wind (Energy) 35 23 12 0 58 70
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 62 91 103 94 153 350
Dist. Feeders (Energy) 8 3 2 1 11 13

Resource Tipping Point Analysis
In many resource plans, a PRS is presented with a comparison to other portfolios to
help illustrate cost and risk trade-offs. This IRP extends the portfolio analysis beyond
this simple exercise by focusing on how the portfolio might change if key assumptions
were changed. This provides an array of strategies in reaction to fundamentally different
futures instead of a single strategy. This section identifies assumptions that could alter
the PRS, such as changes to load growth, varying resource capital costs, hydroelectric
upgrade opportunities, the emergence of other non-wind and non-solar renewable
options, or an expansion of the region’s nuclear generation fleet.

Solar Capital Costs Sensitivity
The capital costs of photovoltaic solar generation significantly decreased since the 2009
IRP and the 30 percent Investment Tax Credit for solar generation was extended
through the end of 2015. Solar generation still is not competitive with wind in the
Northwest, even with lower capital costs and tax credits. A sensitivity analysis
determined the price reduction that would be necessary to make photovoltaic solar
generation competitive with wind generation. The analysis reduced solar capital costs in
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 201 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-35

the year 2020 until the PRiSM model selected solar over wind. This analysis also
assumed the double solar REC credit for I-937. The results of the study were that the
capital costs for solar would need to decrease 53 percent, to $2,020/kW (2020 nominal
dollars including AFUDC), in order to make solar competitive with wind generation.

CCCT Capital Cost Sensitivity
CCCTs were the lowest cost resource option in the 2009 IRP. SCCTs are again the
lowest cost resource option, similar to all Avista IRPs prior to its 2009 IRP. A sensitivity
analysis determined why CCCTs were more cost-effective than SCCTs in the 2009 IRP.
The first test involved an analysis of capital costs. The model found that CCCT capital
costs had to be 22 percent lower than forecasted in this IRP to be selected over SCCTs.
Another indication of the change is that O&M cost estimates were lower in the 2009 IRP
($11/kW-year) as compared to the 2011 IRP ($16/kW-year). The 2009 IRP also
assumed that a lower-cost water-cooled plant rather than an air-cooled plant would be
developed. This IRP assumes an air-cooled CCCT due to the increasing difficulty in
obtaining water rights near customer loads. Additional analysis could indicate that
changes in the spark spread, fuel transportation costs, heat rates, or greenhouse gas
policies could affect the selection of CCCTs over SCCTs more than changes in capital
costs. Further, natural gas prices could affect this choice, such as lower or higher prices
could affect this decision, to fully study this theory would require two additional
stochastic studies and this scope of work would extend the timeline for this IRP’s
completion.

Load Forecast Alternatives
An important test in an IRP is its performance across varying load growth sensitivities.
Avista’s loads could grow faster with future development activity after the economy
recovers, or could stagnate in a continued recession. This sensitivity analysis studies
the impact to the PRS if loads grows faster or slower than the Expected Case estimate.
Faster load growth will increase the need for capital and slower load growth will
decrease the need for capital spending on new generation. This analysis focuses on
understanding the changes in the timing of resource decisions based on changes in
load growth.

Loads are expected to grow, net of conservation, at a rate of 1.37 percent over the IRP
timeframe. The Low Load Growth scenario cuts the underlying load growth rate by 50
percent and the High Load Growth case increases expected load growth rate by 50
percent. The sensitivity analysis indicated that, net of conservation, the Low Load
case’s growth rate is 0.19% and the High Load Growth case is 2.4 percent. See Figure
8.18 for load forecast estimates in each case. The load forecast change is not linear
since conservation will make up a greater amount of new load growth in the low case as
conservation programs target existing load (85 percent of load growth). However, in a
high case conservation only makes up 40 percent of load growth that is assumed to be
code requirement driven energy efficiency. As a comparison, the Expected Case
forecast assumes conservation meets 48 percent of new load.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 202 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-36

Figure 8.18: Load Growth Scenario’s Cost/Risk Comparison

The lower load growth case’s resource strategy would not change near-term resource
acquisitions (see Table 8.25), but would eliminate the need for some wind and gas-fired
resources later in the IRP time horizon.

Table 8.25: Low Load Growth Resource Strategy

Resources 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 0 0 0 212 0 212
CCCT (Nameplate) 0 0 0 0 0 0
Thermal Upgrades 0 0 0 4 0 4
Wind (Energy) 35 12 24 0 47 71
Solar (Energy) 0 0 0 0 0 0
Conservation (Energy) 49 60 69 70 108 247
Dist. Feeders (Energy) 8 3 2 1 11 13

Table 8.26 shows the resource strategy with higher growth rates. The amount of wind
acquisitions would increase by 22 aMW and additional peaking resources would be
required to compensate for higher growth rates. In the later years of the study,
additional gas-fired and wind generation resources would be needed to meet peak load
growth and RPS requirements.

0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
4.0%
Low Load Forecast Expected Case High Load Forecast
an
n
u
a
l

a
v
e
r
a
g
e

g
r
o
w
t
h

r
a
t
e
No Conservation
Existing Conservation Trends
Includes New & Existing Conservation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 203 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-37

Table 8.26: High Load Growth Resource Strategy

Resources 2012-16 2017-21 2022-26 2027-31
First 10
Years
All 20
Years
SCCT (Nameplate) 83 298 83 46 381 510
CCCT (Nameplate) 0 0 270 540 0 810
Thermal Upgrades 4 6 0 0 10 10
Wind (Energy) 35 23 35 0 58 93
Solar (Energy) 0 0 0 1 0 1
Conservation (Energy) 71 94 122 156 165 443
Dist. Feeders (Energy) 8 3 2 1 11 13

Figure 8.19 shows the cost, and cost range, for each load growth scenario from a dollar
per megawatt-hour perspective. The chart explains a positive correlation between load
growth and the average cost to serve customers.

Figure 8.19: Load Growth Scenario’s Cost/Risk Comparison

Base Case Low Load
Growth
High Load
Growth
Levelized Cost $/MWh 49.75 44.11 54.86
1 Sigma Lower 42.67 36.99 47.80
1 Sigma Higher 56.83 51.23 61.92
$0
$10
$20
$30
$40
$50
$60
$70
$/
M
W
h
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 204 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-38

Summary
The Preferred Resource Strategy is the roadmap for a resource acquisition plan that
which balances the tradeoff between cost and risk while preparing the Company to
provide reliable electricity service to its customers. Table 8.27 provides a summary of
the total resources selected for each of the portfolios discussed in this chapter.
Distribution Feeder upgrades are included at the same level (13 aMW) in all portfolios
but are not included in the table.

Table 8.27: Summary of Resource Portfolios

Portfolio SC
C
T

(N
a
m
e
p
l
a
t
e
)

CC
C
T

(N
a
m
e
p
l
a
t
e
)

Th
e
r
m
a
l

Up
g
r
a
d
e
s

Wi
n
d

(E
n
e
r
g
y
)

So
l
a
r

(E
n
e
r
g
y
)

Co
n
s
e
r
v
a
t
i
o
n

(E
n
e
r
g
y
)

Preferred Resource Strategy 212 540 4 71 0 310
Least Cost 747 0 0 71 0 310
Least Risk 187 540 17 98 64 310
50/50 Cost Risk 177 540 4 93 9 310
75/25 Cost Risk 332 540 0 82 0 310
25/75 Cost Risk 83 810 4 95 5 310
PRS without Apprentice Credits 212 540 4 96 0 310
2009 PRS 0 810 0 102 0 310
PRS Without Wind 212 540 4 0 0 310
CCCT with Solar 0 810 10 36 33 310
National Renewable Energy Standard 212 540 4 177 1 310
PRS without Conservation 475 815 10 94 0 0
PRS Conservation A/C 25% Lower 249 540 4 82 0 266
PRS Conservation A/C 25% Higher 415 270 7 70 0 334
PRS Conservation A/C 50% Higher 129 540 4 70 0 350
Low Load Growth 212 0 4 71 0 247
High Load Growth 510 810 10 93 1 443

The IRP is a continual effort to select cost- and risk-minimizing resources
complementing the Company’s existing resource mix. Its results and insights help
management and policy-makers formulate good decisions on behalf of ratepayers. The
PRS includes a combination of conservation, efficiency improvements including feeder
upgrades, hydroelectric upgrades, wind, and gas-fired simple and combined-cycle
combustion turbines. The resource strategy identified in this report will change in
response to new information, but Avista focuses decision making on near-term resource
acquisitions where substantial changes concerning the data needed to make decisions
are less likely to occur.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 205 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-39

Table 8.28: Winter 18-Hour Capacity Position (MW) Net of Conservation with New
Resources12

12 Native load includes forecasted savings from conservation and distribution efficiencies programs.
20
1
2
20
1
3
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1
4
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44
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37
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%
15
%
14
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16
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16
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20
4
20
4
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w

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b
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y
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C
0
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0
0
0
0
0
0
26
0
26
0
26
0
52
0
52
0
52
0
52
0
52
0
Ne
w

W
i
n
d
0
0
0
0
0
0
0
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0
0
0
0
0
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0
0
0
0
0
0
Th
e
r
m
a
l

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e
s
o
u
r
c
e

U
p
g
r
a
d
e
s
0
0
0
0
0
0
0
16
16
16
16
16
16
16
16
16
16
16
16
16
To
t
a
l

N
e
w

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
96
96
17
6
17
6
17
6
43
5
43
5
43
5
69
5
69
5
69
5
74
0
74
0
Pe
a
k

P
o
s
i
t
i
o
n

w
i
t
h

N
e
w

R
e
s
o
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r
c
e
s
66
8
65
5
59
2
40
5
29
3
35
6
25
0
31
0
20
7
21
3
52
21
25
4
21
3
15
8
11
4
76
29
36
-1
1
Pl
a
n
n
i
n
g

M
a
r
g
i
n

W
i
t
h

N
e
w

R
e
s
o
u
r
c
e
s
56
%
55
%
52
%
44
%
37
%
43
%
37
%
40
%
34
%
35
%
26
%
24
%
37
%
34
%
31
%
28
%
26
%
24
%
24
%
22
%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 206 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-40

Table 8.29: Summer 18-Hour Capacity Position (MW) Net of Conservation with New
Resources13

13 Ibid
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
TO
T
A
L

L
O
A
D

O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e

L
o
a
d

(
N
e
t

o
f

E
f
f
i
c
i
e
n
c
y

P
r
o
g
r
a
m
s
)
-1
,
5
0
0
-1
,
5
3
8
-1
,
5
7
3
-1
,
6
1
4
-1
,
6
3
7
-1
,
6
6
0
-1
,
6
7
9
-1
,
6
9
2
-1
,
7
0
7
-1
,
7
2
1
-1
,
7
3
1
-1
,
7
4
5
-1
,
7
6
7
-1
,
7
9
5
-1
,
8
2
7
-1
,
8
5
2
-1
,
8
7
9
-1
,
9
0
7
-1
,
9
3
9
-1
,
9
7
3
Fir
m

P
o
w
e
r

S
a
l
e
s
-2
4
3
-2
1
8
-2
1
2
-1
5
9
-1
5
9
-9
-9
-8
-8
-8
-8
-8
-8
-7
-7
-7
-7
-7
-7
-7
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-1
,
7
4
3
-1
,
7
5
6
-1
,
7
8
5
-1
,
7
7
4
-1
,
7
9
7
-1
,
6
6
9
-1
,
6
8
8
-1
,
7
0
0
-1
,
7
1
5
-1
,
7
2
9
-1
,
7
3
9
-1
,
7
5
3
-1
,
7
7
5
-1
,
8
0
2
-1
,
8
3
4
-1
,
8
5
9
-1
,
8
8
6
-1
,
9
1
5
-1
,
9
4
6
-1
,
9
8
1
RE
S
O
U
R
C
E
S
Fir
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
85
85
85
85
85
85
85
83
83
82
82
82
82
82
82
82
82
82
82
82
Hy
d
r
o

R
e
s
o
u
r
c
e
s
90
0
81
9
90
2
85
9
86
6
86
4
88
5
83
3
84
0
85
9
83
3
84
0
85
9
83
3
84
0
85
9
83
3
84
0
85
9
83
3
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
79
9
55
1
55
1
55
1
55
1
55
1
Win
d

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Pe
a
k
i
n
g

U
n
i
t
s
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
17
6
To
t
a
l

R
e
s
o
u
r
c
e
s
1,
9
6
0
1,
8
8
0
1,9
6
2
1,9
1
9
1,
9
2
6
1,
9
2
4
1,
9
4
5
1,
8
9
1
1,8
9
7
1,9
1
6
1,
8
9
1
1,
8
9
6
1,
9
1
6
1,
8
9
0
1,8
9
6
1,6
6
8
1,
6
4
2
1,
6
4
8
1,
6
6
8
1,6
4
2
Pe
a
k

P
o
s
i
t
i
o
n

B
e
f
o
r
e

R
e
s
e
r
v
e
s

P
l
a
n
n
i
n
g
21
7
12
4
17
6
14
6
13
0
25
5
25
7
19
1
18
3
18
7
15
2
14
4
14
1
88
62
-1
9
1
-2
4
4
-2
6
7
-2
7
9
-3
3
9
RE
S
E
R
V
E
S

P
L
A
N
N
I
N
G
Re
q
u
i
r
e
d

O
p
e
r
a
t
i
n
g

R
e
s
e
r
v
e
s
-1
5
3
-1
5
6
-1
5
8
-1
5
9
-1
6
1
-1
5
4
-1
5
5
-1
5
6
-1
5
8
-1
5
9
-1
6
0
-1
6
1
-1
6
3
-1
6
5
-1
6
8
-1
5
5
-1
5
4
-1
5
5
-1
5
7
-1
5
6
Av
a
i
l
a
b
l
e

O
p
e
r
a
t
i
n
g

R
e
s
e
r
v
e
s
15
5
66
17
1
15
9
15
9
15
9
16
1
15
8
15
8
16
1
15
8
15
8
16
1
15
8
15
8
16
1
15
8
15
8
16
1
15
8
Pla
n
n
i
n
g

M
a
r
g
i
n
-2
2
7
-2
3
2
-2
3
8
-2
4
4
-2
4
8
-2
5
2
-2
5
5
-2
5
7
-2
5
9
-2
6
2
-2
6
3
-2
6
6
-2
6
9
-2
7
3
-2
7
8
-2
8
2
-2
8
6
-2
9
0
-2
9
5
-3
0
0
To
t
a
l

R
e
s
e
r
v
e
s

P
l
a
n
n
i
n
g
-2
2
7
-3
2
2
-2
3
8
-2
4
4
-2
5
1
-2
5
2
-2
5
5
-2
5
7
-2
5
9
-2
6
2
-2
6
5
-2
6
9
-2
7
1
-2
8
0
-2
8
8
-2
8
2
-2
8
6
-2
9
0
-2
9
5
-3
0
0
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

R
e
s
e
r
v
e
s

P
l
a
n
n
i
n
g
-1
0
-1
9
9
-6
2
-9
9
-1
2
2
3
2
-6
6
-7
7
-7
4
-1
1
4
-1
2
5
-1
3
0
-1
9
2
-2
2
6
-4
7
3
-5
3
0
-5
5
7
-5
7
4
-6
3
9
Pl
a
n
n
i
n
g

M
a
r
g
i
n

B
e
f
o
r
e

N
W

M
a
r
k
e
t
21
%
11
%
19
%
17
%
16
%
25
%
25
%
21
%
20
%
20
%
18
%
17
%
17
%
14
%
12
%
-2
%
-5
%
-6
%
-6
%
-9
%
Av
i
s
t
a

S
h
a
r
e

o
f

E
x
c
e
s
s

N
W

M
a
r
k
e
t
27
5
22
1
17
8
14
1
10
7
78
52
31
10
3
0
0
0
0
0
0
0
0
0
0
Pe
a
k

P
o
s
i
t
i
o
n

W
i
t
h

N
W

M
a
r
k
e
t
26
5
22
11
7
42
-1
5
81
54
-3
5
-6
7
-7
1
-1
1
4
-1
2
5
-1
3
0
-1
9
2
-2
2
6
-4
7
3
-5
3
0
-5
5
7
-5
7
4
-6
3
9
Pl
a
n
n
i
n
g

M
a
r
g
i
n

W
i
t
h

N
W

M
a
r
k
e
t
37
%
23
%
29
%
25
%
22
%
29
%
28
%
22
%
20
%
20
%
18
%
17
%
17
%
14
%
12
%
-2
%
-5
%
-6
%
-6
%
-9
%
NE
W

R
E
S
O
U
R
C
E
S
Ne
w

S
i
m
p
l
e

C
y
c
l
e

C
C
0
0
0
0
0
0
0
72
72
14
4
14
4
14
4
14
4
14
4
14
4
14
4
14
4
14
4
18
4
18
4
Ne
w

C
o
m
b
i
n
e
d

C
y
c
l
e

C
C
0
0
0
0
0
0
0
0
0
0
0
0
23
5
23
5
23
5
47
0
47
0
47
0
47
0
47
0
Ne
w

W
i
n
d
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Th
e
r
m
a
l

R
e
s
o
u
r
c
e

U
p
g
r
a
d
e
s
0
0
0
0
0
0
0
1
1
1
1
1
1
1
1
1
1
1
1
1
To
t
a
l

N
e
w

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
73
73
14
5
14
5
14
5
38
0
38
0
38
0
61
5
61
5
61
5
65
5
65
5
Pe
a
k

P
o
s
i
t
i
o
n

w
i
t
h

N
e
w

R
e
s
o
u
r
c
e
s
26
5
22
11
7
42
-1
5
81
54
38
6
74
32
20
25
0
18
8
15
4
14
2
85
58
81
16
Pl
a
n
n
i
n
g

M
a
r
g
i
n

W
i
t
h

N
e
w

R
e
s
o
u
r
c
e
s
37
%
23
%
29
%
25
%
22
%
29
%
28
%
27
%
25
%
29
%
26
%
26
%
38
%
35
%
33
%
31
%
28
%
26
%
28
%
24
%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 207 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-41

Table 8.30: Average Annual Energy Position (aMW) With New Resources14

14 Ibid
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
TO
T
A
L

L
O
A
D

O
B
L
I
G
A
T
I
O
N
S
Na
t
i
v
e

L
o
a
d

(
N
e
t

o
f

E
f
f
i
c
i
e
n
c
y

P
r
o
g
r
a
m
s
)
-1
,
1
0
2
-1
,
1
2
1
-1
,
1
3
5
-1
,
1
4
7
-1
,
1
6
5
-1
,
1
8
4
-1
,
1
9
9
-1
,
2
0
8
-1
,
2
2
0
-1
,
2
3
1
-1
,
2
3
9
-1
,
2
4
9
-1
,
2
6
6
-1
,
2
8
6
-1
,
3
1
2
-1
,
3
3
1
-1
,
3
5
1
-1
,
3
7
2
-1
,
3
9
6
-1
,
4
2
1
Fi
r
m

P
o
w
e
r

S
a
l
e
s
-1
4
0
-1
2
7
-1
0
9
-5
8
-5
8
-6
-6
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
-5
To
t
a
l

R
e
q
u
i
r
e
m
e
n
t
s
-1
,
2
4
2
-1
,
2
4
8
-1
,
2
4
4
-1
,
2
0
5
-1
,
2
2
2
-1
,
1
9
0
-1
,
2
0
4
-1
,
2
1
4
-1
,
2
2
5
-1
,
2
3
6
-1
,
2
4
4
-1
,
2
5
4
-1
,
2
7
1
-1
,
2
9
1
-1
,
3
1
8
-1
,
3
3
6
-1
,
3
5
6
-1
,
3
7
7
-1
,
4
0
1
-1
,
4
2
6
RE
S
O
U
R
C
E
S
Fi
r
m

P
o
w
e
r

P
u
r
c
h
a
s
e
s
16
3
16
4
16
3
16
5
16
3
11
2
11
1
91
66
66
65
65
65
65
65
65
65
65
65
65
Hy
d
r
o

R
e
s
o
u
r
c
e
s
52
2
52
5
52
7
49
5
49
5
49
5
49
0
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
48
1
Ba
s
e

L
o
a
d

T
h
e
r
m
a
l
s
75
5
71
4
75
1
74
4
74
6
74
1
72
4
75
8
72
1
72
1
75
8
72
1
72
1
75
8
68
4
51
5
54
1
51
5
51
5
54
1
Wi
n
d

R
e
s
o
u
r
c
e
s
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
To
t
a
l

R
e
s
o
u
r
c
e
s
1,
4
4
1
1,
4
0
3
1,
4
4
2
1,4
0
5
1,4
0
4
1,3
4
8
1,3
2
5
1,3
3
0
1,2
6
8
1,2
6
8
1,3
0
4
1,
2
6
6
1,
2
6
7
1,
3
0
4
1,
2
2
9
1,
0
6
0
1,
0
8
7
1,
0
6
0
1,
0
6
0
1,
0
8
7
En
e
r
g
y

P
o
s
i
t
i
o
n

B
e
f
o
r
e

C
o
n
t
i
n
g
e
n
c
y

P
l
a
n
n
i
n
g
19
8
15
5
19
8
20
0
18
2
15
8
12
1
11
7
43
32
61
12
-4
12
-8
8
-2
7
5
-2
6
9
-3
1
7
-3
4
0
-3
3
9
CO
N
T
I
N
G
E
N
C
Y

P
L
A
N
N
I
N
G
Pe
a
k
i
n
g

R
e
s
o
u
r
c
e
s
15
3
15
3
15
3
13
8
15
3
15
4
15
3
14
7
14
6
14
5
14
7
14
6
14
5
14
7
14
6
14
5
14
7
14
6
14
5
14
7
Co
n
t
i
n
g
e
n
c
y
-2
2
8
-2
2
9
-2
3
0
-2
3
1
-2
3
2
-2
3
3
-2
3
3
-2
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 208 of 1069
Chapter 8 – Preferred Resource Strategy
Avista Corp 2011 Electric IRP 8-42

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Table 8.31: Washington State RPS Detail with New Resources (aMW)15

15 Retail sales forecast includes new conservation programs.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 209 of 1069
Chapter 9–Action Items
Avista Corp 2011 Electric IRP 9-1
9. Action Items
The Integrated Resource Plan (IRP) is an ongoing and iterative process balancing
regular publication timelines with pursuing the best 20-year resource strategies. The
biennial publication date provides opportunities for ongoing improvements to the
modeling and forecasting procedures and tools, as well as the opportunity to enhance
the process with new research as the planning environment changes. This section
provides an overview of the progress made on the 2009 IRP Action Plan and provides
the 2011 Action Plan.

Summary of the 2009 IRP Action Plan
The 2009 Action Plan included five separate categories: resource additions and
analysis, energy efficiency, environmental policies, modeling and forecasting
enhancements, and transmission planning.

2009 Action Plan – Resource Additions and Analysis
 Continue to explore the potential for wind and non-renewable resources.
 Issue an RFP for turbines at Reardan and up to 100 MW of wind or other
renewables in 2009.
 Finish studies on the costs and environmental benefits of hydro upgrades at Cabinet
Gorge, Long Lake, Post Falls, and Monroe Street.
 Study potential locations for the natural gas-fired resource identified to be online
between 2015 and 2020.
 Continue participation in regional IRP processes and where agreeable find resource
opportunities to meet resource requirements on a collaborative basis.

Progress Report – Resource Additions and Analysis
After filing the 2009 IRP, the Company issued two RFPs: (1) a 35 aMW Renewable
RFP and (2) a wind turbine RFP for the Reardan development. The 2009 RFP showed
that the anticipated benefits of early construction of Reardan, or a third party acquisition,
identified in the 2009 IRP were not available. The Company retains the Reardan Wind
Project site as an option to meet future RPS goals. Site control provides a hedge
against escalating costs and the limited number of viable Pacific Northwest wind sites.
Additional studies on non-wind renewable energy sources continued throughout this
planning cycle. More details about non-wind renewables are included in the Generation
Resource Options and Preferred Resource Strategy chapters.

Following the 2009 RFP, several wind development firms asked when another RFP
would be issued, indicating that wind turbine prices had fallen greatly since the 2009
RFP and that prices in a new RFP issuance would be competitive to the wholesale
market prices (when including REC sales) when including federal and state tax
subsidies. In response, the Company issued an RFP for approximately 35 aMW of
Washington renewable portfolio standard-qualified renewable energy contracts. The
Company did not include its Reardan Wind Project, as it could not be completed in time
to take advantage of the expiring Federal tax subsidies.1 The Company’s February 2011
1 Federal tax incentives for wind expire at the end of calendar year 2012.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 210 of 1069
Chapter 9–Action Items
Avista Corp 2011 Electric IRP 9-2
RFP received bids for 774 MW of qualifying projects (769 MW of wind and 5 MW of
landfill gas). The Company selected the 105 MW Palouse Wind Project, located near
Oakesdale, Washington. The proposal is a 30-year power purchase agreement with a
buyout option after year 10. Further details regarding this acquisition are contained in
the Preferred Resource Strategy Chapter.

The Company is continuing to research system hydroelectric upgrade options. The
results of these studies are not yet complete, and we therefore were unable to include
the results of these studies in this IRP. Some preliminary results are in the Generation
Resource Options Chapter, and in presentations to the third Technical Advisory
Committee on December 2, 2010. The slides from that presentation are contained in
Appendix A.

Preliminary work on identifying potential locations for future natural gas-fired resources
identified in the 2009 IRP is complete, but a final site selection is not complete. The
2011 PRS pushes the need for the next gas-fired plant until 2019 and changes the
technology from combined to simple cycle. This work will continue and an update given
as an Action Item in the 2013 IRP.

The Company continues to participate in regional IRP processes, attending peer-utility
meetings. Regional utilities participated in our Technical Advisory Committee meetings
to share the latest concepts in resource planning.

2009 Action Plan – Energy Efficiency
 Pursue American Reinvestment and Recovery Act of 2009 (ARRA) funding for low
income weatherization.
 Analyze and report on the results of the July 2007 through December 2009 demand
response pilot in Moscow and Sandpoint.
 Have an external party perform a study on technical, economic, and achievable
potential for energy efficiency in Avista’s entire service territory.
 Study and quantify transmission and distribution efficiency concepts as they apply to
meeting Washington’s RPS goals.
 Update processes and protocols for conservation measurement, evaluation and
verification.
 Determine the potential impacts and costs of load management options.

Progress Report – Energy Efficiency
Avista’s Community Action Agencies received significant increases for low-income
weatherization through ARRA funds. The Idaho Load Management Pilot Final Report,
issued on March 1, 2010, provides details on the Moscow and Sandpoint demand
response project. The pilot included ten successful trial events, including the cycling of
heating and air conditioning units and the short-term interruption of water heaters. Five
percent of the eligible participants agreed to participate in the volunteer program; two
percent of customers participating in the study opted-out of the program during events.
Even though the program successfully showed the capability of a load interruption
program as a reliable capacity resource, the regional power market does not support
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 211 of 1069
Chapter 9–Action Items
Avista Corp 2011 Electric IRP 9-3
the present costs of such a program at this time. The Company will continue to monitor
the marketplace to determine if this type of load management program will become cost
effective in the future.

Global Energy Partners (Global) completed a 20-year conservation potential
assessment for our residential, commercial and industrial customers in Idaho and
Washington. Global presented the assessment results at the fifth Technical Advisory
Committee meeting on April 12, 2011. A copy of the presentation is included in
Appendix D, and more details are in the Energy Efficiency chapter.

The study and quantification of transmission and distribution efficiency concepts, as
they apply to meeting Washington’s renewable portfolio standard goals is part of an
ongoing process. It will be refined as the Company prepares its initial Washington
Energy Independence Act compliance report to the Washington Utility and
Transportation Commission. Additional details are in the Energy Efficiency and
Transmission and Distribution chapters of this IRP.

The Company continues to update the processes and protocols for conservation
measurement, evaluation and verification (EM&V). The Company participated in an
EM&V Collaborative in 2010 resulting in an EM&V framework, annual EM&V plans and
development of individual program EM&V plans. This continual EM&V loop will feed
improved processes and protocols for conservation measurement, evaluation and
verification. As part of the conservation potential study, Global Energy Partners looked
at demand response potential and costs. More details about this work are in the Energy
Efficiency chapter.

2009 Action Plan – Environmental Policy
 Continue to study the potential impact of state and federal climate change
legislation.
 Continue and report on the work of Avista’s Climate Change Council.

Progress Report – Environmental Policy
Avista’s Climate Change Council and the Resource Planning team actively analyze
state and federal greenhouse gas legislation. This work will continue until final rules are
established and laws passed. The focus will then shift to mitigating the costs of meeting
these laws and regulations. Avista has quantified its greenhouse gas emissions using
the World Resources Initiative–World Business Council for Sustainable Development
(WRI-WBCSD) inventory protocol in anticipation of state and federal greenhouse gas
reporting mandates. Details about Climate Change Council efforts are in the Policy
Considerations chapter.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 212 of 1069
Chapter 9–Action Items
Avista Corp 2011 Electric IRP 9-4
2009 Action Plan – Modeling and Forecasting Enhancements
 Refine cost driver relationships in the stochastic model.
 Continue to refine PRiSM by developing a resource retirement capability to solve for
other risk measurements and by adding more resource options.
 Continue developing Loss of Load Probability and Sustained Peaking analysis for
inclusion in the IRP process, and confirm appropriateness of the 15 percent capacity
planning margin assumed for this IRP.
 Continue studying the impacts of climate change on the load forecast.
 Study load growth trends and their correlation to weather patterns.

Progress Report – Modeling and Forecasting Enhancements
Improvements have continued on stochastic modeling for the IRP. This plan relies on
new methods for modeling natural gas and wind. Work continues on developing a
method to correlate temperature, wind and hydro in the stochastic model. This work will
continue and results reported in the 2013 IRP.

The 2011 IRP includes several refinements to the PRiSM model. A resource retirement
capability was developed, but not utilized for this IRP. We developed a method to
evaluate the true standard deviation of power supply costs for the 2011 IRP, but long
solution times prevented its adoption. This plan also includes more resource options,
and modeling of generators by state and by location on the regional transmission
system.

Loss of Load Probability (LOLP) and Sustained Peaking analysis models were
developed and used for the 2011 IRP. This IRP uses an 18-hour sustained peak over
three days to estimate the need for new resources. Avista developed an LOLP model
for this IRP and presented it to the TAC on September 9, 2010; however, subsequent
testing of the model found that the LOLP study was driven primarily by regional market
availability assumptions that were beyond the scope of the study. The Company will
continue to work with the Northwest Power and Conservation Council to determine the
best methods for identifying regional market availability. More details are in the Loads &
Resources and Preferred Resource Strategy chapters.

The IRP load forecast continues to estimate the impacts of climate change on customer
load growth. More details are included in the Load and Resource chapter of this IRP.
Any changes will be in the 2013 IRP.

Transmission Planning
 Work to maintain/retain existing transmission rights on the Company’s transmission
system, under applicable FERC policies, for transmission service to bundled retail
native load.
 Continue to participate in BPA transmission practice processes and rate
proceedings to minimize the costs of integrating existing resources outside of the
Company’s service area.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 213 of 1069
Chapter 9–Action Items
Avista Corp 2011 Electric IRP 9-5
 Continue to participate in regional and sub-regional efforts to establish new regional
transmission structures (ColumbiaGrid and other forums) to facilitate long-term
expansion of the regional transmission system.
 Evaluate costs to integrate new resources across Avista’s service territory and from
regions outside of the Northwest.
 Study and implement distribution feeder rebuilds to reduce system losses.
 Study transmission reconfigurations that economically reduce system losses.

Progress Report – Transmission Planning
The 2009 IRP transmission planning action item studies continue and are included in
the 2013 Action Plan. Details about progress made toward the maintenance of existing
transmission rights, involvement in BPA processes, participation in regional
transmission processes, and the evaluation of integrating different resources in the IRP
are in the Transmission and Distribution chapter.

Avista has completed a feeder rebuild pilot project at its 9th and Central 12F4 feeder.
The Company received federal stimulus dollars for several “Smart Grid” initiatives that
include projects contained in the 2009 IRP. The Company is developing a program to
rebuild additional feeders as outlined in this plan. Additional details on these projects
are included in the Transmission and Distribution Chapter.

2011 IRP Action Plan
The Company’s 2011 Preferred Resource Strategy provides direction and guidance for
the type, timing and size of future resource acquisitions. The 2011 IRP Action Plan
highlights the activities planned for possible inclusion in the 2013 IRP. Progress and
results for each of the 2011 Action Plan items will be reported to the Technical Advisory
Committee and the results will be included in Avista’s 2013 IRP. The 2011 Action Plan
includes input from Commission Staff, the Company’s management team, and the
Technical Advisory Committee.

Resource Additions and Analysis
 Continue to explore and follow potential new resources opportunities.
 Continue studies on the costs, energy, capacity and environmental benefits of hydro
upgrades at both Spokane and Clark Fork River projects.
 Study potential locations for the natural gas-fired resource identified to be online by
the end of 2018.
 Continue participation in regional IRP processes and, where agreeable, find
opportunities to meet resource requirements on a collaborative basis with other
utilities.
 Provide an update on the Little Falls and Nine Mile hydroelectric project upgrades.
 Study potential for demand response projects with industrial customers.
 Continue to monitor regional surplus capacity and Avista’s reliance on this surplus
for near- and medium-term needs.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 214 of 1069
Chapter 9–Action Items
Avista Corp 2011 Electric IRP 9-6
Energy Efficiency
 Study and quantify transmission and distribution efficiency projects as they apply to
Washington RPS goals.
 Update processes and protocols for conservation measurement, evaluation and
verification.
 Continue to determine the potential impacts and costs of load management options.

Environmental Policy
 Continue studies of state and federal climate change policies.
 Continue and report on the work of Avista’s Climate Change Council.

Modeling and Forecasting Enhancements
 Continue following regional reliability processes and develop Avista-centric modeling
for possible inclusion in the 2013 IRP.
 Continue studying the impacts of climate change on retail loads.
 Refine the stochastic model for cost driver relationships, including further analyzing
year-to-year hydro correlation and the correlation between wind, load, and hydro.

Transmission and Distribution Planning
 Work to maintain the Company’s existing transmission rights, under applicable
FERC policies, for transmission service to bundled retail native load.
 Continue to participate in BPA transmission processes and rate proceedings to
minimize costs of integrating existing resources outside of Avista’s service area.
 Continue to participate in regional and sub-regional efforts to establish new regional
transmission structures to facilitate long-term expansion of the regional transmission
system.
 Evaluate the costs to integrate new resources across Avista’s service territory and
from regions outside of the Northwest.
 Study and implement distribution feeder rebuilds to reduce system losses.
 Continue to study other potential areas to implement Smart Grid projects to other
areas of the service territory.
 Study transmission reconfigurations that economically reduce system losses.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 215 of 1069
Chapter 9–Action Items
Avista Corp 2011 Electric IRP 9-7
Production Credits

Primary Avista 2011 Electric IRP Team

Individual Title Contribution
Clint Kalich Manager of Resource Planning & Analysis Project Manager
James Gall Senior Power Supply Analyst Analysis/Author
John Lyons Power Supply Analyst Research/Author/Editor
Randy Barcus Economic Analyst Load Forecast
Lori Hermanson Utility Resource Analyst Energy Efficiency
Scott Waples Director System Planning Transmission & Distribution

Other Contributors

Name Title
Reuben Arts System Planning Engineer
Thomas Dempsey Manager, Generation Joint Projects
Mike Gonnella Manager of Engineering - Thermal
Jason Graham Mechanical Engineer
Curt Kirkeby Senior Engineer II
Mike Magruder Substation Engineering Manger
Jon Powell Partnership Solutions Manager
Greg Rahn Manager of Natural Gas Planning
Xin Shane Power Supply Analyst
Ken Sweigart Transmission Design Manager
Steve Wenke Chief Generation Engineer
Jessie Wuerst Communications Manager

Contact contributors via email by placing the names in this email address format:
[e-mail]

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 216 of 1069

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 217 of 1069
APPENDIX
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 218 of 1069
Appendix Table of Contents
Appendix A – Technical Advisory Committee Presentations (page 1)
Technical Advisory Committee Meeting No. 1 (page 2)
Technical Advisory Committee Meeting No. 2 (page 49)
Technical Advisory Committee Meeting No. 3 (page 112)
Technical Advisory Committee Meeting No. 4 (page 262)
Technical Advisory Committee Meeting No. 5 (page 345)
Technical Advisory Committee Meeting No. 6 (page 438)
Appendix B – Work Plan for the 2011 Electric Integrated Resource Plan (page 493)
Appendix C – Comprehensive List of Energy Efficiency Equipment and Measures
Included in the Study (page 499)
Appendix D – Conservation Potential Assessment Study (page 572)
Appendix E – North Idaho Transmission Study (page 841)
Appendix F – 2011 Electric IRP New Resource Table for Transmission (page 849)

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 219 of 1069

2011 Electric Integrated
Resource Plan

Appendix A – Technical Advisory
Committee Presentations

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 220 of 1069
Avista’s 2011 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 1 Agenda
Thursday, May 27, 2010
Conference Room 130

Topic Time Staff

1. Introduction 10:30 Lafferty

2. Work Plan 10:35 Lyons

3. Load & Resource Balance Update 11:00 Shane

4. Resource Planning Environment 11:35 Lyons

5. Lunch 12:00

6. 2011 IRP Topic Discussions 1:15
Analytical Process Changes Gall
Hydro Modeling Shane
Resource Adequacy Kalich
Loss of Load Probability Gall
Energy Efficiency Hermanson
Scoping the 2011 Plan Kalich

7. Adjourn 3:30

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 221 of 1069
Work Plan
John Lyons
Technical Advisory Committee Meeting #1
2011 Electric Integrated Resource Plan
May 27, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 222 of 1069
Technical Advisory Committee Meetings
May 27, 2010: Work plan, load & resource balance, resource planning
environment, and 2011 IRP topic discussions (analytical process changes, hydro
modeling, resource adequacy, loss of load probability, energy efficiency, and
scoping the 2011 plan)
August 2010: Risk and resource assumptions, loss of load probability analysis,
scenarios and futures, and energy efficiency
October 2010: Load forecast, preliminary electric and gas price forecasts,
updated load & resource forecast balance, and transmission cost studies
February 2011:Review of modeling and assumptions, and draft PRS
March 2011: Review of scenarios and futures, and portfolio analysis
April 2011: Review of final PRS and action items
June 2011: Review of the 2011 IRP
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 223 of 1069
2011 Integrated Resource Plan Modeling Process
Preferred
Resource
Strategy
AURORA
“Wholesale Electric
Market”
300 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Emission Pricing
Existing Resources
Resource Options
Transmission
Resource &
Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,
Capacity,
& RPS
Balances New Resource
Options & Costs
Cost Effective T&D
Projects/Costs
Cost Effective
Conservation
Measures/Costs
Mid-Columbia
Prices
Stochastic Inputs Deterministic Inputs
Capacity
Value
Avoided
Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 224 of 1069
2011 Electric IRP Draft Outline
1. Executive Summary
2. Introduction and Stakeholder Involvement
3. Loads and Resources
a)Load forecast and scenarios
b)Existing resources
c) Resource adequacy
4. Energy Efficiency and Demand Response
a)Energy and capacity savings projections and methodology
b)Two year energy savings target (I-937) & business planning process
c) Demand response options and study results
d)Risk and externalities
5. Environmental Issues
a)Carbon emissions
b)Other
6. Transmission Planning
a)Resource integration
b)Smart grid
c) Other T&D efficiencies
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 225 of 1069
2011 Electric IRP Draft Outline (cont)
7. Generation Resource Options
a)New resource alternatives
b)Thermal and hydro upgrades
8. Market Analysis
a)Regional loads, transmission, resources
b)Fuel price forecasts
c)Risk modeling
d)Market price forecasts
e)Market scenario analysis
9. Preferred Resource Strategy
a)The PRiSM Model and efficient frontier analysis
b)Preferred Resource Strategy results and I-937 compliance
c) Portfolio scenario analysis
10. Action Items
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 226 of 1069
Load and Resource Balance Forecast
Xin Shane
Technical Advisory Committee Meeting #1
2011 Electric Integrated Resource Plan
May 27, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 227 of 1069
L&R Changes From 2009 IRP
Load- 10 year growth rate 1.8%, 20 year growth rate 1.6%for
Peak and Energy. The forecast for year 2011 is 42 aMW lower
than previous forecast or 3.6%lower
Hydro- Uses Clark Fork Optimization Package Results
Thermal- CS2 duct burner capacity is upgraded to 28 MW from
23 MW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 228 of 1069
Annual Average Energy Position
Base Case
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
aM
W
Hydro Base Thermal Contracts Peakers Load Load w/ Cont.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 229 of 1069
Winter Capacity Position
Base Case
Planning Margin = 15%
0
500
1,000
1,500
2,000
2,500
3,000
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
MW
Peakers Contracts Base Thermal Hydro Load Load w/PM, w/o Maint
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 230 of 1069
August Capacity Position
Base Case
0
500
1,000
1,500
2,000
2,500
3,000
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
MW
Peakers Contracts Base Thermal Hydro Load Load w/PM, w/o Maint
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 231 of 1069
Energy Positions –7 Scenarios
(aMW)
(1,000)
(800)
(600)
(400)
(200)
0
200
400
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
w/o Energy Efficiency
No PURPA
w/o Short-term Purchases
NPCC PM
Base Case
High Load
Low Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 232 of 1069
Winter Capacity Positions –7 Scenarios
(MW)
(1,600)
(1,400)
(1,200)
(1,000)
(800)
(600)
(400)
(200)
0
200
400
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
Base Case
w/o Energy Efficiency
No PURPA
w/o Short-term Purchases
NPCC PM
High Load
Low Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 233 of 1069
August Capacity Positions –7 Scenarios
(MW)
(1,600)
(1,400)
(1,200)
(1,000)
(800)
(600)
(400)
(200)
0
200
400
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
Base Case
w/o Energy Efficiency
No PURPA
w/o Short-term Purchases
NPCC PM
High Load
Low Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 234 of 1069
Washington State RPS (aMW)
On-line
Year
Apprentice
Labor
Upgrade
Energy 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
WA State Retail Sales Forecast 656 668 681 693 702 712 721 730 740 751
Load 10% Chance of Exceedance 29 30 30 31 31 32 32 33 33 34
Planning RPS Load 685 698 711 724 733 744 753 763 773 785
RPS %0%3%3%3%3%9%9%9%9%15%
Required Renewable Energy 0.0 20.3 20.8 21.1 21.5 65.6 66.5 67.4 68.2 115.2
Renewable Resources
Purchased RECs 0.0 5.7 5.7 5.7 5.7 0.0 0.0 0.0 0.0 0.0
Kettle Falls 1983 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Stateline 1999 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Long Lake 3 1999 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2
Little Falls 4 2001 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6
Cabinet 2 2004 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
Cabinet 3 2001 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5
Cabinet 4 2007 1.0 1.99 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
Noxon 1 2009 1.0 2.90 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
Reardan 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Hydro 10% Chance of Exceedance (4.2)(4.2)(4.2)(4.2)(4.2)(4.2)(4.2)(4.2)(4.2)(4.2)
Total Qualifying Resources 10.9 16.5 16.6 16.6 16.6 10.9 10.9 10.9 10.9 10.9
Net REC Position (Completed)10.9 (3.8)(4.2)(4.6)(5.0)(54.7)(55.6)(56.5)(57.4)(104.4)
Budgeted Hydro Upgrades
Noxon 2 2011 1.0 1.00 0.5 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0
Noxon 3 2010 1.0 1.30 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3
Noxon 4 2012 1.0 1.20 0.0 0.6 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2
Nine Mile 2012 1.2 3.80 0.0 2.3 4.6 4.6 4.6 4.6 4.6 4.6 4.6 4.6
Hydro 10% Chance of Exceedance (0.5)(1.3)(2.0)(2.0)(2.0)(2.0)(2.0)(2.0)(2.0)(2.0)
Total Budgeted Hydro Upgrades 1.3 3.8 6.1 6.1 6.1 6.1 6.1 6.1 6.1 6.1
Rollover Credits 0.0 12.1 12.2 14.1 15.6 16.7 0.0 0.0 0.0 0.0
Net REC Postion (Budgeted Upgrades)with Rollover 12.1 12.2 14.1 15.6 16.7 (31.9)(49.5)(50.4)(51.3)(98.3)
Net REC Postion (Budgeted Upgrades)w/o Rollover 12.1 0.1 1.9 1.5 1.1 (48.6)(49.5)(50.4)(51.3)(98.3)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 235 of 1069
Planning Environment
John Lyons
Technical Advisory Committee Meeting #1
2011 Electric Integrated Resource Plan
May 27, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 236 of 1069
Major Planning Issues
1.Renewable Portfolio Standards
–State and federal
2.Greenhouse Gas Regulations
–State, regional, and federal
–Emissions performance standards and reporting
3.Energy Efficiency Requirements
4.Reliability Planning
5.Variable Resource Integration
6.Electric Vehicles
7.Smart Grid
8.PURPA
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 237 of 1069
State & Federal Greenhouse Gas Reduction Goals
Kerry-Lieberman Waxman-Markey
2013 4.75%3% (2012)
2020 17%17%
2030 42%42%
2050 83%83%
Percentage goals below 2005 greenhouse gas emissions
Washington Goals
2020 1990 emissions
2035 25% below 1990
2050 50% below 1990
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 238 of 1069
Key Components Kerry-Lieberman
(American Power Act)
Allowances:
–75% emissions based and 25% load based
–Prohibition from receiving excess allocations
–Electricity sector begins in 2013, natural gas in 2016
–Increased levels of free allocations
Preemption of state cap-and-trade programs
Preempt EPA regulation through Clean Air Act
Carbon fees for petroleum
Emissions credit limitations
Emissions credit banking and borrowing
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 239 of 1069
American Power Act –Price Collars
$-
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
$70.00
$80.00
$90.00
$100.00
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
Price Floor
Price Ceiling
2009 IRP
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 240 of 1069
EPA Tailoring Rule
Clean Air Act permitting requirements for greenhouse gas (GHG)
emissions from large stationary sources
January 2, 2011: Prevention of Significant Deterioration (PSD)
requirements for GHG emissions for new and modified facilities
needing non-GHG PSD permits and increasing GHG emissions
75,000 tons CO2-e or more per year
July 1, 2011: PSD requirements on new facilities emitting
100,000 tons CO2-e and modifications increasing GHG
emissions 75,000 tons
Rulemaking in 2011 setting emission thresholds and permitting
requirements for 2013
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 241 of 1069
Analytical Process Changes
James Gall
Technical Advisory Committee Meeting #1
2011 Electric Integrated Resource Plan
May 27, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 242 of 1069
2011 Integrated Resource Plan Modeling Process
Preferred
Resource
Strategy
AURORA
“Wholesale Electric
Market”
300 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Emission Pricing
Existing Resources
Resource Options
Transmission
Resource &
Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,
Capacity,
& RPS
Balances New Resource
Options & Costs
Cost Effective T&D
Projects/Costs
Cost Effective
Conservation
Measures/Costs
Mid-Columbia
Prices
Stochastic Inputs Deterministic Inputs
Capacity
Value
Avoided
Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 243 of 1069
Modeling Enhancements and Questions/Feedback
Modeling Enhancements
Study period 2012 –2031
Use Loss of Load Probability/Expectation to target planning margins
Resource retirements as an option in PRiSM
Add other matrices to evaluate portfolio risk (i.e. Tail Var, CoVar, CO2)
Increased number of resource upgrades as options (thermal and hydro)
Increased number of distribution efficiency programs
Evaluate demand response programs
Further enhance relationships of regional market variables (i.e. correlations)
Questions/Feedback
Real versus nominal costs/prices reporting
Market analysis (more, less, same- stochastic or scenario focused)
Portfolio analysis (more, less, or same)
Other requests
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 244 of 1069
Hydro System Optimization Modeling
Xin Shane
Technical Advisory Committee Meeting #1
2011 Electric Integrated Resource Plan
May 27, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 245 of 1069
Structure of Hydro System Optimization Package
System
Optimization
Model
Water Budget
Model
Output
Database
Input
Database
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 246 of 1069
Water Budget Model Overview
The Water Budget Model’s primary goal is to recognize the storage capabilities inherent in
system reservoirs, optimizing water releases to maximize generation values while enforcing
project constraints.
Today’s computers cannot optimize at an adequate detail level to extend the hourly
Optimization Model to annual or multi-year timeframes
Water Budget Model simplifies certain aspects, allowing optimization across many
weeks to years
Approach is a best practice, “industry standard”
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 247 of 1069
System Optimization Model Overview
Hourly model, with potential for more granularity (i.e., intra-hour analyses)
Each project is represented in detail, including:
–Accurate (piece-wise) reflection of individual turbine efficiency curves;
–Physical and license-constrained reservoir elevations;
–Tailrace elevations;
–Minimum and maximum flow constraints; and
–Other regulation constraints
Shapes generation into the most beneficial (i.e., most economic) time periods using
storage reservoirs
Maximizes generation by flowing water through the most efficient points on each
turbine’s power curve
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 248 of 1069
Model vs Actual Generation- Clark Fork Example (aMW)
Before Benchmarking
150.0
200.0
250.0
300.0
350.0
400.0
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Actual Generation Model Output
After Benchmarking
150.0
200.0
250.0
300.0
350.0
400.0
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
Actual Generation Model Output
Cabinet Unit 4
Upgrade was online
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 249 of 1069
Next Steps
Complete Spokane River Model
Complete Upgrade Analyses for the Following Projects
–Long Lake–new power house with 1 or 2 new units (30-120 MW, pumped storage)
–Post Falls–replace powerhouse with between 1 and 3 new units (25-40 MW)
–Monroe Street–one additional unit (~45 MW capacity)
–Cabinet Gorge–one or 2 new units (60-120 MW, help with total dissolved gas
mitigation)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 250 of 1069
Resource Adequacy
Clint Kalich
Technical Advisory Committee Meeting #1
2011 Electric Integrated Resource Plan
May 27, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 251 of 1069
Concepts
Generator Capacity Services
–Energy
–Reserve for forced outages and extended load (i.e., hot and cold weather) excursions
–Regulating
–Load following
–Energy imbalance (mismatches between scheduled and actual generation)
Traditional Resource Planning Methodologies
–Energy L&R
•Average forecast
•Plus contingency energy
–Capacity L&R
•Average peak load
•Plus planning margin
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 252 of 1069
Capacity Services Definitions
Energy
–Average capability to do work over a given time horizon
–Conversion of fuel (water, wind, coal, gas, wood, etc.) to electricity
Planning Reserves
–Operating Reserve –capacity held back to cover forced outages and non-firm imports
•5%-7%-5% of online capacity for hydro-thermal-wind
•at minimum half must be “spinning;” the remaining can be “non-spinning”
•first hour of system contingency met through NWPP Reserve Sharing Group
–Regulating Reserve –spinning reserve immediately responsive to AGC
•generally a seconds-to-5-minute product
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 253 of 1069
Capacity Services Definitions, Cont.
Planning Reserves, Cont.
–Load Following
•Reserve-like product to follow variations in load and resources across the trading
hour
*beyond 5 minutes
*can be spinning or non-spinning (traditionally spinning in the NW)
–Energy Imbalance
•“Make-up energy”
•Covers variations between hourly scheduled and actual generation levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 254 of 1069
Potential Changes to L&R Planning Margin
Operating Reserve
–5% hydro and wind
–7% thermal
Regulating Reserve: ~25 MW
Load Following: TBD
Energy Imbalance
–Wind and solar ~10-15%
–Load ~2%
Weather Variation: TBD
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 255 of 1069
Key Considerations by Resource
All Resources
–Abilities to provide individual capacity services discussed above
–Potential maintenance schedules
–Forced outage characteristics
Hydro
–Sustained peaking capabilities
–Run-of-river vs. reservoir storage vs. pumped storage
–Upstream inflows during critical events
Gas-Fired Thermals
–Weather impacts
–Resource type (peaking versus base-load, etc.)
–Fuel availability over peak events
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 256 of 1069
Key Considerations by Resource, Cont.
Coal
–Ramp rates
Load Interruption (aka demand-side management)
–Coincidence of measure with system peaking periods
–Frequency of interruption rights
–Duration of interruption rights
–Sustainability of interruption savings
•Especially when looking outside of industrial/large commercial classes
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 257 of 1069
Key Considerations by Resource, Cont.
Market Purchases
–How much is available during critical events
•Transmission constraints
•Surpluses on 3rd party systems
–“Firmness” of anticipated deliveries
•Is 3rd party “firming” the sale?
•In other words, will purchases be cut during critical events to serve 3rd-party system?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 258 of 1069
Illustration of Capacity Obligation
1000
100
25 66 20
100
0
200
400
600
800
1,000
1,200
1,400
1-in-2 peak
energy
load following regulation op. reserves forecast error planning
margin
total
planning margin forecast error
op. reserves regulation
load following 1-in-2 peak energy 311 MW of
additional
capacity,
or 31%
311 MW of
additional
capacity,
or 31%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 259 of 1069
Metrics to Measure Resource Adequacy
Loss of Load Probability (LOLP)
–Percent of iterations that have at least one loss of load event
Loss of Load Expectation (LOLE)
–Days with an event; units are the number of days per year
Loss of Load Hours (LOLH)
–Hours with an event; units are the number of hours per year
Expected or Equivalent Unserved Energy (EUE)
–Average quantity of energy not served in each iteration (MWh)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 260 of 1069
Planning Margin Perspectives
Avista Margin History
–10% of peak load, plus 90 MW (1980s-2008)
–15% of peak load (2009)
FERC Standard Market Design: 12-18%
Northwest Power and Conservation Council: 23% winter (January) , 24% summer (July)
Avista 2011 IRP Margin
–Based on probabilistic reliability study
•LOLP, LOLE, LOLH, EUE metrics
*5% LOLP (proposed)
*1 day in 10 years LOLE (proposed)
*LOLH and EUE (TBD)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 261 of 1069
Loss of Load Probability
James Gall
Technical Advisory Committee Meeting #1
2011 Electric Integrated Resource Plan
May 27, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 262 of 1069
Overview
Why
Avista’s capacity planning margin is 15% of peak load. Without conducting a statistical
analysis regarding probability of no serving all customer load due to lack of generation, the
15% should be questioned- especially as additional variable generation is added.
Modeling
8,760 hours for ~1,000 potential outcomes (draws, games, iterations, etc)
Study 2012, ‘16, ‘20, ‘24, and ’28
Randomizes: forced outages, temperature, loads, wind generation, and hydro conditions
Takes into account hydro constraints, market purchases, and reserves including: within
hour load variation, variable resource reserves, and operating reserves
Can illustrate benefits using demand response and federal emergency hydro
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 263 of 1069
For the Next TAC meeting
Detailed presentation on how model works
Finalize 2012 study (final load & wind modules)
Market reliance scenarios
Test 2009 IRP’s Preferred Resource Strategy for later years
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 264 of 1069
Energy Efficiency & Demand Response
Lori Hermanson
Technical Advisory Committee Meeting #1
2011 Electric Integrated Resource Plan
May 27, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 265 of 1069
Energy Efficiency Progress Since Last IRP
Targets and Year-to-Date Achievement
I-937 Plan for Washington accepted with conditions
–Target for Washington electric only
–Year-to-date results toward I-937 targets
Demand Response Pilot
– Tested and improved equipment capability on Avista’s system
–Initiated 10 successful events of either cycling heating or AC or
shutting off water heaters for 2-4 hrs
– Proved customers’ strong willingness to participate with few opt-outs
–Low northwest on/off-peak price differentials makes these programs
not cost effective
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 266 of 1069
Next Steps for 2011 IRP
Conservation Potential Assessment (all states, gas/electric )
–Issue RFP in June
–Complete RFP by October
–Evaluate TRC cost-effectiveness with draft IRP electric price
forecast in November
–Establish energy efficiency placeholder levels in early January
–Update with finalized IRP electric price forecast in late January
–Finalize energy efficiency levels in early February
–Draft energy efficiency and demand response section of IRP
document
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 267 of 1069
Avista’s 2011 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
September 8th and 9th, 2010
Avista Headquarters – Spokane, Washington

Wednesday, September 8th

Leave from Avista 8:30 am
Lancaster Tour 9:30 am
Rathdrum CT & Boulder Park Stops
Lunch – Sawtooth Grill 12:30 pm
Upper Falls & Monroe Street 1:45 pm
Return to Avista 4:00 pm

Thursday, September 9, 2010
Avista Conference Room 130
Topic Time Staff
1. Introduction 10:00 Storro

2. Resource Assumptions 10:05 Lyons

3. Reliability Planning 10:35 Gall

4. Lunch 11:30

5. Sustainability Report 12:30 Wuerst

6. Combined Heat and Power Generation 1:30 Dempsey

7. Energy Efficiency 2:30 Hermanson

8. Adjourn 3:30

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 268 of 1069
Resource Assumptions
John Lyons
Technical Advisory Committee Meeting #2
2011 Electric Integrated Resource Plan
September 9, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 269 of 1069
Supply Side Resource Data Sources
Power Council –6th Power Plan
Resource lists developed internally from:
–Trade journals
–Press releases from other companies
–Engineering studies and models
–State commission announcements
–Proposals from developers
Consulting firms/reports
State and federal resource studies
Data sources are used to check and refine generic resource
assumptions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 270 of 1069
Resource Updates from 2009 IRP
Focusing on resource options identified in the 6th Power Plan
Lancaster PPA began serving Avista Utilities load on January 1, 2010
150 MW of Northwest based wind in the 2009 Preferred Resource Strategy
has been postponed
Noxon Rapids Unit #3 upgrade completed in April 2010; Unit #2 and #4
upgrades scheduled for April 2011 and April 2012
Started work on the Nine Mile upgrade
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 271 of 1069
Natural Gas-Fired Resources
Resource
Type
First
Year
Size
(MW)
Levelized
Overnight Costs
(2012 $/MWh) *
Capital Cost
Excludes AFUDC
(Nominal 2012)
SCCT (aero)2014 46 $106 $1,033/kW
SCCT (frame)2014 83 $114 $591/kW
Hybrid SCCT 2014 94 $103 $1,107/kW
CCCT (air)2016 270 $88 $1,105/kW
CCCT (water)2016 275 $85 $1,053/kW
Small
Cogeneration
2015 5 $112 $3,472/kW
Reciprocating
Engine
2014 99 $111 $1,139 /kW
* Prices are based on a preliminary gas price forecast
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 272 of 1069
Other Thermal Resources
Resource Type First
Year
Size
(MW)
Levelized
Overnight
Costs
(2012
$/MWh)
Capital Cost
Excludes AFUDC
(Nominal 2012)
Coal (Ultra-critical)2018 300 $123 $3,250/kW
Coal (IGCC)2014 300 $138 $3,252/kW
Coal (IGCC
w/sequestration)
2018 250 $156 $4,722/kW
Nuclear 2021 500 $150 $5,802/kW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 273 of 1069
Renewable Resources
Resource
Type
First
Year
Size
(MW)
Levelized
Overnight Costs
(2012 $/MWh)
Capital Cost
Excludes AFUDC
(Nominal 2012)
Wind 2016 50 $106 $1,951/kW
Geothermal 2017 15 $110 $4,463/kW
Wood
Biomass
2015 25 $166 $3,710/kW
Landfill Gas 2014 3.2 $60 $2,023/kW
Manure
Digester
2013 0.85 $111 $4,304/kW
Waste Water
Treatment
2014 0.85 $114 $4,304/kW
Solar
Photovoltaic
2014 5 $429 $7,140/kW
Solar Thermal 2016 25 $195 $4,751/kW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 274 of 1069
Avista Hydro Upgrades
Resource Type Year Size (MW)
Little Falls 1 Upgrade 2014 1.0
Little Falls 2 Upgrade 2015 1.0
Little Falls 3 Upgrade 2016 1.0
Little Falls 4 Upgrade 2017 1.0
Post Falls New Powerhouse TBD TBD
Upper Falls Upgrade 2019 2.0
Long Lake Second Powerhouse / Pumped Storage 2020 60
Long Lake Second Powerhouse 2020 50 –60
Cabinet Gorge Unit 5 2015 50
Monroe Street Unit 2 TBD 37.5
Cost estimates for these potential Avista resource upgrades will be presented at a
later TAC meeting after the estimates are further developed
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 275 of 1069
Reliability Planning
James Gall
Technical Advisory Committee Meeting #2
2011 Electric Integrated Resource Plan
September 9, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 276 of 1069
Overview
Objective
Develop a planning tool to help quantify the amount of resources need above expected peak
load
Why
A 15% capacity planning margin is currently added to forecast peak load. Without
conducting a statistical analysis regarding the probability of not serving all customer load and
reserve requirements, the 15% should be questioned- especially as variable generation is
added.
End Result
Determine load variation adder to include in long-term load & resource balance (In addition to
regulating reserves and regulating margin)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 277 of 1069
Modeling
8,760 hours for 800 potential outcomes (draws, games, iterations, etc)
This presentation includes 2012 and 2017
Other years of interest 2016, 2020, 2025, 2027
Randomizes: forced outages, temperature, loads, wind generation, and hydro conditions
Includes hydro constraints, short-term market purchases, and reserves including: within
hour load variation, variable resource reserves, and operating reserves
Can illustrate benefits of using demand response and federal hydro
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 278 of 1069
Load
Forced Outage
Rates
Historical
Temperatures
Thermal
Availability
Maintenance
Schedules
Wind
Randomization
Model
Hydro
Availability
Wind
Output
Demand
Response
Operating
Reserves
Net Power
Contracts
Thermal Capacity
Curves
Historical Water
Conditions
Reliability Model
Customer Appeal
Other DR Programs
Long-Term
Contracts + Short
Term Contract
Limits
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 279 of 1069
Loads
Load shapes are derived from historic daily high and low temperatures
Uses 120 years of Spokane temperatures
The average load of all iterations matches the energy load forecast
The average of the peak load is within the standard error of the peak load forecast
Hourly load forecast uses monthly regression model with coefficients:
–hour, day, temperature, and major weather event triggers
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 280 of 1069
Hydro
Randomly selects a hydro year between 1928 and 1999
Each hydro year includes monthly energy averages
Run-of-river facilities
–Monthly energy average is used for all hours of the month
–No shaping or reserves are assumed to be available
Storage facilities
– Monthly average generation equals the “drawn” hydro level
–In case of planned/forced outage, water can be spilled
–Linear program moves energy into hours needed to meet load
–Reservoir min and max levels, ramping rates, and daily limits are enforced
–Unused capacity is held as operating reserves
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 281 of 1069
Thermal
Plants are considered available rather than dispatched
Temperature dependency
–Gas-fired facilities use capacity based upon location temperature
–Temperatures are randomly drawn and are the same as the temperatures
used in the load calculation
Forced outages
–Input forced outage rate and mean-time-to-repair
–Outages occur randomly using a frequency and duration method
–Ramp rates are used following outages
Maintenance schedules
–Planned maintenance schedules are assumed
–Typical outages are in April though June
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 282 of 1069
Wind
Uses monthly on/off peak duration curves (see chart on left of January on-peak hours)
Random number selects position on curve
Following hour is correlated to previous hour using a correlation factor and variation
January On-Peak Wind Duration Curve January Hourly Simulated Wind Generation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 283 of 1069
Wind (continued)
Historical data from BPA control area shows generation is mitigated in below 32°F
and above 95° F. (see chart below on left)
Capacity factors are reduced at specified temps to model this phenomenon, (see
chart on right)
BPA Wind CF vs Spokane Temperatures Capacity Factor Adjustments for Specific Temperatures
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 284 of 1069
Demand Curtailment
Customer appeal
–Public appeal to all customers to conserve energy, radio/TV broadcasts
–Base case includes 25 MW reductions up to two times per year for hours
across the peak
Industrial process
–Not included in base case
–Designed to shift load from peak hours
Sensitivities studies can help determine value of programs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 285 of 1069
Reserves
Operating Reserves:
–5% hydro and 7% thermal are simplified to 6% of load minus market
purchases
–Simplification allows linearization of the objective function
Regulating Margin:
–1.6% of average hourly load level (based on historical average of max load
within hour versus average load)
–Capacity is for within hour load variations
Intermediate (Wind) Resource Regulation:
–Lesser of 10% of nameplate capacity or generation amount
Reserves are met by excess hydro capacity and thermal generation in excess of
load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 286 of 1069
Third Party Transactions
Long term firm power agreements are considered in the objective function
Short-term transactions are treated as available market purchase, no short-term
sales are considered
In tight market conditions (low or high temperatures) market availability is limited
to 300 MW on-peak and 500 MW off-peak.
In other market conditions the market availability is limited to 500 MW on-peak
and 750 MW off-peak.
Scenario analysis will be performed to understand the change in loss of load
given these assumptions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 287 of 1069
Objective Function
Load Serving
- Load [SM]
+ Available thermal capacity [RM]
+ Dispatched hydro capability [LP]
+ Wind generation [SM/RM]
+/- LT Contracts
+ Federal Hydro (optional)
+ Demand Curtailment (optional) [LP]
+ Market Purchases
>= 0 or event triggered
Operating Reserves
- Operating Reserve Requirement
- Intra-hour load regulation
- Wind regulation
+ Available thermal capacity
+ Unused hydro capacity
>= 0 or event triggered
SM: Stochastic Model
RM: Randomization Model
LP: Linear Program
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 288 of 1069
Metrics
Monthly and Annual Data
Loss of Load Probability (LOLP): percent of iterations with a reserve or load loss
–Calculation: iterations with event / # of iterations
–Metric: 5% or less
Loss of Load Hour (LOLH): expected number of hours each year with a load loss
–Calculation: total hours with event / (# of iterations)
–Metric: 0.24 (24 hours per 10 years)
Loss of Load Expectation (LOLE): expected number of days each year with a load
loss
–Calculation: Days with event / # of iterations
–Metric: 1 day in 10 years or 0.10 or less [or do we want 0.05, 1 in 20?]
Equivalent Unserved Energy (EUE): average MWh of lost load over a year
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 289 of 1069
2012 Assumptions
Noxon Rapids 4 is on maintenance Jan –mid March
300 MW on-peak market
No Federal hydro release
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 290 of 1069
2012 Draft Results Item
Annual
Results Target
LOLP 4.8%Below 5%
LOLH 0.255 Not below 0.24
LOLE 0.066 Below 0.10
EUE 38.47 TBD
Results Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Iterations
Load loss w/o reserves 7 2 3 0 0 0 2 1 0 0 0 1
Load loss w/ reserves 5 2 3 0 0 0 2 1 0 0 0 1
Reserve violatons 16 3 0 0 0 0 7 4 0 0 0 0
Total Load Loss or Reserve Violatons 20 5 3 0 0 0 7 5 0 0 0 1
LOLP 2.5%0.6%0.4%0.0%0.0%0.0%0.9%0.6%0.0%0.0%0.0%0.1%
Hours at Loss
Load loss w/o reserves 79 31 22 0 0 0 7 6 0 0 0 10
Load loss w/ reserves 64 27 20 0 0 0 6 6 0 0 0 8
Reserve violations 37 7 0 0 0 0 29 9 0 0 0 0
Total Load Loss or Reserve Violations 98 34 20 0 0 0 29 15 0 0 0 8
LOLH 0.12 0.04 0.03 - - - 0.04 0.02 - - - 0.01
Other Data
Reserves Used (MWh/Iterations)12 8 5 - - - 1 1 - - - 2
Unserved Energy (MWh/Iterations)14 8 6 - - - 1 1 - - - 3
Reserve Violations (MWh/Iterations)3 0 - - - - 2 0 - - - -
Unserved Energy (MWh/Iterations)2 0 1 - - - 0 0 - - - 0
EUE: Unserved Energy/Reserves (MWh/Iteratons)4.7 0.7 1.2 0.0 0.0 0.0 2.2 0.3 0.0 0.0 0.0 0.1
Market used (iterations)286 120 39 6 518 548 349 374 92 56 91 37
Market used (hours)5,100 1,450 968 19 5,785 6,136 4,072 8,246 1,179 727 2,055 332
Probability of market 35.8%15.0%4.9%0.8%64.8%68.5%43.6%46.8%11.5%7.0%11.4%4.6%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 291 of 1069
2012 Draft Results
(What if Noxon 4 was
not on Maintenance?)
Item
Annual
Results Target
LOLP 2.5%Below 5%
LOLH 0.14 Below 0.24
LOLE 0.035 Below 0.10
EUE 18.99 TBD
Results Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Iterations
Load loss w/o reserves 1 1 0 0 0 0 0 0 0 0 2 0
Load loss w/ reserves 1 1 0 0 0 0 0 0 0 0 2 0
Reserve violatons 7 0 0 0 1 0 4 2 1 0 0 2
Total Load Loss or Reserve Violatons 8 1 0 0 1 0 4 2 1 0 2 2
LOLP 1.0%0.1%0.0%0.0%0.1%0.0%0.5%0.3%0.1%0.0%0.3%0.3%
Hours at Loss
Load loss w/o reserves 54 13 0 0 0 0 0 0 0 0 9 0
Load loss w/ reserves 51 12 0 0 0 0 0 0 0 0 6 0
Reserve violations 15 0 0 0 2 0 10 8 2 0 0 6
Total Load Loss or Reserve Violations 66 12 0 0 2 0 10 8 2 0 6 6
LOLH 0.08 0.02 - - 0.00 - 0.01 0.01 0.00 - 0.01 0.01
Other Data
Reserves Used (MWh/Iterations)12 2 - - - - - - - - 1 -
Unserved Energy (MWh/Iterations)13 2 - - - - - - - - 1 -
Reserve Violations (MWh/Iterations)1 - - - 0 - 0 0 0 - - 0
Unserved Energy (MWh/Iterations)1 0 - - - - - - - - 0 -
EUE: Unserved Energy/Reserves (MWh/Iteratons)2.1 0.3 0.0 0.0 0.0 0.0 0.5 0.4 0.0 0.0 0.4 0.2
Market used (iterations)203 83 49 6 539 560 352 382 82 41 95 34
Market used (hours)3,954 1,110 985 8 5,712 5,971 3,822 8,183 1,039 485 2,353 267
Probability of market 25.4%10.4%6.1%0.8%67.4%70.0%44.0%47.8%10.3%5.1%11.9%4.3%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 292 of 1069
Results (DRAFT)
Study LOLP
(% of draws)
LOLH
(Avg un-served
hours)
LOLE
(Avg un-served
days)
EUE
(Avg Un-served
MWh)
2012 4.8%0.255 0.066 38.47
2012
(Noxon Available all Year)
2.5%0.140 0.035 18.99
2017
(with 150 MW wind)
1.5%0.099 0.019 20.75
2017
(No Wind)
1.9%0.110 0.028 20.17
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 293 of 1069
How Many Iterations Is Enough?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 294 of 1069
Next Steps For Reliability Planning
Study additional years
Re-evaluate number of draws
Run scenarios for different market availability amounts, demand curtailment,
and wind penetration
Evaluate moving model from Excel/WB to a different platform to increase speed
Lock down acceptable metrics for load loss
Develop new planning margin based upon results of the study
More to come at a future TAC meeting
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 295 of 1069
Avista’s 2010 Sustainability Report
TAC Presentation
SEPT. 9, 2010
“To be persuasive, we must be believable; to be believable, we must be credible; to be
credible, we must be truthful.”
Edward R. Murrow
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 296 of 1069
Our commitment to sustainability:
Avista’s goal is to provide energy for today’s customers while
preserving the ability of future generations to do the same.
We strive to engage our stakeholders --customers, investors,
employees, communities and others –in achieving this goal.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 297 of 1069
Why do a Corporate Sustainability Report?
•Trust and transparency have been found to be as important to corporate
reputation as service quality.
•CSR is a means to provide enterprise-wide information in a single location
about our company’s strategies and actions impacting people, planet and
performance –topics key to building trust.
•An increasing number of investors, customers and other stakeholders and
prospective employee are looking for this information.
0
20
40
60
80
100
2008
2004
# of S&P 100 companies including
web-based sustainability information
0
20
40
60
80
2008
2007
# of S&P 100 companies producing
formal sustainability reports
“The time has come to usher in a new era…of responsibility.”
President Barak Obama
Source: Social Investment Forum, Dec. 2009)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 298 of 1069
Objectives of Avista’s Sustainability Report:
•Be a launch pad for initiating stakeholder conversations and
enhancing engagement, internally and externally
•Provide information about Avista’s environmental, operations,
governance and socially responsible programs and actions and
business practices
•Act as a catalyst for internal strategy and goal setting
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 299 of 1069
What goes into a sustainability report?
•Sustainability Action Team –Internal, cross-enterprise
Environmental, Safety, Production & Generation, DSM/Energy Solutions, Power Supply,
Facilities, Supply Chain, Human Resources, Finance, Corporate Communications
•Prioritizing topics for inclusion
Assess stakeholder interest
Assess society’s interest
Determine business position
Determine impact on reputation
Public or reportable information
•Structure of the report
•Distribution of the report
113 Performance
indicators reported on
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 300 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 301 of 1069
Considerations for Future Sustainability Reporting
•Review of 2010 report by GRI
• Determine project’s scope and direction and align these with
Avista’s strategic direction
•Initiate in-depth conversations with departments across the
company to determine additional reporting and data assurance
opportunities
•Expand the number of external stakeholders who give feedback on
the report
• Increase the visibility of Avista’s sustainability report and practices
across stakeholders and other audiences without “green washing”
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 302 of 1069
Materiality: Which information to Include?
High
HighLow
Im
p
o
r
t
a
n
c
e

t
o

S
t
a
k
e
h
o
l
d
e
r
s
Relevance for Avista
Avista’s Energy Efficiency
Biodiversity
Corporate Citizenship
Customer Satisfaction
Direct Use of Natural Gas
DSM Programs
Employee Satisfaction
Energy Security
Environmental Performance
Ethical Business Practices
Executive Compensation
Financial Performance
GHG Footprint
Global Climate Change
Governance
Human Resources
NGO Relations
Public Policy
Rates
Resource Planning
Safety
Stakeholder Engagement
System Reliability
Supply Chain
Waste Discharge
Water use
Work Force Diversity
Topics to Consider
Others??
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 303 of 1069
Cogeneration Case Study
Thomas C. Dempsey, PE
Manager Generation Joint Projects
Technical Advisory Committee Meeting #2
2011 Electric Integrated Resource Plan
September 9, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 304 of 1069
Cogeneration
“Cogeneration is the use of a heat engine or a power
station to simultaneously generate both electricity and
useful heat.”- Wikipedia
“A combined cycle is characteristic of a power producing
engine or plant that employs more than one
thermodynamic cycle”-Wikipedia
Cogeneration= Power [kW]+ Heat [Btu/hr]
Combined Cycle = Gas Turbine Power [kW] + Steam Turbine Power [kW]
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 305 of 1069
Cogeneration Design
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 306 of 1069
Efficiency of a Combined Cycle Plant
Efficiency = What you get/What you pay for
Heat Rate = What you pay for/What you get
Heat Rate = 1/Efficiency
How does the efficiency of a combined cycle plant compare with that of a cogeneration facility?
Shown below are numbers typical to advanced combined cycle combustion turbine facilities.
What we pay for is the fuel expressed in terms of British Thermal Units [Btu’s]. What we “get” is
electrical energy expressed in terms of kilowatt-hours [kWh’s]. Advanced combined cycle
turbines have higher heating value net efficiencies around 50%.
%503412
6800
1
1
kWh
Btu
kWh
BtuncycleEfficieCombinedCy
eNetHeatRatncycleEfficieCombinedCy
NOTE: Btu’s and kWh’s are both units of “energy”. We multiply by the unit conversion
factor of 3412 in order to arrive at a dimensionless number which we can express as
percent.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 307 of 1069
Efficiency of a Cogeneration Facility
Efficiency = What you get/What you pay for
There are many ways of looking at the efficiency of a cogeneration facility. The calculation below
is calculated strictly in terms of useful energy divided by fuel energy. For the example turbine
modeled, the thermal efficiency as calculated below is much higher than the thermal
efficiency for my example combined cycle plant.
%75
78808
35606412.36801
EfficiencyCogenCycle
h
kBtu h
kBtu
kWh
kBtukW
EfficiencyCogenCycle
Fuel
HeatyElectricitiencyCogenEffic
NOTE: Solar Taurus 70, Spokane Elevation, 150 psig steam, no duct firing
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 308 of 1069
Comparing Combined Cycle with Cogen on Equivalent Terms
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 309 of 1069
Comparing Combined Cycle with Cogen on Equivalent Terms
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 310 of 1069
Comparing Combined Cycle with Cogen on Equivalent Terms
For this example, the cogen facility uses only 87.8% if the gas that would be used by a
combined cycle plant in conjunction with an auxiliary boiler to produce steam. At a gas price
of $4.00 per Million Btu, the combined cycle would incur an additional $6.40 per MWh in fuel
costs. In most cases this magnitude of reduction in costs is not enough to overcome the low
economies of scale and other costs associated with cogen.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 311 of 1069
Cogeneration Fuel Savings in Context
•At $4.00 per MMBtu, this cogen case shows a reduction of $6.40/MWh in fuel costs.
•For an 80% capacity factor, maintaining 5 additional employees to operate the
cogen facility around the clock will cost approximately $10.00/MWh (only 1 employee
on shift most of the time). Labor costs for the combined cycle facility will be on the
order of $2.50 per MWh due to enormous economies of scale effects.
•Maintenance costs for the cogen facility will be on the order of $4-$7 per MWh more
than that of the combined cycle facility.
•Capital cost recovery on a per MWh basis is significantly higher for the cogen facility
due to economy of scale effects.
•In the Pacific Northwest there are significant periods every year where it is
uneconomic to run due to hydro run-off. A cogen facility would either have to run
during uneconomic times or the plant would have to have complete redundancy with
gas fired boilers.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 312 of 1069
Energy Efficiency Approach for the 2011
Electric Integrated Resource Plan
Lori Hermanson
Technical Advisory Committee Meeting #2
2011 Electric Integrated Resource Plan
September 9, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 313 of 1069
Evolvement of Energy Efficiency
Growth in annual tariff rider funding and program offerings over the last 10
years
–Five times more electric funding
–Nearly 12 times more natural gas funding
Heightened regulatory requirements and increasing amounts of Evaluation,
Measurement & Verification (EM&V)
–Annual electric (I-937 conditions) and natural gas verification of savings
(Washington decoupling)
–EM&V Collaborative as required by the Washington Utilities and
Transportation Commission (WUTC) –final paper filed 9/1/10
–WUTC required 3-6% of conservation budget on EM&V
IRP action item and one of the I-937 conditions –potential studies every two
years
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 314 of 1069
Approach for Estimating Energy Efficiency Potential
Energy Market
Profiles
by end use, fuel,
segment and vintage
Customer surveys
Utility data
Secondary data
Forecast data:
Customer growth
Price forecast
Purchase shares
Codes and standards
EE measure list
Measure costs
Energy analysis to
estimate savings
Develop prototypes and
perform energy analysis
Baseline Forecast
by End Use
EE Potential
Midwest Residential (305 TWh)
Space heat
7%
Air conditioning
12%
Water Heat
6%
Refrigeration
9%
Cooking
2%
Dryers
6%
Freezers
2%
Lighting
16%Washers
1%
Dishwashers
2%
Color TV
8%
PCs
2%
Furnace Fans
3%
Other Uses
24%
Technical
Potential Economic
Potential Maximum
Achievable
Potential
Realistic
Achievable
Potential
201020202030
2008 2010 2020 2030
An
n
u
a
l

E
l
e
c
t
r
i
c

I
n
t
e
n
s
i
t
y

(
k
W
h
/
h
h
)
Base-year Energy
Consumption
by state, fuel and
sector
Utility data
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 315 of 1069
Global Energy Partners LoadMAPTM Analysis Framework
(Load Management Analysis and Planning tool)
Market Profiles
Base-year Energy
Consumption
by technology,
end use, segment,
vintage & sector
Forecast Results
Market size
Equipment saturation
Fuel shares
Technology shares
Vintage distribution
Unit energy consumption
Coincident demand
Customer segmentation
Forecast Data
Economic Data
Customer growth
Energy prices
Exogenous factors
Elasticities
Technology Data
Efficiency options
Codes and standards
Purchase shares
Energy-efficiency
analysis
List of measures
Saturations
Adoption rates
Avoided costs
Cost-effectiveness
screening
Baseline forecast
Savings
Estimates
(Annual & peak)
Technical potential
Economic potential
Achievable potential
Energy-efficiency
forecasts:
Technical
Economic
Achievable
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 316 of 1069
Market Segmentation for Energy Efficiency
State and fuels
By sectors
–Residential
•Limited Income
•Single-family housing
•Multifamily housing
•Mobile homes and manufactured housing
–Commercial and industrial by rate class
–Pumping
Vintage (retrofit vs. lost-opportunity)
Appliances/end uses (space heat, cooling, lighting, water heat, motors) and
technologies (lamps, chillers, color TVs, etc)
Equipment efficiency (old, standard, high efficiency)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 317 of 1069
Market Segmentation for Demand Response
State
Energy metric (peak demand) for annual, summer and winter
Sector
–Residential
–Commercial and industrial combined
Appliances/end uses (space heat, cooling, water heat, process, other)
Enabling technology (with and without enabling technology)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 318 of 1069
Energy Market Profile Example: Residential
End Use Technology Saturation UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 86%3,985 3,433 1,587
Cooling Room AC 13%3,188 410 190
Space Heating Electric Resistance 5%18,214 910 421
Space Heating Electric Furnace 0%18,943 --
Combined Heat/CoolAir Source Heat Pump 13%14,004 1,820 842
Combined Heat/CoolGeo-Thermal Heat Pump 0%9,242 --
Water Heating Water Heater 24%2,793 663 307
Interior Lighting Screw-in 100%1,242 1,242 574
Interior Lighting Linear Fluorescent 100%243 243 112
Exterior Lighting Screw-in 85%374 318 147
Exterior Lighting Linear Fluorescent 85%73 62 29
Appliances Refrigerator 100%891 891 412
Appliances Freezer 42%376 157 73
Appliances Second Refrigerator 20%1,326 265 123
Appliances Clothes Washer 96%561 540 250
Appliances Clothes Dryer 84%821 693 321
Appliances Combined Washer/Dryer 0%786 --
Appliances Dishwasher 61%173 105 49
Appliances Cooking 71%750 533 247
Electronics Personal Computer 65%470 306 142
Electronics Color TV 96%313 300 139
Electronics Other Electronics 100%343 343 159
Miscellaneous Pool Pump 13%2,671 339 157
Miscellaneous Furnace Fan 68%431 293 136
Miscellaneous Other Miscellaneous 100%194 194 90
Total 14,069 6,505
Cooling
26%
Space Heating
11%
Combined
Heating/Cooling
11%
Water Heating
6%
Interior
Lighting
10%
Exterior Lighting
3%
Appliances
21%
Electronics
7%
Miscellaneous
5%
End-use shares of total
residential sector use
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 319 of 1069
Baseline End-Use Forecast
Definition of baseline forecast:
Comprehensive end-use forecast
Forecast without future utility programs
Incorporates appliance standards and building codes already on the books
Typically includes naturally occurring efficiency (consistent with 6th Plan)
Process for developing the baseline forecast
1.End-use segmentation
2.Energy market profiles –snapshot of current energy use
3.Technologies/efficiency options available today and in the future
4.Forecast data and assumptions
5.Assess and compare with existing forecasts
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 320 of 1069
End-Use Segmentation Example
Residential Commercial Industrial
Cooling Cooling Process Heating
Central AC Central Chiller Electric resistance
Room AC Packaged AC Radio frequency
Space Heating PTAC Process Cooling and Refrigeration
Electric Resistance Space Heating Machine Drive
Electric Furnace Electric Resistance 1-5 hp motors
Combined Heating/Cooling Combined Heating/Cooling 5-20 hp motors
Air Source Heat Pump Air Source Heat Pump 20-50 hp motors
Geothermal Heat Pump Geohermal Heat Pump 50-100 hp motors
Water Heating Water Heating 100-200 hp motors
Interior Lighting Interior Lighting 200-500 hp motors
Screw-in Screw-in 500-1,000 hp motors
Linear Fluorescent Linear Fluorescent 1,000-2,500 hp motors
Exterior Lighting Exterior Lighting >2,500 hp motors
Screw-in Screw-in Facility HVAC
Linear Fluorescent Linear Fluorescent Facility lighting
Appliances Refrigeration Incandescent
Refrigerator Walk-in Refrigeration Fluorescent
Freezer Reach-in Refrigeration HID
Clothes Washer Office Equipment
Clothes Dryer PC
Combined Washer/Dryer Server
Dishwasher Monitor
Cooking Printer/Copier
Electronics Food Service
Personal Computer Ventilation
Color TV Miscellaneous
Other Electronics
Miscellaneous
Pool Pump
Furnace Fan
Other Miscellaneous
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 321 of 1069
Energy Market Profiles
Description
Energy market profiles describe how customers use
energy in a recent base year
Market profile elements
Market size
Fuel shares/saturations by end use
Unit energy consumption (UECs, EUIs) by end
use/tech
Peak factors
Profile elements are calibrated to match customer
segments’ use in base year from billing system
Key data sources
Market characterization data
Previous potential studies
Global’s previous customer surveys
Prototypes and BESTTM analysis
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 322 of 1069
Forecast Data and Assumptions
Forecast drivers
Customer growth
Other exogenous variables
Energy prices
Income
Usage elasticities by end use for each
exogenous variable
Technology forecasts
Equipment purchase shares by decision type
Replace on burnout
New construction
Non-owner acquisition
Shares are user defined
Defaults based on trends in EIA’s Annual
Energy Outlook
Incorporate existing appliance/equipment
standards
Will be refined using PNW and Avista data
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 323 of 1069
Sample Baseline Forecast for Residential Sector
Residential Use by End Use (GWh)
2007 2010 2012 2015 2018 % Change
Avg.
growth
rate
Cooling 2,093 2,128 2,151 2,186 2,227 6.4%0.56%
Space Heating 862 863 864 867 871 1.1%0.10%
Combined Heating/Cooling 883 923 951 989 1,029 16.5%1.39%
Water Heating 482 495 503 515 528 9.7%0.84%
Interior Lighting 858 872 880 840 802 -6.6%-0.62%
Exterior Lighting 215 215 215 202 189 -11.8%-1.14%
Appliances 1,711 1,741 1,760 1,787 1,816 6.1%0.54%
Electronics 578 616 641 679 718 24.2%1.97%
Miscellaneous 412 423 430 441 453 9.9%0.86%
Total 8,093 8,274 8,395 8,506 8,633 6.7%0.59%
Residential Use in the Base Year (2007)Residential Forecast (GWh)
Cooling
26%
Space Heating
11%
Combined
Heating/Cooling
11%
Water Heating
6%
Interior
Lighting
10%
Exterior Lighting
3%
Appliances
21%
Electronics
7%
Miscellaneous
5%
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
2007 2010 2012 2015 2018
An
n
u
a
l

U
s
e

(
G
W
h
)
Cooling
Space Heating
Combined Heating/Cooling
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 324 of 1069
Energy Efficiency Potential
1.Characterize energy efficiency measures
2.Perform economic screen
3.Assemble data for estimating achievable potential
4.Calculate potential
5.Develop supply curves based on levelized costs of each
individual measure (low, medium, high-case potential
differentiations)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 325 of 1069
Definitions of Energy Efficiency Potential
Technical Potential –most efficient measures are adopted,
regardless of cost or customer acceptance
Economic Potential –only cost-effective measures are adopted by
customers
Apply TRC test
Avista avoided costs + 10% conservation adder (consistent with 6th
Plan)
Achievable Potential
Council’s definition –85% of economic potential at the end of ten years
Other definition?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 326 of 1069
Estimate Demand Response Potential
Develop revised peak demand forecast
–After savings from EE are applied
Identify capacity-constraint time period
–Winter peak day (cold weather)
–Summer peak day (hot weather)
Identify and characterize relevant DR options (e.g., direct load
control, curtailable/interruptible tariffs, demand bidding)
Estimate potentials
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 327 of 1069
Estimating Demand Response Potential
Develop baseline forecast by segment
–Peak by segment
–Customer by segment
Program data
–Participants in base year
–Forecast of participants
–Per customer impacts in base year
Assess cost effectiveness
Compute peak reduction
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 328 of 1069
Deliverables that Feed IRP Process
Report documenting entire study and presentation to Avista (electric
–October, natural gas 2011)
LoadMAP, fully populated for future updates
Updated avoided costs from Aurora available in November as well
as updated load and price forecasts
Updated potentials for energy efficiency and demand response for
final input in model
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 329 of 1069
Potential Study Timeline
Month August September October Nov Dec Jan Feb March AprilWeek123412341234
Kick-off meeting M
Final work plan t
Gather data
Electricity Analysis
Market characterization t
Baseline forecasts t
EE measure list t
Preliminary potential estimates M
Final potential estimates t
Draft report w/supply curves R
Demand Response Analysis
Market characterization t
Baseline forecasts t
Identify DR programs M
Preliminary potential estimates t
Draft report R
Natural Gas Analysis
EE measure analysis t
Baseline forecasts t
EE measure list t
Preliminary potential estimates tM
Final potential estimates t
Draft report R
Final Report (on all analyses)R, M
Meetings (in-person or webcast)M
Memos, interim deliverables t
Reports R
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 330 of 1069
Avista’s 2011 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 3 Agenda
Avista Headquarters – Spokane, Washington

Thursday, December 2, 2010
Avista Conference Room 428

Topic Time Staff
1. Introduction 9:00 Storro

2. Transmission (costs & issues) 9:05 Waples

3. Potential Hydro Upgrades 10:00 Wenke

4. Potential Thermal Upgrades 10:45 Graham

5. Lunch 11:30

6. Load Forecast 12:30 Barcus

7. Stochastic Modeling 1:30 Gall

8. Adjourn 2:30

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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 331 of 1069
New Resource Integration –Transmission
Executive Level Summary of Avista 2010 Resource Integration Study Work
Scott Waples, Reuben Arts, and the Avista System Planning Group
Technical Advisory Committee Meeting #3
2011 Electric Integrated Resource Plan
December 2nd, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 332 of 1069
Federal Standards of Conduct
Mandatory Federal Standards of Conduct Require That:
No non-public transmission information be shared with the
Avista Merchant Function.
Please note that there are Avista Merchant Personnel in
attendance at this meeting.
Meeting Notices:
This meeting was Posted on the Avista OASIS website on
11/19/2010.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 333 of 1069
Federal Standards, Requirements, and Risks
Mandatory Federal Standards Include:
No overloads all lines and equipment in service (N-0).
No overloads or loss of load for one element out of service (N-1).
Some relaxation of the above for two elements out (N-2).
Resource Integration requirements (Avista or 3rd party generation)
are the same as those for the general system –all Standards
must be met.
Potential Sanctions:
Up to $1M Per Day Per Occurrence.
Mitigation Plan must be provided and progress demonstrated.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 334 of 1069
Recent Examples of Avista Construction
Benewah Station:
230 / 115 kV Station with a Single 125 MVA Transformer.
230 kV Connections between the North and South Avista
Load Centers.
230 kV Double Breaker / Double Bus Configuration for
increased reliability.
Benewah –Shawnee 230 kV line:
Completes transmission required for both load service and
the West of Hatwai transfer requirements.
Allows for resource integration in the center and south areas
of the Avista system.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 335 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 336 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 337 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 338 of 1069
Examples of Future Construction Required to Meet
NERC / WECC Reliability Standards
Moscow Station:
230 / 115 kV Station, single 250 MVA transformer.
Increases capacity to the Moscow / Pullman area and
relieves loading on the Shawnee transformer.
Westside Station:
230 / 115 kV Station, two 250 MVA transformers.
Increases capacity and security to the West Plains area of
Spokane County, and relieves heavy loading on large
transformers in the central Spokane area.
Irvin 115 kV and Associated 115 kV Reconductoring:
115 kV Switching Station and other upgrades to meet
additional load growth in the Spokane Valley.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 339 of 1069
Westside Rebuild –2 x 250 MVA Transformers
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 340 of 1069
Moscow 230/115 kV Estimate and Schedule
2010 2011 2012 2013 2014 total
Transmission $575,000 $575,000 $1,150,000
Substation $500,000 $1,500,000 $3,000,000 $4,775,000 $2,750,000 $12,525,000
Distribution $25,000 $25,000
total $500,000 $1,500,000 $3,000,000 $5,350,000 $3,350,000 $13,700,000
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 341 of 1069
Irvin Project
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 342 of 1069
Avista Non-IRP Generation Queue
Active (see http://www.oatioasis.com/avat/index.html):
Project # 08:
–75 MW, in Facility Study Stage.
Project # 14:
–210 MW, in System Impact Study Stage (SIS).
Project #17:
–100 MW, in Facility Study Stage.
Project # 26:
–42MW, in SIS Stage.
Project # 27:
–10 MW, in SIS Stage.
Project # 29:
–6.5 MW, in SIS Stage.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 343 of 1069
Non-coincident IRP Interconnection Requests
Potential West Plains / Devils Gap Integration :
Reardan:
–90 MW, 2014
–+60 MW (150 MW total), 2014
Long Lake:
–+ 30 MW (118 MW total), 2018
–+ 60 MW (148 MW total), 2018
–+ 100 MW (188 MW total), 2018
Little Falls:
–+ 4MW (40 total), 2014-2017
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 344 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 345 of 1069
Non-coincident IRP Interconnection Requests
Potential “Far West” (Big Bend) Area Integration :
Othello Area:
–Up to 100 MW in 2014, 2015, or 2019 (2015
energization is the most probable)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 346 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 347 of 1069
Non-coincident IRP Interconnection Requests
Potential “Central Area” Thermal or Wind Integration :
Benewah:
–300 MW 2018
Rosalia:
–300 MW, 2018
Potential “East & North Area” Thermal or Wind Integration :
Rathdrum:
–300 MW, 2018
–+ 100 MW (400 MW total), 2018
Sandpoint:
–100-300 MW, 2018
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 348 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 349 of 1069
Non-coincident IRP Interconnection Requests
Other “Large” Hydro Integration :
Cabinet Gorge (“East”): + 60 MW, 2018
Monroe Street (Spokane): + 20MW, 2018 or +60 MW, 2018
Post Falls (Coeur d’ Alene): + 14 MW, 2018
“Small” Hydro Integration :
Upper Falls (Spokane): + 2 MW, 2019
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 350 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 351 of 1069
Study Process and Cost Estimates
Study Process:
Avista System Planning does transmission system analysis
using WECC approved “study cases” (which we modify) for
all analyses and uses approved software tools (PTI, GE,
PowerWorld) to “do the math” on various alternatives.
Pre-Engineering Cost Estimates:
Avista Engineering does pre-engineering cost estimation.
Estimates are generally plus or minus 50% accuracy (no
rights-of-way, soils analysis, firm quotes for equipment, etc.).
Transmission integration is often about 10% of total project
costs (but can be much higher depending on where the
resource is integrated).
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 352 of 1069
Transmission Study Process With Respect to Resource Type
“We (Transmission) Don’t Care”!
Transmission Analysis is “Resource Blind”:
–Wind
–Water
–Gas
–Pumped Storage
–Other
Transmission Integration Costs Will be the Same for
ANY Resource.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 353 of 1069
West Plains / Devils Gap Area
Necessitates a “Tipping Point” Analysis:
Total potential generation is 4 MW to 254 MW –lots of options!
Voltage Level Analysis:
–How much can be integrated at 115 kV:
o At no cost?
o At a “max 115 kV development” cost?
–How much can be integrated at 230 kV:
o Can it be done with only one 230 kV line?
o What are the costs for one versus two lines?
What are the $/MW costs for the various options?
(Need a map from John…)Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 354 of 1069
West Plains / Devils Gap Area
115 kV Analysis:
4 MW requires no transmission additions (one bookend).
75 MW can be integrated for about $15M.
Requires new 115 kV line and station upgrades.
230 kV Analysis:
254 MW can be added for about $30-$55M (2-230 kV lines).
These costs don’t include the planned 230 kV Spokane Loop.
“All Things Being Equal” $$/MW Comparison:
75 MW @ 115 kV @ $15M => $200/kW
254 MW @ 230 kV @ $30-$55M => $118-$217/kW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 355 of 1069
“Central” and “East” Areas
230 kV Integration:
Benewah: 300 MW @ about $5M
Rosalia: 300 MW @ about $8M
Rathdrum:
–300 MW @ about $5M (Will require Gen Dropping).
–400 MW @ about $5M (Will require Gen Dropping).
– A concern is “too many eggs” on the Rathdrum Prairie:
o Existing Rathdrum –160 MW.
o Existing Lancaster –270 MW.
o New Rathdrum –300-400 MW.
All studies are post integration of the Lancaster generation
into the Avista 230 kV system.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 356 of 1069
“Far West” (Big Bend) Area
Othello 115 kV Analysis:
17 MW requires no transmission additions (one bookend).
100 MW can be integrated for between $13-$25M.
Requires new 115 kV line, local 115 kV line reconductor,
and a new POI 115 kV substation (the lower costs require
generator dropping).
230 kV Analysis:
250 MW can be added for about $8M.
Requires a new POI 230 kV substation.
Does not consider contractual constraints on the Walla
Walla –Wanapum 230 kV line
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 357 of 1069
“North” and Other Hydro
Sandpoint, Idaho:
Sandpoint: 50 MW @ about $2-5M (depending on BPA).
More than 50 MW is probably cost prohibitive.
Other “Large” Hydro:
Cabinet Gorge: 60 MW @ about $2-$10M (Cabinet Gorge –
Rathdrum @ 100 Degrees Centigrade & 115 kV reconductor).
Monroe Street: 20 MW @ about $3M (does not include Metro).
Monroe Street: 60MW @ about $3M (as above).
Post Falls: 14 MW @ about $1M
Other “Small” Hydro Integration :
Upper Falls: 2 MW @ about $1M
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 358 of 1069
“Off System” Resources
Integration of 100-300 MW:
Potential at Bell, Hatwai, Hot Springs, or Mid Columbia:
Wheeling over the BPA system presently costs $4.4M/year
plus $2.5M/year for losses (@$50/MW-hr) for 300 MW of BPA
transmission service (if it is available). The BPA rate is
expected to increase by about 9% in 2013. A BPA “Lines and
Loads” Study (funded by AVA) is required to determine
capacity in the BPA Grid.
A study similar to the FERC “Market Power Study” is used to
determine at what cost these resources could be integrated
into the Avista Grid. Recent studies have indicated that as
much as $50M could be required for 300 MW of integration
from BPA into the Avista system.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 359 of 1069
Future Work?
Generic Break Point Studies for IRP / 3rd Party Developers:
“How many MW can we integrate where for about what $$?”
–Main Grid 230 kV Stations.
–Select 115 kV Stations.
Potential Open Seasons:
“Does anyone want to get to the Mid Columbia?”
“Does anyone want to get out of Montana?”
“Does anyone want to get to PAC or IPC?”
Canada –Northwest –California Transmission Project:
“If this project is built, how should we interconnect?”
“What other markets would this project access?”
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 360 of 1069
Finis
Questions?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 361 of 1069
Hydro Upgrade Opportunities
Steve Wenke
Technical Advisory Committee Meeting #3
2011 Electric Integrated Resource Plan
December 2, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 362 of 1069
Presentation Outline
Background of Avista’s Hydro System
Looking Back on What has Been Done
Current Upgrade Projects
Other Opportunities
Issues
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 363 of 1069
Background
Aging hydro system
Advancements in hydro turbine technology
Hydraulic size of facilities
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 364 of 1069
Avista’s Hydro Portfolio
First project was Monroe Street that came on line in 1891.
“Newest” Spokane River plant is Upper Falls which came on line
in 1920.
The larger Clark Fork River projects were developed in the mid to
late 1950’s
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 365 of 1069
Aging Technology
Modern turbine designs convert the energy of falling water at a rate
of about 94% efficiency
Combined Cycle Gas Plant –52%
Wind Turbine 40-50%
1960 and earlier vintage hydro plants have efficiencies of abut 88%
or lower
Estimate 80% at Upper Falls
Estimate 85% at Little Falls
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 366 of 1069
Plant Hydraulic Designs
The older Spokane River Plants were sized based on the needs of
the day
Base loaded energy
Ability to swing output to make loads (i.e. regulation)
Generator island areas (i.e. generator were not networked
together)
The result are plants that are relatively high on the flow exceedence
curves
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 367 of 1069
The Opportunity
In simple terms, with unit flow capacity (cfs) and plant head (height of
dam) the same, we should be able to improve the energy output of an
older hydro unit by as much as 6% by replacing the old turbine with a
modern designed unit.
In fact, this does vary for each particular site based on the civil works
of the specific dams
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 368 of 1069
Plant Hydraulic Designs
0
5
10
15
20
25
30
35
40
45
0 10 20 30 40 50 60 70 80 90 100
Upper Falls
Monroe Street
Post Falls
Long Lake
Nine Mile
Little Falls
Modern Design
Target Flows
Flow Duration Curve for Long Lake HED
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 369 of 1069
Noxon Rapids Upgrades
Variable Efficiency Curves
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 370 of 1069
New Runner Comparison
Noxon Unit Efficiency
84
86
88
90
92
94
80 85 90 95 100
MW Output
%
E
f
f
i
c
i
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n
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Unit 1
Unit 2
Unit 3
Unit 4
New
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 371 of 1069
Looking Back
We have been actively pursuing hydro upgrades since 1989
Monroe Street -1992
Nine Mile Units 3 and 4 -1994
Cabinet Gorge Unit 1 -1994
Long Lake Units 1, 2, 3, and 4 –1994 -1999
Little Falls Units 2 and 4 –1994, 2001
Cabinet Gorge Units 2, 3, and 4 –2001 –2004
Noxon Rapids Units 1, 3 2009, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 372 of 1069
Character of the Upgrades
Powerhouse Replacement
Powerhouse Refurbishment and Unit Replacement
Runner Replacement
Unit Replacement
Powerhouse Additions
To this point in time, we have not added new powerhouse
additions to existing facilities
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 373 of 1069
What we have done to date:
Energy (GWh’s)
-
100
200
300
400
500
600
700
800
900
0
20
40
60
80
100
120
140
160
180
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 374 of 1069
What we have done to date:Added Hydro Capacity (MW’s)
-
50
100
150
200
250
300
350
400
0
10
20
30
40
50
60
70
Mo
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 375 of 1069
Summary
Over the past 20 years, we have added 334,000 MWh’s and 120
MW’s of hydro to our system
We are currently planning to add an estimated 49,000 MWh’s and
48 MW’s
There are considerations for an additional 116,000 MWh’s and
176 MW’s
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 376 of 1069
Current Projects
Little Falls Refurbishment
Nine Mile Redevelopment
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 377 of 1069
Little Falls Upgrade
Seeking an increase in turbine
efficiency
Current estimated efficiency is
80%
Upgraded runners are expected to
be 85%
Approximately 2 MW improvement
expected
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 378 of 1069
Little Falls Upgrade
General Scope of work would
include replacement of all of
the old equipment at the plant
–a major undertaking
Photo Showing New Turbine Runners
Being installed in Unit 4 in 2001
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 379 of 1069
Little Falls Upgrade
Expected additional Capacity –2 MW
Expected additional Energy –8,760 MWh
Estimated Costs - $1.5 million
Other Considerations:
–Much of the existing equipment is at the end of its service life
and will likely be replaced, significantly increasing the scope of
this project work.
–We have yet to explore expansion plans for this site, and may
elect to do so.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 380 of 1069
Nine Mile Redevelopment
This project is to replace
Units 1 and 2. These are
original 1908 machines and
are no longer repairable.
The basic scope is to
remove the old systems
and install new turbines,
generators, switchgear,
and controls to update the
plant.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 381 of 1069
Nine Mile Redevelopment
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 382 of 1069
Nine Mile Redevelopment
Expected additional Capacity –16 MW
Expected additional Energy –11,800 MWh
Estimated Costs - $38 million
Other Considerations:
–This addresses Units 1 and 2. Units 3 and 4 were replaced in
the 1994.
–Sediment buildup in the river needs to be addressed.
–Existing balance of plant equipment is also to be replaced with
this project work
–We just completed a “Obermeyer Gate” installation to eliminate
the flashboard system
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 383 of 1069
Nine Mile Sediment Impacts
Original Shoreline Main Channel
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 384 of 1069
Nine Mile Flashboard Replacement
From the 1940’s until last year, we
Would install wooden flashboards
On the dam to get an additional 10
Feet of head. Each spring these
Would be released and have to be
Replaced each year.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 385 of 1069
Nine Mile Obermeyer Gate
Inflatable Bladders
To control gates
Steel Plate
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 386 of 1069
Other Opportunities
Upper Falls Runner Replacement
Long Lake Second Powerhouse Addition
Cabinet Gorge Second Powerhouse Addition
Post Falls Refurbishment
Monroe Street Second Powerhouse Addition
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 387 of 1069
Upper Falls Runner Replacement
Seeking to increase the output
of the unit by replacing the
turbine runner and modifying
the existing draft tube to
improve efficiency.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 388 of 1069
Upper Falls Runner Replacement
General Scope of Work would
be to remove the old runner,
modify the draft tube, stay
vanes, and discharge area,
and install a new runner
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 389 of 1069
Upper Falls Runner Replacement
Expected additional Capacity -2 MW’s
Expected additional Energy 8,600 MWh’s
Estimated Costs - $6.8 million
Other Considerations:
–New license conditions have not yet been considered in this
options.
–Would require considerable modification to the existing draft
tube system
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 390 of 1069
Long Lake Second Powerhouse
Seek to increase plant capacity
by the addition of a second
powerhouse and large capacity
unit
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 391 of 1069
Long Lake Second Powerhouse
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 392 of 1069
Long Lake Second Powerhouse
Expected additional Capacity –60 - 120 MW
Expected additional Energy –158,000 –178,000 MWh
Estimated Costs - $120+ million
Other Considerations:
–Impacts of construction to the existing plant
–Condition of small arch dam to be used as a cofferdam
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 393 of 1069
Cabinet Gorge Second Powerhouse
Seek to increase plant capacity
by the addition of a second
powerhouse and match Noxon
Rapids flow capacity
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 394 of 1069
Cabinet Gorge Second Powerhouse
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 395 of 1069
Cabinet Gorge Second Powerhouse
Expected additional Capacity –50 MW
Expected additional Energy –57,000 MWh
Estimated Costs - $115 million
Other Considerations:
–This project would favorably impact the Total Dissolved Gas
(TDG) issue at Cabinet Gorge and is currently under
consideration by the Clark Fork License team.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 396 of 1069
Post Falls Refurbishment
This would involve removing all of
the old station equipment and
replacing it with new units. The
building exterior would remain
intact
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 397 of 1069
Post Falls Upgrade
The Scope is to remove the old horizontal units and replace them with
high efficiency and higher capacity vertical units
Existing Horizontal Unit Vertical Unit Configuration
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 398 of 1069
Post Falls Upgrade
Expected Additional Capacity – 19 MW’s
Expected additional Energy –33,000 MWh’s
Estimated Costs - $75 million
Other Considerations:
–Need to evaluate this plan against new license conditions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 399 of 1069
Monroe Street Second Powerhouse
The basic project here is to
harness the capacity of the 140
waterfall that the Spokane River
drops in downtown Spokane
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 400 of 1069
Monroe Street Second Powerhouse
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 401 of 1069
Monroe Street Second Powerhouse
Expected Additional Capacity – 37.5 MW’s
Expected additional Energy –142,000 MWh’s
Estimated Costs - $95 million
Other Considerations:
–Downtown Spokane and Riverfront Park locations make this a
challenging option
–Would require a significant make over of the western edge of
Riverfront Park, and channel dredging
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 402 of 1069
Hydro Upgrades –Other Issues
Aging equipment is driving much of the work.
Gaining valuable experience for our work force
Current incentives for REC’s and tax incentives are playing a part
Needs for future capacity
Environmental Drivers
–Total Dissolved Gas –desire to reduce spill at some sites
–Needs for more modern plants with appropriate systems to
avoid possible releases
–Licenses have provided some certainty around investment
opportunities.
–Significant permit time for second powerhouse projects
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 403 of 1069
Potential Thermal Upgrades
Jason Graham
Generation Engineer
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 404 of 1069
Overview
•Conversion of Rathdrum CT to a Combined Cycle Power Plant
•Water Demineralization System for Inlet Fogging at Rathdrum CT
•Inlet Chiller at Coyote Springs 2
•Cold Day Performance Software Upgrade at Coyote Springs 2
•Advanced Hot Gas Path Hardware Upgrade at Coyote Springs 2
•Cooling Optimization Hardware Upgrade at Coyote Springs 2
•Wood Fuel Gasification at Kettle Falls Generation Site
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 405 of 1069
Rathdrum Combustion Turbine
Rathdrum, Idaho
•Two General Electric 7EA Combustion Turbines
•On Line in 1994
•Simple Cycle Configuration
•Approximately 160 MW Combined Output
•Heat Rate of 11,612 Btu/kWh (HHV)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 406 of 1069
Conversion of Rathdrum CT
to a Combined Cycle Power Plant
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 407 of 1069
Conversion of Rathdrum CT to Combined Cycle
Water Cooled Condenser
Incremental Output Increase: 78.4 MW At 5°F
85.2 MW at 55°F
91.4 MW at 100°F
Overall Plant Heat Rate Change: -3782 Btu/kWhr (HHV)
Variable Operating Costs:$1.50/MWh
Fixed Operating Costs:$15/kWyr
Capital Cost:$71M
Plant Unavailable Time:6 Months
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 408 of 1069
Conversion of Rathdrum CT to Combined Cycle
Air Cooled Condenser
Incremental Output Increase: 77.9 MW At 5°F
79.9 MW at 55°F
82.4 MW at 100°F
Overall Plant Heat Rate Change: -3626 Btu/kWhr (HHV)
Variable Operating Costs:$1.30/MWh
Fixed Operating Costs:$15/kWyr
Capital Cost:$81.5M
Plant Unavailable Time:6 Months
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 409 of 1069
Water Demineralizer at Rathdrum CT for Inlet Fogging
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 410 of 1069
Water Demineralizer at Rathdrum CT for Inlet Fogging
Incremental Output Increase: N/A At 5°F
4.4 MW at 55°F
17.6 MW at 100°F
Overall Plant Heat Rate Change: -67 Btu/kWhr (HHV)
Variable Operating Costs:$1.00/MWh
Fixed Operating Costs:Insignificant
Capital Cost:$1M
Plant Unavailable Time:2 Months
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 411 of 1069
Coyote Springs 2
Boardman, Oregon
•One General Electric 7FA Combustion Turbine
•Combined Cycle Configuration
•On Line in 2003
•Approximately 279 MW Combined Output (Duct Fired)
•Heat Rate of 6229 Btu/kWh (HHV)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 412 of 1069
Inlet Chiller at Coyote Springs 2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 413 of 1069
Inlet Chiller at Coyote Springs 2
w/o Thermal Storage
Incremental Output Increase: N/A At 5°F
0 MW at 55°F
29.8 MW at 100°F
Overall Plant Heat Rate Change: Insignificant
Variable Operating Costs:Insignificant
Fixed Operating Costs:Insignificant
Capital Cost:$10M
Plant Unavailable Time:3 Months
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 414 of 1069
Inlet Chiller at Coyote Springs 2
With Thermal Storage
Incremental Output Increase: N/A At 5°F
0 MW at 55°F
32.2 MW at 100°F
Overall Plant Heat Rate Change: Insignificant
Variable Operating Costs:Insignificant
Fixed Operating Costs:Insignificant
Capital Cost:$10M
Plant Unavailable Time:3 Months
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 415 of 1069
Cold Day Performance Software Upgrade
at Coyote Springs 2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 416 of 1069
Cold Day Performance Software Upgrade
at Coyote Springs 2
Incremental Output Increase: 17.6 MW At 5°F
0.8 MW at 55°F
1.2 MW at 100°F
Overall Plant Heat Rate Change: Insignificant
Variable Operating Costs:None
Fixed Operating Costs:None
Capital Cost:$4.5M
Plant Unavailable Time:2 Months
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 417 of 1069
Advanced Hot Gas Path Hardware Upgrade
at Coyote Springs 2
Source: General Electric
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 418 of 1069
Advanced Hot Gas Path Hardware Upgrade
at Coyote Springs 2
Incremental Output Increase: 8.6 MW At 5°F
8.0 MW at 55°F
7.1 MW at 100°F
Overall Plant Heat Rate Change: -76 Btu/kWhr
Variable Operating Costs:None
Fixed Operating Costs:$3.9M
Capital Cost:$18M
Plant Unavailable Time:None
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 419 of 1069
Cooling Optimization Hardware Upgrade
at Coyote Springs 2
Source: General Electric
7FA Cooling Optimization Package,
Image removed, GE Proprietary
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 420 of 1069
Cooling Optimization Hardware Upgrade
at Coyote Springs 2
Incremental Output Increase: 2.8 MW At 5°F
2.6 MW at 55°F
2.3 MW at 100°F
Overall Plant Heat Rate Change: -35 Btu/kWhr
Variable Operating Costs:None
Fixed Operating Costs:None
Capital Cost:$7.2M
Plant Unavailable Time:2 Months
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 421 of 1069
Kettle Falls Generating Station
Kettle Falls, Washington
•Wood Fired Boiler with General Electric Steam Turbine
•On Line in 1983
•Approximately 48 MW Output
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 422 of 1069
Gasification of Wood Fuel
at Kettle Falls Generation Site
Nexterra Gasification System
1.Fuel In-Feed System
2.Gasifier
3.Automatic Ash Removal System
4.Syngas
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 423 of 1069
Gasification of Wood Fuel
at Kettle Falls Generation Site
• Gasification of wood fuel for use in turbines is in it’s infancy
•Difficulty with adequately cleaning the syngas for use in a
turbine
•No reliable data on expected costs or operational characteristics
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 424 of 1069
Questions?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 425 of 1069
Load Forecast
Randy Barcus
Technical Advisory Committee Meeting #3
2011 Electric Integrated Resource Plan
December 2, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 426 of 1069
Load Forecast 2011-2035
Outline
Economy
Weather
Price Elasticity
Customer Regressions
Small Sector Forecasts
Large Customer Forecasts
Irrigation and Pumping Sales
Sales Forecast
Load Forecast
Expected Peak Forecast
Load Forecast Scenarios
2 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 427 of 1069
Real Gross Metropolitan Product ($millions)
History 1995-2010, Forecast 2010-2035
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spokane Real Gross Metropolitan Product (Millions 2000$)Kootenai Real Gross Metropolitan Product (Millions 2000$)
3
Spokane Kootenai
1995-2010 1.84%4.81%
2010-2015 2.83%3.50%
2010-2020 2.68%3.40%
2010-2030 2.52%3.16%
2010-2035 2.47%3.09%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 428 of 1069
Real Gross Metropolitan Product
Annual Percent Change
4
-4%
-2%
0%
2%
4%
6%
8%
10%
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spo-RGDP(%)Kot-RGDP(%)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 429 of 1069
Annual Population—thousands of persons
History 1995-2010, Forecast 2010-2035
0
100
200
300
400
500
600
700
800
900
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spokane Population Kootenai Population
5
Spokane Kootenai
1995-2010 1.08%2.87%
2010-2015 1.18%2.16%
2010-2020 1.09%2.08%
2010-2030 0.98%1.97%
2010-2035 0.93%1.95%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 430 of 1069
Population
Annual Percent Change
0%
1%
2%
3%
4%
5%
6%
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spo-Pop(%)Kot-Pop(%)
6 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 431 of 1069
Annual Housing Starts
History 1995-2010, Forecast 2010-2035
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spokane Housing Starts, Total Private (SAAR)Kootenai Housing Starts, Total Private (SAAR)
7 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 432 of 1069
Average Annual Non-Ag Employment—thousands
History 1995-2010, Forecast 2010-2035
0
50
100
150
200
250
300
350
400
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spokane Employment (NAICS), Total Nonfarm (Thous.)Kootenai Employment (NAICS), Total Nonfarm (Thous.)
8
Spokane Kootenai
1995-2010 0.94%2.70%
2010-2015 1.62%2.45%
2010-2020 1.31%2.02%
2010-2030 1.00%1.61%
2010-2035 0.92%1.48%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 433 of 1069
Non-Ag Employment
Annual Percent Change
-8%
-6%
-4%
-2%
0%
2%
4%
6%
8%
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spo-Emp(%)Kot-Emp(%)
9 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 434 of 1069
Average Annual Unemployment Rate--Percent
0
2
4
6
8
10
12
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spokane Unemployment Rate (%)Kootenai Unemployment Rate (%)
10 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 435 of 1069
Average Annual Household Income—Thousands $
50
75
100
125
150
175
200
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spokane Average Household Income (Thous.)Kootenai Average Household Income (Thous.)
11
Spokane Kootenai
1995-2010 3.27%3.07%
2010-2015 3.19%3.13%
2010-2020 3.57%3.59%
2010-2030 3.49%3.42%
2010-2035 3.50%3.36%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 436 of 1069
Average Household Income—Percent Change
Compared to U.S. Consumer Price Index (CPIU)
-4.0%
-2.0%
0.0%
2.0%
4.0%
6.0%
8.0%
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Spo-AHHI(%)Kot-AHHI(%)Consumer Price Index
12 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 437 of 1069
Weather Assumptions
We use degree days (heating and cooling) base 65 degrees
We define ―normal‖ as the average of the last 30 years of actual
data; for this forecast, the period is 1980-2009
We assume the first year (2011) of the forecast is ―normal‖
A gradual warming trend in temperature equal to the University
of Washington ―Climate Change Scenarios‖ 2008 study Average
case converted by us to heating and cooling degree days
http://cses.washington.edu/cig/fpt/ccscenarios.shtml
Spokane HDD 1970-1999 Average 6,848 Spokane CDD 1970-1999 Average 411
Low 1.1 6,547 95.6%Low 1.1 511 124.3%
2025 Computation Average*2.0 6,300 92.0%2025 Computation Average*2.0 593 144.3%
High 3.3 5,944 86.8%High 3.3 711 173.0%
Low 1.5 6,437 94.0%Low 1.5 548 133.2%
2045 Computation Average*3.2 5,971 87.2%2045 Computation Average*3.2 702 170.8%
High 5.2 5,423 79.2%High 5.2 884 215.1%
Low 2.8 6,081 88.8%Low 2.8 666 162.0%
2085 Computation Average*5.3 5,396 78.8%2085 Computation Average*5.3 893 217.3%
High 9.7 4,190 61.2%High 9.7 1,294 314.7%
13 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 438 of 1069
Price Elasticity
The price elasticity assumptions are unchanged from the prior
IRP
–Residential -0.15
–Commercial -0.10
–Cross-price +0.05
–Income +0.75
We monitor price elasticity estimates for consistency
–Energy Information Administration
–Itron Energy Forecasting Group
–American Gas Association/Gas Forecasters Forum
14 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 439 of 1069
Customer Regressions
We use annual housing starts forecasts from Global Insight, Inc.
to forecast residential customers—this method is new
–The dependent variable is annual residential customer
additions, the independent variable is annual housing starts
–We forecast Idaho and Washington Schedule 1 customers
using separate models
We use annual residential customer additions to forecast
commercial customer additions.
–The dependent variable is annual commercial customer
additions, the independent variable is residential customer
additions
For very large commercial customers, we add one in 2017,
2021, and 2028 in Washington and one in Idaho in 2025
15 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 440 of 1069
Small Sector Forecasts
We forecast electricity sales by state, by rate schedule
We produce monthly sales forecasts until 2015, annual to 2035
We define small sector sales in Washington as:
–Residential schedule 1, 12, 22, 32 and 48
–Commercial schedule 11, 21, 28, 31 and 47
–Industrial schedule 11, 21, 31, 32 and 47
–Street Lighting schedule 41, 42, 44, 45 and 46
We define small sector sales in Idaho as:
–Residential schedule 1, 12, 22, 32, 48 and 49
–Commercial schedule 11, 21, 31, 47 and 49
–Industrial schedule 11, 21, 31, 32, 47 and 49
–Street Lighting schedule 41, 42, 43 44, 45 and 46
We define large sector sales as schedule 25 commercial and
industrial in both states
16 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 441 of 1069
Large Customer Forecasts
We are prohibited from disclosing individual large customer
sales
Sector groupings
–Paper Manufacturers
–Potato Processors
–Lumber and Wood Producers
–Hospitals
–Aircraft Parts Manufacturers
–Universities
–Wastewater Treatment Facilities
–Ammunition Manufacturers
–Cabinetry Manufacturers
–Foundries
–Mines
–Hotels
–Electronic Equipment Manufacturers
–Courthouse/Office Building
All together there are 13 commercial and 18 industrial meter
points
17 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 442 of 1069
Large Customer Share of Total kWh Sales
Commercial and Industrial Schedule 25
18
0%
5%
10%
15%
20%
25%
30%
JA
N
FE
B
MA
R
AP
R
MA
Y
JU
N
JU
L
AU
G
SE
P
OC
T
NO
V
DE
C
AN
N
U
A
L
Sch25 Commercial Sch25 Industrial
0%
5%
10%
15%
20%
25%
30%
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
Sch25 Commercial Sch25 Industrial
Note—the above charts are stacked line
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 443 of 1069
Irrigation and Pumping Sales
Special Load Analysis
19
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
4.0%
JA
N
FE
B
MA
R
AP
R
MA
Y
JU
N
JU
L
AU
G
SE
P
OC
T
NO
V
DE
C
AN
N
U
A
L
2011 Irrigation-Pumping/Total Sales
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
Annual Irrigation-Pumping/Total Sales
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 444 of 1069
Customer Forecasts
20
250,000
300,000
350,000
400,000
450,000
500,000
19
9
7
20
0
0
20
0
3
20
0
6
20
0
9
20
1
2
20
1
5
20
1
8
20
2
1
20
2
4
20
2
7
20
3
0
20
3
3
Residential Commercial Industrial Street Lights
85.0%
87.5%
90.0%
92.5%
95.0%
97.5%
100.0%
19
9
7
20
0
0
20
0
3
20
0
6
20
0
9
20
1
2
20
1
5
20
1
8
20
2
1
20
2
4
20
2
7
20
3
0
20
3
3
Residential Commercial Industrial Street Lights
Residential Commercial Industrial Street Lights Total Customers
2000-2010 1.44%1.19%0.94%1.37%1.41%
2010-2015 1.22%1.06%0.90%2.63%1.20%
2010-2020 1.26%1.14%0.85%2.49%1.24%
2010-2030 1.20%1.14%0.72%2.27%1.19%
2010-2035 1.17%1.12%0.69%2.18%1.16%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 445 of 1069
kWh Use per Average Residential Customer
21
10,000
10,500
11,000
11,500
12,000
12,500
13,000
13,500
14,000
14,500
15,000
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
20
3
1
20
3
3
20
3
5
Residential
50,000
55,000
60,000
65,000
70,000
75,000
80,000
85,000
90,000
95,000
100,000
19
9
7
20
0
0
20
0
3
20
0
6
20
0
9
20
1
2
20
1
5
20
1
8
20
2
1
20
2
4
20
2
7
20
3
0
20
3
3
Commercial
Residential Commercial
2000-2010 -0.29%-0.50%
2010-2015 -0.49%0.65%
2010-2020 -0.47%0.70%
2010-2030 0.00%0.65%
2010-2035 0.27%0.64%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 446 of 1069
kWh Sales
Customer Class
22
0
2,000,000,000
4,000,000,000
6,000,000,000
8,000,000,000
10,000,000,000
12,000,000,000
14,000,000,000
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Residential Commercial Industrial Street Lights
Residential Commercial Industrial Street Lights Total Sales
2000-2010 1.11%0.69%0.23%0.53%0.75%
2010-2015 0.72%1.71%2.74%2.49%1.56%
2010-2020 0.79%1.84%2.38%2.32%1.56%
2010-2030 1.19%1.79%1.78%2.03%1.55%
2010-2035 1.44%1.77%1.56%1.94%1.59%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 447 of 1069
Electric Car Forecast (PIH & PEV)
23
0
100,000,000
200,000,000
300,000,000
400,000,000
500,000,000
600,000,000
700,000,000
800,000,000
900,000,000
1,000,000,000
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Total Vehicles kWh Consumption
Assumes 2,500 kWh average per vehicle
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 448 of 1069
Load Forecast in Average MW
24
800
900
1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 449 of 1069
Peak Demand in Megawatts
25
1,400
1,500
1,600
1,700
1,800
1,900
2,000
2,100
2,200
2,300
2,400
2,500
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
Peak Load Forecast based on Average Coldest Day
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 450 of 1069
Medium Scenario Growth Rates
26
Energy
2000-2010 0.48%
2010-2015 1.85%
2010-2020 1.72%
2010-2030 1.66%
2010-2035 1.68%
Peak Demand
0.87%
0.76%
1.22%
1.46%
1.55%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 451 of 1069
Load Forecast Prepared 10 Years Ago
27
For
Forecast
aMW Days
Forecast
MWH
Actual
aMW Days
Actual
MWH
Percent
Difference
2009 Jan 1,362 31 1,013,121 1,272 31 946,653 -6.6%
Feb 1,266 28 850,592 1,186 28 796,895 -6.3%
Mar 1,145 31 851,634 1,121 31 833,848 -2.1%
Apr 1,080 30 777,278 980 30 705,751 -9.2%
May 1,068 31 794,688 952 31 708,039 -10.9%
Jun 1,089 30 783,858 979 30 704,569 -10.1%
Jul 1,070 31 796,388 1,057 31 786,248 -1.3%
Aug 1,074 31 798,938 1,034 31 769,272 -3.7%
Sep 986 30 709,832 968 30 697,305 -1.8%
Oct 1,109 31 825,286 1,014 31 754,464 -8.6%
Nov 1,217 30 875,980 1,106 30 796,630 -9.1%
Dec 1,335 31 993,573 1,321 31 982,507 -1.1%
10,071,167 9,482,181 -5.8%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 452 of 1069
Forecast Comparisons
28
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
F2011 929 954 989 1,013 965 995 1,013 1,021 1,046 1,069 1,088 1,098 1,082 1,063 1,094 1,109 1,131 1,148 1,165 1,186 1,209 1,228 1,244 1,260
F2010 1,088 1,098 1,076 1,101 1,130 1,151 1,174 1,197 1,216 1,235 1,260 1,278 1,296 1,315
F2009 1,088 1,113 1,119 1,148 1,171 1,188 1,202 1,222 1,252 1,270 1,289 1,311 1,329 1,347
F2007IRP 1,091 1,124 1,163 1,196 1,229 1,255 1,274 1,306 1,325 1,358 1,379 1,399 1,426 1,449
F2006 1,043 1,086 1,122 1,159 1,198 1,232 1,270 1,299 1,327 1,360 1,388 1,417 1,440 1,461 1,491 1,516
F2005 1,029 1,067 1,099 1,122 1,152 1,185 1,215 1,246 1,270 1,296 1,323 1,354 1,379 1,395 1,417 1,447 1,472
F2004 1,000 1,035 1,061 1,085 1,109 1,135 1,164 1,196 1,225 1,247 1,270 1,293 1,327 1,356 1,384 1,412 1,444 1,474
F1999 986 988 971 982 1,009 1,033 1,059 1,088 1,121
900
1,000
1,100
1,200
1,300
1,400
1,500
1,600
Av
e
r
a
g
e

M
W

i
n
c
l
u
d
i
n
g

l
o
s
s
e
s
Net Native Load
with Electric Cars
F2011 F2010 F2009 F2007IRP F2006 F2005 F2004 F1999
Forecast 2011-2020
Actual 1997-2009
2010 has 9 months actual
2011 Forecast Growth Rates Base 2011
5 =1.63%, 10 =1.56%, 20 =1.60%, 24 =1.63%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 453 of 1069
Population Forecasts—Then and Now
29
Spokane
County
Census
April 1st
OFM
1995
OFM
2007
Avista
2000
Avista
2010
Decade
Medium
Growth
Rate
Decade
Low
Growth
Rate
Decade
High
Growth
Rate
1960 278,333
1970 287,487 0.32%
1980 341,835 1.75%
1990 361,333 361,333 361,333 0.56%
2000 417,939 417,939 1.47%
2010*470,300 476,400 466,724 449,300 475,646 1.19%
2020 529,451 530,003 1.09%0.54%1.63%
2030 589,623 577,829 0.87%0.43%1.30%
2035 599,873
July 1st Estimates
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 454 of 1069
Low, Medium and High Growth Scenarios
Global Insight provides us with Medium Scenario economic forecasts
We plan to overlay the 6th Power Plan range for Low and High
NPPC Low 0.8%, Medium 1.4%, High 1.8% for 2010-2030
–http://www.nwcouncil.org/energy/powerplan/6/final/SixthPowerPlan_Ch3.pdf page 3-5
Avista’s 2010-2030 growth rate medium scenario 1.66%
Overlay Low 0.95%, Overlay High 2.13% by ratio method
30 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 455 of 1069
Stochastic Modeling Assumption &
Methodology Discussion
James Gall
Technical Advisory Committee Meeting #3
2011 Electric Integrated Resource Plan
December 2, 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 456 of 1069
2011 Integrated Resource Plan Modeling Process
Preferred
Resource
Strategy
AURORA
“Wholesale Electric
Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Emission Pricing
Existing Resources
Resource Options
Transmission
Resource &
Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,
Capacity,
& RPS
Balances New Resource
Options & Costs
Cost Effective T&D
Projects/Costs
Cost Effective
Conservation
Measures/Costs
Mid-Columbia
Prices
Stochastic Inputs Deterministic Inputs
Capacity
Value
Avoided
Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 457 of 1069
Why Conduct a Stochastic Study
Quantifies the risk (range in prices/costs) of the wholesale
electric market.
Determines range in potential market value of each resource
option.
Determines the range in potential cost to serve customers over
the IRP time period.
IRP’s objective is plan on a resource portfolio that is not only least cost but
at an acceptable level of risk.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 458 of 1069
Measurements of Risk
Standard Deviation
Mean Absolute Error
Value at Risk
Tail Var “90”
Percentile
Probability
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 459 of 1069
Market Stochastic Study Variables
Hydro availability
Wind availability
Coal prices
Wood prices
Oil prices
Inflation
Forced outages
Natural gas prices
Weather (load)
Economic growth (load)
Conservation (load)
Carbon legislation
Resource Capital Costs (?)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 460 of 1069
2009 Mid-Columbia Flat Electric Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 461 of 1069
2009 Mid-Columbia Flat Electric Prices
with Individual Normalized Inputs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 462 of 1069
2009 Mid-Columbia Flat Normalized Electric Price
$0.00
$10.00
$20.00
$30.00
$40.00
$50.00
$60.00
1 2 3 4 5 6 7 8 9 10 11 12
$
p
e
r

M
W
h
2009 Normalized 2009 AURORA Backcast
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 463 of 1069
Hydro
Random draw of 70 historical hydro years.
Avista projects use results of Avista hydro model
Regional projects uses Northwest Power Pool model
Mean: 17,849
Stdev: 2,506 (14%)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 464 of 1069
Historical Wind Generation
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1 21 41 61 81
10
1
12
1
14
1
16
1
18
1
20
1
22
1
24
1
26
1
28
1
30
1
32
1
34
1
36
1
38
1
40
1
42
1
44
1
46
1
48
1
50
1
52
1
54
1
56
1
58
1
60
1
62
1
64
1
66
1
68
1
70
1
72
1
74
1
Ca
p
a
c
i
t
y

F
a
c
t
o
r
January Wind Generation on BPA
2007 2008 2009 2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 465 of 1069
Wind
Use 50 potential wind draws
Each draw will be 8,760 hour shape
Use separate wind shape available for most of the Western
states and provinces
NREL hourly simulated generation data (2004-06) is used to
estimate capacity factors and correlations for non-NW areas
Area CF Area CF
Northwest 31.8%Southwest 28.8%
California 30.6%Utah 29.0%
Montana 37.2%Colorado 32.2%
Wyoming 38.2%British Columbia 33.2%
Eastern WA 30.6%Alberta 34.3%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 466 of 1069
Wind (Continued)
Regression model using BPA/NREL data
–Uses hour type, month, hour -1, hour -2 for the coefficients
–Northwest: 97.5% R2, 4.7% (CF standard error)
–Random error with normal distribution to create variability
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 467 of 1069
Coal, Oil, and Wood Prices
Assume normal distribution of annual change in price
Mean prices are based on Wood Mackenzie for oil and coal
Standard Deviations:
–Coal: 10%
–Oil: 25%
–Wood: 10%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 468 of 1069
Inflation
Based on Global Insights forecast for average and standard
deviation
Average inflation is assumed to be 1.70%, w/ standard deviation
of 1% (59% of mean)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 469 of 1069
Forced Outages
Historical Outage rates are available from NERC’s GAR Report
–GADS- Generation Availability Report
Data available for Coal, Nuclear, NG, and Oil by size of plant
–Both planned and unplanned outages are tracked
–Data is only available for all plants (no drill down option)
AURORA’s has random forced outage logic
–Uses mean time to repair and annual forced outage rate
–Both matrices can be derived from GADS data
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 470 of 1069
Historical Monthly AECO Natural Gas Prices
Historical prices have been volatile
Will volatility continue, or will shale gas flatten volatility?
Will there still be boom/bust in natural gas prices?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 471 of 1069
Natural Gas Prices
Mean natural gas prices are yet to be finalized. Prices will be
finalized by end of 2010 to take into account best available
information for the plan
To model the variability of prices will use a new method for this
IRP.
–Randomize the percent change between month to month
prices based on a lognormal distribution
–This method provides high month to month correlations as
history demonstrates (90%+)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 472 of 1069
Natural Gas Forecast (individual draws)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 473 of 1069
Natural Gas Forecast (Statistics 500 draws)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 474 of 1069
Load (Weather)
Weather variation will be modeled in AURORA with monthly load
variances for 2005 through 2009
Weather is assumed to be normally distributed with standard
deviation for each load area and a correlation to the Northwest
area based on FERC Form 714 hourly load profiles
Further detail on this methodology can be found in prior IRPs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 475 of 1069
Load (Economic & Conservation)
Weather is not the only driver in future loads, economic growth,
electric cars, and conservation will affect energy demand
Historical load growth is highly volatile (see chart below)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 476 of 1069
Load (Economic & Conservation)…. continued
Expected load growth will assume Wood Mackenzie forecast
Standard deviation is assumed to be 50% (same as last plan)
100
105
110
115
120
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
Lo
a
d

I
n
d
e
x
NW Regional Load Growth
100 draws
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 477 of 1069
Carbon Legislation
No national carbon legislation has been passed
Many western states/provinces have passed some type of carbon
reduction scheme
For this plan..
–5 scenarios are developed based on potential outcomes.
–Each scenario is assigned a weighting
–The weighted average of the scenarios will be the base
forecast
–Natural gas prices and carbon prices will be correlated for
national policy scenarios
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 478 of 1069
Carbon Legislation Scenarios
1.Western Climate Initiative “WCI” (20% probability)
–No federal legislation, carbon reduction in CA, OR, WA, NM only
–15% below 2005 levels by 2020
–Begins in 2012, regional trading allowed
2.Regional Greenhouse Gas Initiative “RGGI” (20% probability)
–No federal legislation, carbon reduction in CA, OR, WA, NM only
–187 million tons per year through 2014, then 10% reduction by 2018
–Begins in 2012, within state trading only
3.National Climate Policy (20% probability)
–Federal legislation only applies
–17% below 2005 levels by 2020, 42% below 2005 levels by 2030
–Begins in 2015, national trading allowed
4.National Carbon Tax (15% probability)
–Federal legislation only applies
–$33 per short ton, than 5% per year escalation
–Begins in 2015
5.No Carbon Reductions (5% probability)
–No carbon reduction scheme
–State level emission performance standards apply and no new coal in US West
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 479 of 1069
Next Meeting
1.Finalize mean key driver assumptions
2.Implement stochastic modeling methodologies with AURORA
3.Simulate the market future 500 times between 2012-2031
4.Present results for electric market prices and other key results
5.Evaluate the potential of modeling capital costs stochastically
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 480 of 1069
Avista’s 2011 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
Avista Headquarters – Spokane, Washington

Thursday, February 3, 2011
Avista Conference Room 130

Topic Time Staff
1. Introduction 9:30 Storro

2. Natural Gas Price Forecast 9:35 Rahn

3. Electric Price Forecast 10:30 Gall

4. Lunch 12:00

5. Resource Requirement Projections 1:00 Kalich

6. Portfolio and Market Scenario Planning 2:30 Lyons

7. Adjourn 3:00

Conference Call Instructions:
1. Please join my meeting.
https://www2.gotomeeting.com/join/717354547

2. Join the conference call:

Dial [phone]
Access Code: 717-354-547
Audio PIN: Shown after joining the meeting

Meeting ID: 717-354-547

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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 481 of 1069
Avista Electric IRP
Natural Gas Price Forecast
Technical Advisory Committee Meeting
February 4, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 482 of 1069
Henry Hub Historical Price Trend
???
Average price: $6.19Average price:
$2.29
Average
price: $4.500
2
4
6
8
10
12
14
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
US
Dollars
per
MMBtu
End of the
Gas Bubble
Unconventional Inadequacy
The Shale
Gale
Source: Platts.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 483 of 1069
Brief History of Forecasts
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$/
D
t
h
Various Henry Hub Forecasts
Nominal $
Oct-06
Feb-07
Aug-08
Dec-08
Dec-09
Dec-10
NPCC 6th
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 484 of 1069
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
$/
D
t
h
Nymex Forward Prices
Annual Strips
12/1/2006
12/3/2007
12/1/2008
12/1/2009
12/1/2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 485 of 1069
Long Term Natural Gas Price Drivers
DEMAND
Economy
–Industrial
–Power Generation
SUPPLY
US Natural Gas Production
Imports from Canada
OTHER FACTORS
Oil and Coal Prices
Carbon Legislation/Renewable Portfolio Standards
Global Dynamics; LNG Imports (Exports?)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 486 of 1069
US Natural Gas Demand Forecast
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 487 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 488 of 1069
0
20
40
60
80
100
2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020
U.S. Conventional Canada Conventional U.S. Unconventional Canada Unconventional
Actual Projection
North American Natural Gas Production
Bcf/d
Source: EIA & NEB historic data; Encana forecasts
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 489 of 1069
Shale Gas Economics 101
Bigger Costs. Bigger Volumes.
Conventional Vertical Drilling
Unconventional Horizontal Drilling
and Hydraulic Fracturing
9 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 490 of 1069
The Shale Drilling Process
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 491 of 1069
BC SHALES
ROCKIES
GULF STATES
MARCELLUS
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 492 of 1069
Growth in U.S. Shale Gas Production
Source: MIT Study The Future of Natural Gas
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 493 of 1069
Costs and Volumes –Selected Gas Plays
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 494 of 1069
1.Drilling Days -depending on vertical depth and lateral length, a typical 90-
100 day turnaround has been reduced down to 18–45 days
2.Lateral Length - commonly going to about 4,000+ feet horizontal, pushing
beyond 10,000 feet in some wells
3.Wells per Pad/Simultaneous Operations - each pad has up to 8 wells;
simultaneous well work on multiple wellbores
4.Number of Fracturing Stages –1 or 2 stage jobs in the past; now 8-10
stages or more
5.Simultaneous Fracturing –fracturing simultaneous wellbores to achieve
acute stresses and more effective fracs
The Gas Factory
Technology and Efficiency
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 495 of 1069
Shale Gas and US Production
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 496 of 1069
Natural Gas Liquids (NGLs)
What are they?
Natural gas liquids (NGLs) are hydrocarbons
often found resident with natural gas. They
are recovered as liquids through a
purification process at processing plants.
They include ethane, propane, and butane
and condensate (natural gasoline).
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 497 of 1069
Canada Exports
Recent Trends
Imports declining slower than anticipated
BC Shale larger and faster than
anticipated
Alberta royalties renegotiated
Lower oil prices have slowed demand for
oil sands production
Historical Trend –Declining Exports
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 498 of 1069
Oil vs. Natural Gas Relationship
•Strong long term price
correlation historically
•Long term ratio of approx.
8 to 1 (1994-2008)
•Since Jan 2009 ratio has
doubled to approx 17 to 1
•Shale gas could
fundamentally and
permanently change
historic ratio
•Alternatively, increased
demand from low prices
could cure low prices
$0
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$0
$20
$40
$60
$80
$100
$120
$140
$160
Ja
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9
9
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-20
0
0
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0
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0
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0
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0
8
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0
9
Ja
n
-20
1
0
$/
D
t
h
$/
B
a
r
r
e
l
Historical Oil and Gas Prices -Nymex
Oil Natural Gas
0
5
10
15
20
25
30
Ja
n
-19
9
4
Ja
n
-19
9
5
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9
6
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9
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9
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9
9
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-20
0
0
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0
1
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0
2
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3
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0
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0
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0
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0
7
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n
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0
8
Ja
n
-20
0
9
Ja
n
-20
1
0
Oil to Natural Gas Price Ratio
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 499 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 500 of 1069
Carbon Policy/Renewable Portfolio Standards
Natural Gas has a critical yet complex role in carbon policy creation
and implementation.
•Numerous complex issues and uncertainties
•Need to balance economic challenges with policy objectives
•Complex issues within cap and trade vs. simpler carbon tax
•Long term role or interim bridge?
Natural Gas also has an important backup role for intermittent
renewable generation sources
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 501 of 1069
Global Natural Gas Estimates
Source: MIT Study The Future of Natural Gas
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 502 of 1069
LNG Imports…or Exports?
Source: Federal Energy Regulatory Commission
Source: Geology.com
LNG traditionally flows to North America after other higher-priced markets receive their share
Source: Apache LNG
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 503 of 1069
IRP Price Forecast Methodology
1.Two fundamental forecasts (Consultant #1 & Consultant #2)
2.Forward prices
3.50/50 weighting fundamental and forwards year 1
4.Reduce forwards weighting 10% each year thereafter
5.By year 6, forecast is 50% Consultant #1, 50% Consultant #2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 504 of 1069
IRP Price Forecast Components
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$/
D
t
h
Price Forecasts Henry Hub
Nominal $
Consult 1
Consult 2
Forwards
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 505 of 1069
IRP Price Forecast –Selected Hubs
Nominal $
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$/
D
t
h
HENRY HUB
MALIN
STANFIELD
AECO
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 506 of 1069
Electric Market Forecast
(Preliminary Draft)
James Gall
Technical Advisory Committee Meeting #4
2011 Electric Integrated Resource Plan
February 3, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 507 of 1069
2011 Integrated Resource Plan Modeling Process
Preferred
Resource
Strategy
AURORA
“Wholesale Electric
Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Emission Pricing
Existing Resources
Resource Options
Transmission
Resource &
Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,
Capacity,
& RPS
Balances New Resource
Options & Costs
Cost Effective T&D
Projects/Costs
Cost Effective
Conservation
Measures/Costs
Mid-Columbia
Prices
Stochastic Inputs Deterministic Inputs
Capacity
Value
Avoided
Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 508 of 1069
Historical Monthly Flat Mid-Columbia Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 509 of 1069
Historical Monthly Implied Market Heat Rates
(Mid-Columbia/Stanfield x 1,000)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 510 of 1069
Western Interconnect Load Growth
Regional Load Growth Source: Wood Mackenzie
1.8%
2.1%
1.4%
0.9%
1.4%
1.6%
Growth Rate
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 511 of 1069
New Western Interconnect (WECC) Conservation
New
conservation
meets 21% of
Load Growth
Regional Load Growth/Conservation Source: Wood Mackenzie
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 512 of 1069
Western Interconnect Plug-in Electric Hybrid Vehicles
Assumption
Electric Cars are assumed to be adopted at the Northwest
Power & Conservation Council estimate per the “Case 2” of the
6th Power Plan
–18% of cars by 2020 and 28% by 2030
95% of cars will charge at night and 5% during on-peak hours
PHEV are not assumed to meet electric capacity needs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 513 of 1069
Natural Gas Price Re-Cap
$7.28- Henry Hub
2012-2031
Nominal
Levelized Price
$6.71- Stanfield
$6.39- AECO
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 514 of 1069
Western Interconnect Transmission Additions
Additional regional transmission additions are assumed to take
place in the future, these are the additions assumed in the Base
Case market analysis (MW)
–Idaho - NW: 1,500 (2019)
–Canada -NW - California: 3,000 (2018)
–Wyoming - Utah: 3,000 (2015)
–Wyoming - Idaho: 1,500 (2016)
–Wyoming - Colorado: 900 (2013)
–Idaho - Utah: 1,320 (2016)
–N. Nevada - S. Nevada: 1,600 (2015)
–New Mexico - Arizona: 3,000 (2016)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 515 of 1069
New Resource Alternatives
Western Interconnect
Resource alternatives to meet Renewable Portfolio Standards
–Wind
–Solar
–Biomass
–Geothermal
–Hydro Upgrades
Resource alternatives to meet regional capacity requirements
–Combined Cycle
–Simple Cycle (Aero, Frame, Hybrid)
–Solar
–Wind (non RPS states)
–Nuclear
–Coal Pulverized
–Coal IGCC
–Coal IGCC with Sequestration
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 516 of 1069
State Renewable Energy Requirements
Western Interconnect
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 517 of 1069
New Renewable Resources Added for RPS by Type
Western Interconnect
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 518 of 1069
Location of New Renewable Resources
Western Interconnect
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
En
e
r
g
y

(
a
M
W
)
California Arizona Colorado Idaho
Montana New Mexico Nevada Oregon
Utah Washington Wyoming British Columbia
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 519 of 1069
Generation Greenhouse (CO2) Gas Emissions by
State in the Western Interconnect
AZ
CA
CO
IDMT
NM
NVOR
UT
WA
WY
-
50
100
150
200
250
300
350
400
450
500
19
9
0
19
9
1
19
9
2
19
9
3
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
Mi
l
l
i
o
n
s

o
f

S
h
o
r
t

T
o
n
s
Source: EPA
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 520 of 1069
Greenhouse Gas (CO2) Reduction Schemes
Stochastic Case
1.Regional Greenhouse Gas Policies (30% probability)
–State carbon reduction in CA, OR, WA, NM between 2014 and 2019
–~10% reduction below 2005 levels by 2020
–Beginning in 2020 shift to National Climate Policy with 15% below 2005 levels by 2030
2.National Climate Policy (30% probability)
–Federal legislation only applies beginning in 2015
–~15% below 2005 levels by 2020, ~35% below 2005 levels by 2030
3.National Carbon Tax (30% probability)
–Federal legislation only applies
–$33 per short ton, than 5% per year escalation
–Begins in 2015
4.No Carbon Reductions (10% probability)
–No carbon reduction scheme
–State level emission performance standards apply and no new coal in US West
Deterministic Case
–Emissions reduced to the weighted average of four cases above
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 521 of 1069
Resulting Greenhouse Gas (CO2) Reduction Prices
$59.36
2015-2031
Levelized
Price per
Short Ton
$28.02
$46.48
$00.00
$40.20
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 522 of 1069
New Resource Selected to Meet Capacity
Requirements in Western Interconnect
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 523 of 1069
Northwest New Resources (RPS, Export, & Capacity)
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
Na
m
e
p
l
a
t
e

M
W
Natural Gas-Peaker Natural Gas-CCCT
Geothermal Biomass
Solar Hydro
Wind
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 524 of 1069
Deterministic Mid-Columbia Annual Average Price
Forecast
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 525 of 1069
Deterministic Mid-C Annual Avg Price Forecast
Levelized Nominal Prices
Scheme Levelized Price
$/MWh
2012-31
2009 IRP Expected Case (Adjusted)97.60
2011 IRP Expected Case 71.22
Scenarios
Regional Greenhouse Gas Policies 66.91
National Climate Policy 78.94
National Carbon Tax 73.98
No Carbon Reductions 53.70
Weighted Average 71.32
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 526 of 1069
Deterministic Implied Market Heat Rates
(Mid-Columbia / Stanfield x 1,000)
Actual Forecast
Fo
r
w
a
r
d
s
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 527 of 1069
Deterministic Greenhouse Gas (CO2) Levels
(US Western Interconnect)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 528 of 1069
Total Generation Fuel Costs
US Western Interconnect
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 529 of 1069
“Expected Case” Resource Energy Mix
US Western Interconnect
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 530 of 1069
Stochastic Modeling Changes From Last TAC Meeting
Assumptions based on methodologies discussed in last TAC
meeting, with some exceptions.
Wind model randomly draws from 15 wind years for each study
year, previous TAC discussed drawing from 50 wind years for
the entire 20 years of each iteration.
Oil and wood price escalation will use lognormal distributions.
Natural gas price methodology is the same but will use historical
month-to-month standard deviation.
Adjustment developed for linking carbon prices to natural gas
prices, no carbon reduction case will have ~10% reduction to
natural gas prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 531 of 1069
Stochastic Electric Market Prices Compared to
Deterministic
Levelized Prices ($/MWh)
Deter.: $71.22
Mean: $74.48
Median: $73.16
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 532 of 1069
Range in Market Prices
Annual Flat Mid-Columbia
$0
$25
$50
$75
$100
$125
$150
$175
$200
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
$
p
e
r

M
W
h
Average Price
Minus One Stdev
Plus One Stdev
Tail Var 90
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 533 of 1069
Range in US-Western Interconnect Carbon Emissions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 534 of 1069
Resource Valuations Deterministic vs Stochastic
Example
Combined Cycle 2012 Operating Margin Simple Cycle 2012 Operating Margin
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 535 of 1069
Next Steps
1.Finalize “Expected Case” study
2.Portfolio Analysis
–Preferred Resource Strategy
–Efficient Frontier
–Resource cost/availability sensitivities
3.Deterministic Market Scenario Studies
–Resource portfolio scenario analysis
4.Stochastic Market Scenario Studies
– Alternative “risk” markets; i.e. no carbon case, gas volatility
–Alternative Efficient Frontier results
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 536 of 1069
Resource Requirement Projections
Clint Kalich
Technical Advisory Committee Meeting #4
2011 Electric Integrated Resource Plan
February 3, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 537 of 1069
Agenda
Reliability Modeling Update
Avista Reliance on Wholesale Marketplace
Shift from 1-Hour to 18-Hour Peaking Period
Regional Capacity Position
Avista Reliance on Wholesale Marketplace
Avista Resource Positions
Conclusions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 538 of 1069
Reliability Modeling Update
Completed Advanced Model Late 2010
Sophisticated hydro logic
Weather-dependent thermal logic
Robust representation of hourly loads
Time-series representation of data
Numerous Runs of Reliability Model
Results Indicate Key Assumption is Market Availability
More important than hydro, load, thermal resources
Yet Don’t Really Know What The Broader Market Looks Like
Negates Most Benefits (at least for IRP) of Reliability Model
Therefore a Simpler Approach Was Followed
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 539 of 1069
One-Hour vs. 18-Hour Sustained Peak
Historically Region (and Avista) Has Planned on One-Hour
Peak Demand Scenarios
Similar to Other Regions in WECC & NERC
Works Great for Thermal Systems Without Fuel Limits
Doesn’t Work As Well for Hydro Systems with a Limited Fuel
Source
Region Has Shifted from a One-Hour Peak to a 3-Day, 6 Hours
Per Day Sustained Demand Event
AKA 18-Hour Sustained Peak Event
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 540 of 1069
One-Hour vs. 18-Hour Sustained Peak
Affects (Lowers) Hydro Resource and Load Capabilities
No Assumed Impact on Thermal Operations
Except output is affected by assumed peak condition ambient
temperatures
Avista’s Method Relies Substantially on Northwest Power and
Conservation Council’s (“NWPP”) Work
24% Winter and 23% Summer Planning Margin
Compares to 15% assumption in 2009 IRP
Essentially the same as 2009 IRP assumption but operating
reserves are added
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 541 of 1069
Hydro 18-Hour Sustained Capacity Impacts
Avista’s System
116
2 4
122
7 3 3
13
0
20
40
60
80
100
120
140
Clark Fork Spokane Mid-C Total
me
g
a
w
a
t
t
s
18-Hour Capacity Reduction Summary
Winter
Summer
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 542 of 1069
Regional Capacity Position
NPCC Winter Assessment
-10%
0%
10%
20%
30%
40%
50%
60%
70%
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
Su
s
t
a
i
n
e
d

P
e
a
k

R
e
s
e
r
v
e

M
a
r
g
i
n
With Plan Resources
Hydro Flex
In-region
IPP
SW
Market
Adequacy Reserve Margin
Firm Resource
Reserve Margin
Threshold
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 543 of 1069
Regional Capacity Position
NPCC Summer Assessment
-10%
-5%
0%
5%
10%
15%
20%
25%
30%
35%
40%
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
Su
s
t
a
i
n
e
d

P
e
a
k

R
e
s
e
r
v
e

M
a
r
g
i
n
Plan
Resources
Hydro Flex
In-region
IPP
With Plan Resources
Firm Resource
Reserve Margin
Adequacy RM
Threshold
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 544 of 1069
Avista Reliance On Wholesale Market
Avista Relies on a “Modified” NWPP Load and
Resource Balance
Ignore aggressive conservation assumption
use Wood-Mac forecast of 0.9% regional load growth
No capacity contribution for wind (-250 MW)
10% wind capacity reserves (-500 MW)
Do not plan to interrupt wind at peak
5.5% of Regional Surplus is Available to Avista
Phased out over 10 years
10% reduction per year
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 545 of 1069
Regional Capacity Position Comparison
(8,000)
(6,000)
(4,000)
(2,000)
-
2,000
4,000
6,000
8,000
10,000
12,000
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
Regional Sustained Capacity Forecast Comparison
NPCC to Avista 2011 IRP
Winter - NPCC Case
Winter - Avista Mod
Summer - NPCC Case
Summer - Avista Mod
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 546 of 1069
Regional Capacity Position
Winter
-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
me
g
a
w
a
t
t
s
Regional Sustained Capacity Forecast -Winter
Resources
Avista Share
Load
Load w/Contingency
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 547 of 1069
Regional Sustained Capacity Position
Summer
-
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022
me
g
a
w
a
t
t
s
Regional Sustained Capacity Forecast -Summer
Resources
Avista Share
Load
Load w/Contingency
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 548 of 1069
Avista Energy Position
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Loads & Resources
(Average Annual Energy)
Hydro Resources Base/Intermediate Resources Net Firm Contracts
Peaking Resources Load Load + Contingency Planning
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 549 of 1069
Avista Energy Position
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
REQUIREMENTS
1 Native Load -1,109 -1,131 -1,148 -1,165 -1,186 -1,209 -1,228 -1,244 -1,260 -1,277 -1,293 -1,310 -1,333 -1,357 -1,386 -1,406 -1,429 -1,452 -1,477 -1,502
2 Firm Power Sales -138 -124 -107 -57 -57 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5 -5
3 Total Requirements -1,247 -1,256 -1,255 -1,222 -1,243 -1,214 -1,233 -1,249 -1,266 -1,282 -1,298 -1,316 -1,338 -1,362 -1,391 -1,411 -1,434 -1,457 -1,482 -1,508
RESOURCES
4 Firm Power Purchases 160 160 160 160 160 109 108 88 62 62 61 61 61 61 61 61 61 61 61 61
5 Hydro 519 525 528 496 496 496 492 481 481 481 481 481 481 481 481 481 481 481 481 481
6 Baseload/Intermediate Resources 755 714 751 744 746 741 724 758 721 721 758 721 721 758 684 515 541 515 515 541
7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
8 Total Resources 1,435 1,399 1,439 1,401 1,402 1,346 1,324 1,327 1,264 1,264 1,301 1,263 1,263 1,300 1,226 1,057 1,083 1,057 1,057 1,083
9 POSITION 188 144 184 179 159 131 91 78 -2 -18 2 -53 -75 -62 -165 -354 -351 -400 -425 -425
CONTINGENCY PLANNING
10 Peaking Resources 153 153 153 138 153 154 153 147 146 145 147 146 145 147 146 145 147 146 145 147
11 Contingency -227 -228 -228 -229 -230 -231 -232 -214 -195 -196 -197 -198 -199 -200 -201 -202 -203 -203 -204 -199
12 CONTINGENCY NET POSITION 113 69 109 88 82 54 12 11 -51 -69 -48 -105 -128 -115 -221 -411 -407 -458 -484 -476
Energy Margin 15%11%15%15%13%11%7%6%0%-1%0%-4%-6%-5%-12%-25%-24%-27%-29%-28%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 550 of 1069
Avista Winter Capacity Positions
0
500
1,000
1,500
2,000
2,500
3,000
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
18-Hour Loads & Resources
(January Peak)
Hydro Resources Base/Intermediate Resources Net Firm Contracts
Peaking Resources Regional Market Load
Load + Contingency Planning
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 551 of 1069
Avista Winter Capacity Positions
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
REQUIREMENTS
1 Native Load -1,661 -1,688 -1,704 -1,718 -1,751 -1,784 -1,814 -1,839 -1,866 -1,892 -1,919 -1,946 -1,982 -2,020 -2,062 -2,094 -2,131 -2,168 -2,208 -2,249
2 Firm Power Sales -238 -237 -207 -157 -157 -7 -7 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6 -6
3 Total Requirements -1,899 -1,925 -1,911 -1,874 -1,908 -1,790 -1,821 -1,846 -1,873 -1,899 -1,925 -1,953 -1,988 -2,027 -2,068 -2,101 -2,138 -2,174 -2,214 -2,256
RESOURCES
4 Firm Power Purchases 175 175 175 175 175 175 175 173 173 173 90 90 90 90 90 90 90 90 90 90
5 Hydro Resources 882 957 973 861 861 872 868 896 887 896 896 887 896 896 887 896 896 887 896 896
6 Base Load Thermals 895 895 895 895 895 895 895 895 895 895 895 895 895 895 895 606 606 606 606 606
7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
8 Peaking Units 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242 242
9 Total Resources 2,194 2,269 2,285 2,173 2,173 2,185 2,180 2,206 2,197 2,206 2,124 2,114 2,123 2,123 2,114 1,833 1,833 1,825 1,833 1,833
10 PEAK POSITION 295 344 374 299 266 394 360 360 325 307 199 162 135 96 46 -267 -304 -350 -381 -422
RESERVE PLANNING
11 Required Operating Reserves -162 -164 -163 -162 -165 -158 -160 -163 -164 -167 -173 -176 -179 -182 -186 -170 -171 -171 -172 -173
12 Available Operating Reserves 23 42 42 8 8 8 8 34 34 34 34 34 34 34 34 34 34 34 34 34
13 Planning Margin -233 -236 -239 -240 -245 -250 -254 -258 -261 -265 -269 -272 -277 -283 -289 -293 -298 -304 -309 -315
14 Total Reserve Planning -372 -358 -360 -394 -402 -399 -406 -387 -391 -398 -408 -414 -422 -431 -441 -429 -435 -441 -447 -454
15 Peak Position -76 -14 14 -95 -136 -5 -46 -26 -67 -91 -209 -253 -288 -335 -395 -697 -739 -790 -828 -876
16 Planning Margin 16%18%20%16%14%22%20%20%17%16%10%8%7%5%2%-13%-14%-16%-17%-19%
17 Avista Share of Excess NW Capacity 737 656 565 477 400 326 255 186 115 56 0 0 0 0 0 0 0 0 0 0
18 Peak Position Net Market 661 642 579 382 264 321 209 159 48 (35)(209)(253)(288)(335)(395)(697)(739)(790)(828)(876)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 552 of 1069
Avista Summer Capacity Positions
0
500
1,000
1,500
2,000
2,500
3,000
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
18-Hour Loads & Resources
(August Peak)
Hydro Resources Base/Intermediate Resources Net Firm Contracts
Peaking Resources Regional Market Load
Load + Contingency Planning
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 553 of 1069
Avista Summer Capacity Positions
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
REQUIREMENTS
1 Native Load -1,514 -1,556 -1,597 -1,644 -1,673 -1,701 -1,727 -1,748 -1,771 -1,793 -1,815 -1,838 -1,868 -1,900 -1,937 -1,964 -1,995 -2,026 -2,059 -2,094
2 Contracts Obligations -239 -214 -208 -158 -158 -8 -8 -8 -8 -8 -8 -8 -8 -8 -8 -8 -8 -8 -8 -8
3 Total Requirements -1,753 -1,770 -1,805 -1,802 -1,831 -1,709 -1,735 -1,756 -1,778 -1,800 -1,822 -1,846 -1,876 -1,908 -1,944 -1,972 -2,002 -2,033 -2,067 -2,102
RESOURCES
4 Contracts Rights 86 86 86 86 86 86 86 82 82 82 82 82 82 82 82 82 82 82 82 82
5 Hydro Resources 904 823 907 864 871 866 887 837 845 864 837 845 864 837 845 864 837 845 864 837
6 Base Load Thermals 799 799 799 799 799 799 799 799 799 799 799 799 799 799 799 551 551 551 551 551
7 Wind Resources 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0
8 Peaking Units 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176 176
9 Total Resources 1,964 1,884 1,968 1,925 1,932 1,927 1,948 1,895 1,903 1,922 1,895 1,902 1,921 1,894 1,902 1,673 1,646 1,653 1,673 1,646
10 PEAK POSITION 212 114 163 123 101 218 213 139 124 121 72 56 46 -14 -42 -299 -357 -380 -394 -456
RESERVE PLANNING
11 Required Operating Reserves -153 -156 -159 -160 -162 -155 -157 -160 -161 -163 -165 -167 -169 -172 -173 -157 -156 -157 -159 -158
12 Available Operating Reserves 155 66 171 159 159 159 161 158 158 161 158 158 161 158 158 161 158 158 161 158
13 Planning Margin -227 -233 -240 -247 -251 -255 -259 -262 -266 -269 -272 -276 -280 -285 -290 -295 -299 -304 -309 -314
14 Total Reserve Planning -227 -324 -240 -248 -255 -255 -259 -264 -269 -271 -279 -285 -289 -298 -305 -295 -299 -304 -309 -314
15 Peak Position -16 -211 -77 -125 -154 -38 -46 -125 -144 -150 -207 -228 -244 -312 -348 -593 -656 -684 -703 -770
16 Planning Margin 12%6%9%7%6%13%12%8%7%7%4%3%2%-1%-2%-15%-18%-19%-19%-22%
17 Avista Share of Excess NW Capacity 275 221 178 141 107 78 52 31 10 3 0 0 0 0 0 0 0 0 0 0
18 Peak Position Net Market 259 10 102 16 (47)40 6 (94)(134)(147)(207)(228)(244)(312)(348)(593)(656)(684)(703)(770)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 554 of 1069
Avista I-937 (Renewable Energy) Position
0
20
40
60
80
100
120
140
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
RPS Compliance Position
(Average Annual RECs)
Qualifying Resources Budgeted Resources Purchased RECs
REC Bank Requirment Requirement & Contingency
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 555 of 1069
Deficits Summary
-1,000
-800
-600
-400
-200
0
200
400
600
800
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
Energy (aMW)
Winter Capacity (MW)
Summer Capacity (MW)
RPS (aMW)
RP
S

-
20
1
6
En
e
r
g
y

-
20
2
0
Su
m
m
e
r

C
a
p
a
c
i
t
y

20
1
9
Wi
n
t
e
r

C
a
p
a
c
i
t
y

20
2
1
Avista 2011 IRP Positions Summary
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Energy (aMW)113 69 109 88 82 54 12 11 (51) (69)
Winter Capacity (MW)661 642 579 382 264 321 209 159 48 (35)
Summer Capacity (MW)259 10 102 16 (47) 40 6 (94) (134) (147)
RPS (aMW)17 25 30 32 (16) (46) (47) (47) (92) (93)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 556 of 1069
Impact of Resource Positions
Positions Determine Future Resource Needs
Targets are 2016 RECs and 2019 summer capacity
PRiSM Model Selects Resources Necessary to Fill Gaps That
Meet Various Criteria
Each New Resource Option Has Unique Capacity and Energy
Characteristics
e.g., wind “consumes” 10% of nameplate
Gas-fired plants generate monthly based on ambient temperatures
during peak weather events
High and Low Cases Indicate Impacts of Varying Load
Conditions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 557 of 1069
Portfolio and Market Scenario Planning
John Lyons
Technical Advisory Committee Meeting #4
2011 Electric Integrated Resource Plan
February 3, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 558 of 1069
Use of Scenarios in the IRP
Scenarios provide details about the impacts of different
planning assumptions
Avista’s current load and resource portfolio
Preferred Resource Strategy
Wholesale electric market
Different resource options
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 559 of 1069
Scenario Types for the 2011 IRP
1.Deterministic Market Scenarios
2.Stochastic Market Scenarios
3.Portfolio Scenarios
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 560 of 1069
2011 IRP Deterministic Market Scenarios
Deterministic scenarios test the Preferred Resource
Strategy (PRS) across several different futures
Low and High Gas Scenarios
High Wind Penetration Scenarios
Carbon Scenarios
Western Coal Plant Phase Out Scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 561 of 1069
2011 IRP Stochastic Market Scenarios
Expected Case –assumes average hydro, load, gas
prices, wind, emissions prices and forced outages
Volatile Fuel Scenario –test higher gas price volatility
Unconstrained Carbon Scenario –determines the
cost of different greenhouse gas emissions programs
Mandatory Coal Retirement Scenario –Western coal
plants automatically retired after 40 years of service
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 562 of 1069
Portfolio Scenarios
Market Reliance Only
Capacity Only
All CCCT and Wind
All SCCT and Wind
CO2 Credit Allocations
Nuclear Availability (2025)
2009 PRS
National Renewable Energy
Standard
CT& CCCT Tipping Point
Wind & Solar Tipping Point
Nuclear Tipping Point Analysis
Carbon Sequestration
Colstrip Scenarios:
Different O&M charges;
Early Retirement;
Incremental Pollution Control,
(sequestration); and
Railed coal
Others?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 563 of 1069
Avista’s 2011 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
Avista Headquarters – Spokane, Washington

Tuesday, April 12, 2011
Avista Conference Room 130

Topic Time Staff
1. Introduction 9:30 Storro

2. Conservation Avoided Cost Methodology 9:35 Gall

3. Conservation 9:45 Hermanson/
Global Energy
Partners

4. Draft Preferred Resource Strategy 11:15 Gall
Portfolio Alternatives & Scenarios

5. Lunch 12:15

6. Draft Preferred Resource Strategy 1:00 Gall
Portfolio Alternatives & Scenarios

7. Smart Grid 2:30 Kirkeby

8. Adjourn 3:30
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 564 of 1069
Conservation Avoided Costs
James Gall
Technical Advisory Committee Meeting #5
2011 Electric Integrated Resource Plan
April 12, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 565 of 1069
2011 Integrated Resource Plan Modeling Process
Preferred
Resource
Strategy
AURORA
“Wholesale Electric
Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Emission Pricing
Existing Resources
Resource Options
Transmission
Resource &
Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,
Capacity,
& RPS
Balances New Resource
Options & Costs
Cost Effective T&D
Projects/Costs
Cost Effective
Conservation
Measures/Costs
Mid-Columbia
Prices
Stochastic Inputs Deterministic Inputs
Capacity
Value
Avoided
Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 566 of 1069
How to Value Conservation
{(E + PC + R) * (1 + P)} * (1 + L) + DC * (1 + L)
Where:
E = market energy price (calculated by Aurora, including forecasted CO2 mitigation)
PC = new resource capacity savings (calculated by PRISM)
R = Risk premium to account for RPS and rate volatility reduction (calculated by PRISM)
P = Power Act preference premium (10% assumption)
DC = distribution capacity savings (~$10/kW-year based on Heritage Project calculation)
L = transmission and distribution losses (6.1% assumption based on Avista’s system average losses)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 567 of 1069
Efficient Frontier Approach
Assumes no additional Conservation Resources
Portfolio Cost
Po
r
t
f
o
l
i
o

R
i
s
k
Market
$70.50/
MWh
Capacity
$130/
kW-Yr
RPS + Risk
7.38/
MWh
Market Only Capacity Only
Capacity + RPS
PRS Mix
Efficient Frontier
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 568 of 1069
Avoided Cost Calculation
For 1 MW Measure With Flat Delivery
Item $/MWh
Energy Price 70.50
Capacity Savings 10.51
Risk Premium 7.38
Subtotal 88.39
Item $/MWh
10% Preference 8.84
Distribution Capacity Savings 1.14
T&D losses 6.02
Subtotal 16.00
Avoided Cost:
$104.39
per
MWh
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 569 of 1069
1
Avista Conservation
Potential Assessment
Electricity
Prepared for
Avista Utilities Technical Advisory Committee
by
Global Energy Partners
April 12, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 570 of 1069
Topics
Background and objectives
Study approach
Energy efficiency analysis results (electricity)
Demand response analysis
2Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 571 of 1069
Background and general objectives
Assess and analyze 20-year cost-effective energy efficiency (EE) potentials
Support Avista IRP development
Meet Washington I-937 Conservation Potential Assessment requirements
EE Potential assessment considers
Impacts of existing programs
Naturally occurring energy savings
Impacts of codes and standards
Technology developments and innovation
The economy and energy prices
Assess and analyze DR potentials
3Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 572 of 1069
Overview of EE analysis approach
4Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 573 of 1069
Base-year Energy Consumption
Base year is 2009
Most recent year with complete sales and customer data when study began
2009 also base year for Avista load research study
Market segmentation, based on rate classes
Residential (rate class 001), segmented by housing type and income
Single Family
Multi Family
Mobile Home
Limited Income
Commercial and Industrial
General Service (rate classes 011, 012)
Large General Service (rate classes 021, 022)
Extra Large Commercial GS (rate class 025C)
Extra Large Industrial GS (rate class 025C)
Pumping (rate classes 031, 032)
5Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 574 of 1069
Base-year Energy Consumption
2009 % of sales, Washington and Idaho
6Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 575 of 1069
Energy Market Profiles
Characterize energy use by sector, segment, end use, and
technology
Existing, replacement, and new construction
Accounts for
Naturally occurring conservation
Codes and standards
Previous DSM results
Equipment saturation and fuel shares
7
Residential Energy Use by End Use, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 576 of 1069
Baseline Forecast
Incorporates
Customer / market growth
Income growth
Avista retail rates forecast
Trends in end-use/technology saturations
Equipment purchase decisions
Elasticities for retail rates, income, persons per household
Accounts for
Naturally occurring conservation
Codes and standards
Previous DSM
8Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 577 of 1069
Baseline Forecast
9
Residential, total
Residential, per household
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 578 of 1069
Baseline Forecast
10
Commercial & Industrial
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 579 of 1069
Baseline Forecast
11
Overall 48% growth in electricity use.
Average annual growth rate of 1.7%
Comparable with Avista 2009 IRP
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 580 of 1069
Energy Efficiency Potential
Energy Efficient Equipment and Measures
2,808 equipment options and 1,524 other measures
Avista existing DSM programs
NEEA RTF
Sixth Power Plan database
Other utility programs
Measure characterization
Life
Energy and demand savings
Cost
Year off market (Standards)
Saturation
Applicability / Feasibility
12
Efficiency Level Useful Life Equipment
Cost
Energy Usage
(kWh/yr)
On
Market
Off
Market
SEER 13 15 $3,794 $1,619 2009 2014
SEER 14 (ENERGY STAR)15 $4,072 $1,485 2009 2032
SEER 15 (CEE Tier 2)15 $4,350 $1,435 2009 2032
SEER 16 (CEE Tier 3)15 $4,628 $1,393 2009 2032
Ductless Mini-split System 20 $8,193 $1,214 2009 2032
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 581 of 1069
Consistency with Sixth Plan
End-use model —bottom-up approach to understanding savings
Measure life
Stock accounting
Measure saturation and applicability
Accounts for
Naturally occurring conservation
Codes and standards
Measures include those in Sixth Plan (other measures also)
Considers both lost opportunity and non-lost opportunity
Economic potential, based on Total Resource Cost (TRC) test
Achievable potential considers realistic rate at which
technologies can be deployed
Maximum potential in 20 years is 85% of economic potential
13Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 582 of 1069
Energy Efficiency Potential
Savings could be acquired through a variety of
means
Market transformation, including NEEA
Utility programs
14Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 583 of 1069
Summary of EE results
Baseline forecast ― 48% growth (2032 vs. 2009)
Achievable potential ― 24% growth (2032 vs. 2009)
Energy efficiency offsets 50% of growth
15Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 584 of 1069
Summary of EE results (continued)
16
2012 2017 2022 2027 2032
Baseline Forecast (MWh) 8,799,079 9,464,078 10,417,644 11,537,369 12,852,394
Cumulative Energy Savings (MWh)
Achievable 49,428 393,796 931,744 1,514,569 2,105,572
Economic 219,482 1,371,691 2,289,256 2,802,046 3,228,731
Technical 301,070 1,967,390 3,327,203 4,116,738 4,697,328
Cumulative Energy Savings (% of Baseline)
Achievable 0.6% 4.2% 8.9% 13.1% 16.4%
Economic 2.5% 14.5% 22.0% 24.3% 25.1%
Technical 3.4% 20.8% 31.9% 35.7% 36.5%

Summary of Energy Savings from Energy Efficiency
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 585 of 1069
Summary of EE results (continued)
17
Summary of Peak Demand Savings from Energy Efficiency
2012 2017 2022 2027 2032
Baseline Forecast (MW) 1,780 1,881 2,080 2,306 2,567
Peak Savings (MWh)
Achievable 14 80 180 303 424
Economic 53 271 459 563 638
Technical 70 391 654 810 923
Peak Savings (% of Baseline)
Achievable 0.8% 4.3% 8.7% 13.1% 16.5%
Economic 3.0% 14.4% 22.1% 24.4% 24.8%
Technical 3.9% 20.8% 31.5% 35.1% 35.9%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 586 of 1069
Savings by Sector
18
2012 2017 2022 2027 2032
Cumulative Energy Savings (MWh)
Residential 25,651 127,984 331,874 606,994 896,296
C&I Total 23,777 265,812 599,870 907,575 1,209,276
Cumulative Energy Savings (% of total)
Residential 52% 33% 36% 40% 43%
General Service 9% 12% 10% 10% 9%
Large General Service 30% 42% 36% 32% 30%
Extra Large GS
Commercial 7% 8% 8% 7% 7%
Extra Large GS Industrial 3% 5% 10% 11% 11%
C&I Total 48% 67% 64% 60% 57%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 587 of 1069
Residential EE Results
19
2012 2017 2022 2027 2032
Baseline Forecast (MWh) 3,626,735 3,871,491 4,356,537 4,919,347 5,601,421
Cumulative Energy Savings (MWh)
Achievable 25,651 127,984 331,874 606,994 896,296
Economic 89,611 516,797 955,211 1,193,716 1,373,565
Technical 135,783 857,178 1,468,391 1,831,465 2,114,488
Cumulative Energy Savings (% of Baseline)
Achievable 0.7% 3.3% 7.6% 12.3% 16.0%
Economic 2.5% 13.3% 21.9% 24.3% 24.5%
Technical 3.7% 22.1% 33.7% 37.2% 37.7%

Savings by housing type, 2022
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 588 of 1069
Residential EE Results
20
Cumulative Energy Savings by End Use (MWh), Selected Years
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 589 of 1069
C&I EE Results
21
Savings by rate class, 2022
2012 2017 2022 2027 2032
Baseline Forecast (MWh) 5,172,344 5,592,586 6,061,107 6,618,022 7,250,973
Cumulative Energy Savings (MWh)
Achievable 23,777 265,812 599,870 907,575 1,209,276
Economic 129,871 854,893 1,334,045 1,608,330 1,855,166
Technical 165,288 1,110,212 1,858,812 2,285,273 2,582,839
Cumulative Energy Savings (% of Baseline)
Achievable 0.5% 4.8% 9.9% 13.7% 16.7%
Economic 2.5% 15.3% 22.0% 24.3% 25.6%
Technical 3.2% 19.9% 30.7% 34.5% 35.6%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 590 of 1069
C&I EE Results
22
Cumulative Energy Savings by End Use (MWh), Selected Years
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 591 of 1069
Avoided Cost Scenarios
23
Economic Potential, Cumulative Savings (MWh)
Economic potential is
69% of tech. potential
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 592 of 1069
Avoided Cost Scenarios
24
Economic Potential Case, Cumulative Savings (MWh)
55%
69%
76%
80% of technical potential
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 593 of 1069
Demand Response Analysis
Define the types of DR programs most suitable for
Avista
Determine DR potential
25
Demand Response Program Residential General
Service
Large
General
Service
Extra Large
General
Service
Pumping
Direct Load Control
Mass Market Direct Load
Control x x
Direct Load Control x x x
Other Programs
Demand Bidding / Buyback x x
Curtailable/Interruptible x x
Auto DR / Fast DR x x x x
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 594 of 1069
Deliverables from CPA analysis
Final report electricity
EE approach and results
DR approach and results
Appendices
LoadMAP models
Gas potential study
26Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 595 of 1069
Contact Information
Ingrid Rohmund
[e-mail]
760-943-1532
Jan Borstein
[e-mail]
303-530-5195
27Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 596 of 1069
Preferred Resource Strategy &
Scenario Analysis
(Preliminary Draft)
James Gall
Technical Advisory Committee Meeting #5
2011 Electric Integrated Resource Plan
April 12, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 597 of 1069
DRAFT
2011 Integrated Resource Plan Modeling Process
Preferred
Resource
Strategy
AURORA
“Wholesale Electric
Market”
500 Simulations
PRiSM
“Avista Portfolio”
Efficient Frontier
Fuel Prices
Fuel Availability
Resource Availability
Demand
Emission Pricing
Existing Resources
Resource Options
Transmission
Resource &
Portfolio
Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,
Capacity,
& RPS
Balances New Resource
Options & Costs
Cost Effective T&D
Projects/Costs
Cost Effective
Conservation
Measures/Costs
Mid-Columbia
Prices
Stochastic Inputs Deterministic Inputs
Capacity
Value
Avoided
Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 598 of 1069
DRAFT
PRiSM Objective Function
Linear program solving for the optimal resource strategy to meet
resource deficits over planning horizon.
Model selects its resources to reduce cost, risk, or both.
Minimize:Total Power Supply Cost on NPV basis (2012-2052 with
emphasis on first 11 years of the plan)
Subject to:
•Risk Level
•Capacity Need +/- deviation
•Energy Need +/- deviation
•Renewable Portfolio Standards
•Resource Limitations and Timing
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 599 of 1069
DRAFT
Efficient Frontier
Demonstrates the trade off of cost and risk
Avoided Cost Calculation
Ri
s
k
Least Cost Portfolio
Least Risk Portfolio
Find least cost portfolio
at a given level of risk
Short-Term
Market
Market + Capacity + RPS = Avoided Cost
Capacity
Need
+ Risk
Cost
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 600 of 1069
DRAFT
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
Loads & Resources
(Average Annual Energy)
Hydro Resources Base/Intermediate Resources Net Firm Contracts
Peaking Resources Load Load + Contingency Planning
Energy Load & Resource Balance (Includes Conservation)
19 aMW 54 aMW 345 aMW 406 aMW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 601 of 1069
DRAFT
0
500
1,000
1,500
2,000
2,500
3,000
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
18-Hour Loads & Resources
(January Peak)
Hydro Resources Base/Intermediate Resources Net Firm Contracts
Peaking Resources Regional Market Load
Load + Contingency Planning
Winter 18 Hr Peak Load & Resource Balance
(Includes Conservation)
148 MW 608 MW 779 MW249 MW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 602 of 1069
DRAFT
0
500
1,000
1,500
2,000
2,500
3,000
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
18-Hour Loads & Resources
(August Peak)
Hydro Resources Base/Intermediate Resources Net Firm Contracts
Peaking Resources Regional Market Load
Load + Contingency Planning
Summer 18 hr Peak Load & Resource Balance
(Includes Conservation)
56 MW32MW 150 MW 500MW 667 MW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 603 of 1069
DRAFT
REC Contingency & Banking
Reserve requirement-Must hold REC reserves in “REC Bank”
each year.
–Sales uncertainty (5%)
–Hydro uncertainty (26%)
–Wind uncertainty (30%)
–Currently 8 aMW
Roll over rights- RECs can be used for prior year or future year.
Plan is to use 2011 REC for 2012, then excess 2012 RECs can
be used for 2013.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 604 of 1069
DRAFT
WA State Renewable Portfolio Standard Compliance
(Does Not Include Contingency)
0
20
40
60
80
100
120
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
RPS Compliance Position
(Average Annual RECs)
Qualifying Resources Budgeted Resources Purchased RECs Used Bank Requirment
38 aMW 82 aMW 88 aMW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 605 of 1069
DRAFT
Actual Efficient Frontier Results
$60
$65
$70
$75
$80
$85
$90
$95
$100
$450 $500 $550 $600 $650 $700
20

Y
r

L
e
v
e
l
i
z
e
d

A
n
n
u
a
l
Po
w
e
r

S
u
p
p
l
y

S
t
d
e
v
20 Yr Levelized Annual Power Supply Rev. Req.
Capacity
Only
Least
Cost
Least
Risk
PRS
Market
Only
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 606 of 1069
DRAFT
Actual Efficient Frontier Results As a Percent of
Market Only Portfolio
-30%
-25%
-20%
-15%
-10%
-5%
0%
0%5%10%15%20%25%30%
20

Y
r

L
e
v
e
l
i
z
e
d

A
n
n
u
a
l
Po
w
e
r

S
u
p
p
l
y

S
t
d
e
v

P
e
r
c
e
n
t

C
h
a
n
g
e

C
o
m
p
a
r
e
d

t
o

Ma
r
k
e
t

O
n
l
y
20 Yr Levelized Annual Power Supply Rev. Req. Percent Change
Compared to Market Only
Capacity
Only
Least
Cost
Least
Risk
PRS
Market
Only
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 607 of 1069
DRAFT
2009 Draft Preferred Resource Strategy
Year Ending Resource
2012 150 MW NW Wind (48 aMW)
2013-2015 Little Falls Unit Upgrades (0.9 aMW)
2019 150 MW NW Wind (50 aMW)
2019 Combined Cycle CT (250 MW)
2020 Upper Falls Upgrade (1 aMW)
2022 50 MW NW Wind (17 aMW)
2024 Combined Cycle CT (250 MW)
2026/27 Combined Cycle CT (250 MW)
2010+Distribution Feeder Upgrades (2.7 aMW by 2029)
2010+Conservation (226 aMW by 2029)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 608 of 1069
DRAFT
2011 Draft Preferred Resource Strategy
Year Ending Resource
2012 Wind (~42 aMW REC)
2018 Simple Cycle CT(~83 MW)
2020 Simple Cycle CT (~83 MW)
2018-2019 Thermal Upgrades (~ 7 MW)
2018-2019 Wind (~43 aMW REC)
2023 Combined Cycle CT (~ 270 MW)
2026/27 Combined Cycle CT (~270 MW)
2029 Simple Cycle CT (~46 MW)
2012+Distribution Feeder Upgrades (13 aMW by 2031)
2012+Conservation (310 aMW by 2031)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 609 of 1069
DRAFT
2011 IRP Comparison to 2009 IRP
2019: CCCT Replaced With Two CTs Over 3 Years
2012: Less Wind (42 aMW vs. 48 aMW)
2024/2027: CCCT Need Remains
2020: Less Wind (43 aMW vs. 50 aMW)
2022: Wind Need Eliminated (-17 aMW)
2030: Additional 46 MW CT
84 aMW Increased Conservation Over 20 Years
10 aMW Increased Distribution Losses Savings over 20 years
Changes in Hydro Upgrade Assumptions
–Little Falls in-kind replacement instead of upgrade
–Upper Falls upgrade removed pending further study
Upper Falls upgrade deferred to next IRP
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 610 of 1069
DRAFT
Winter Capacity Load and Resources
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
Market
New Simple Cycle CC
New Combined Cycle CC
New Wind
Other
Distribution Efficiency
Existing Resources
Load w/o DSM+PM
Load w/ DSM+PM
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 611 of 1069
DRAFT
Summer Capacity Load and Resources
UPDATE
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
me
g
a
w
a
t
t
s
Market
New Simple Cycle CC
New Combined Cycle CC
New Wind
Other
Distribution Efficiency
Existing Resources
Load w/o DSM+PM
Load w/ DSM+PM
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 612 of 1069
DRAFT
Annual Average Energy Load and Resources
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
av
e
r
a
g
e

m
e
g
a
w
a
t
t
s
New Simple Cycle CC
New Combined Cycle CC
New Wind
Other
Distribution Efficiency
Existing Resources
Load w/o DSM+Cont.
Load w/ DSM+Cont.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 613 of 1069
DRAFT
I-937 Table (aMW REC)
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021
Beginning Bank 17 7 19 19 42 47 51 55 59 36
Requirement 0 (19)(19)(19)(19)(59)(59)(60)(60)(101)(102)
Current Available 17 23 26 28 28 22 22 22 22 22 22
New Qualifying RECs 0 0 42 42 42 42 42 42 42 57 85
Sold Qualifying RECs 0 (14)(37)(50)(28)0 0 0 0 0 (5)
End Bank 17 7 19 19 42 47 51 55 59 36 36
Contingency Bank 0 7 8 8 8 23 23 23 23 36 36
2022 2023 2024 2025 2026 2027 2028 2029 2030 2031
Beginning Bank 36 36 36 36 39 42 43 44 43 42
Requirement (103)(103)(103)(104)(105)(106)(107)(108)(109)(110)
Current Available 22 22 22 22 22 22 22 22 22 22
New Qualifying RECs 85 85 85 85 85 85 85 85 85 85
Sold Qualifying RECs (5)(4)(4)(0)0 0 0 0 0 0
End Bank 36 36 36 39 42 43 44 43 42 39
Contingency Bank 36 36 36 36 37 38 38 38 39 39
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 614 of 1069
DRAFT
Preferred Resource Strategy Annual Costs per MWh
Expected Market Conditions (80% Credit Allocation)
(Includes all Power Supply Costs except Capital Plant in Rate Base)
$0
$20
$40
$60
$80
$100
$120
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
$
p
e
r

M
W
h
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 615 of 1069
DRAFT
Preferred Resource Strategy Annual Costs per MWh
No Carbon Legislation
(Includes Power Supply Costs except Capital Plant in Rate Base)
$0
$20
$40
$60
$80
$100
$120
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
$
p
e
r

M
W
h
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 616 of 1069
DRAFT
Greenhouse Gas Emissions (millions of short tons)
-
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
To
n
s

p
e
r

M
W
h
Mi
l
l
i
o
n
s
Greenhouse Gas Emissions
New Resources
Existing Resources
Tons per MWh of Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 617 of 1069
DRAFT
Greenhouse Gas Cost
UPDATE
$0
$50
$100
$150
$200
$250
$300
$350
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
In
c
r
e
m
e
n
t
a
l

A
n
n
u
a
l

C
o
s
t

o
f

C
a
r
b
o
n

Le
g
i
s
l
a
t
i
o
n
0% Allocation
25% Allocation
50% Allocation
Base Case (Declining 80%)
100% Allocation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 618 of 1069
DRAFT
PRS Capital Requirements (millions $)
-
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
-
50
100
150
200
250
300
350
400
450
500
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
Cu
m
u
l
a
t
i
v
e

A
d
d
i
t
i
o
n

t
o

R
a
t
e

B
a
s
e
An
n
u
a
l

A
d
d
i
t
i
o
n

t
o

R
a
t
e

B
a
s
e
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 619 of 1069
DRAFT
Alternative Strategies Comparison
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
-15%-10%-5%0%5%10%15%
An
n
u
a
l

L
e
v
e
l
i
z
e
d

2
0

y
r

S
t
d
e
v

a
s

P
e
r
c
e
n
t

Ch
a
n
g
e

c
o
m
p
a
r
e
d

t
o

P
R
S
Annual 20 yr Levelized Cost Percent Change as Compared to PRS
National RES
125% of AC for DSM
CCCT/Wind/Solar post '20
150%of AC for DSM
No DSM PRS "like"
PRS-but no Wind
Pay75%of AC for DSM
PRS NoAppr. RECPRS
Efficient Frontier
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 620 of 1069
DRAFT
Capital Expenditures (Alternative Portfolios)
0 500 1,000 1,500 2,000 2,500 3,000 3,500
Capacity Only
PRS No Wind
Least Cost
Very High DSM
PRS
Low DSM
High DSM
PRS No Apprentice …
Mid-High risk
Mid Risk
Colstrip Retire 2025
CCCT/Wind
Mid-Low Risk
CCCT-Wind-Solar
National RES
No DSM
Low Risk
Least Risk
Nominal Capital Cost (Millions)
First 10 Years
Last 10 Years
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 621 of 1069
DRAFT
Base Case Efficient Frontier Compared to No Carbon
Costs Efficient Frontier
$50
$55
$60
$65
$70
$75
$80
$85
$90
$95
$100
$450 $500 $550 $600 $650 $700
20

Y
r

L
e
v
e
l
i
z
e
d

A
n
n
u
a
l
Po
w
e
r

S
u
p
p
l
y

S
t
d
e
v
20 Yr Levelized Annual Power Supply Rev. Req.
Capacity
Only
Least Cost
Least
Risk
PRS
Market
Only
Least
Cost
Least
Risk
PRS
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 622 of 1069
DRAFT
Power Supply Cost Expected and Historical Growth
Index
0
20
40
60
80
100
120
140
160
180
200
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
20
3
0
Po
w
e
r

S
u
p
p
l
y

C
o
s
t

I
n
d
e
x

Re
a
l

$

(
2
0
1
2

=

1
0
0
)
Historical Energy Crisis
Expected Case Forecast Unconstrained Carbon Forecast
Linear (Historical)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 623 of 1069
DRAFT
Resource Cost Tipping Point Analysis
Target
Resource
Capital
Cost ($/kW)
Required
Cost to be
Selected
($/kW)
Percent
Reduction
CCCT to replace SCCT to be
least cost (2024)
$1,609 $1,255 -22%
Wind shift to Solar (2020)
(2x REC included)
$4,371 $2,052 -53%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 624 of 1069
Market Scenario Analysis Update
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 625 of 1069
DRAFT
Mid-Columbia Electric Price Forecast
$0
$20
$40
$60
$80
$100
$120
$140
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
$
p
e
r

M
W
h
Expected Case Stochastic Expected Case Deterministic
National Cap & Trade National Carbon Tax
Regional Carbon Policy No Carbon Policy
Low Natural Gas Prices High Natural Gas Prices
Coal Plant Retirement
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 626 of 1069
DRAFT
US WECC GHG Emissions
0
50
100
150
200
250
300
350
400
450
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
Mi
l
l
i
o
n
s

o
f

G
H
G

T
o
n
s
Expected Case Deterministic National Cap & Trade
National Carbon Tax Regional Carbon Policy
No Carbon Policy Low Natural Gas Prices
High Natural Gas Prices Coal Plant Retirement
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 627 of 1069
DRAFT
Next Steps
Obtain internal feedback and approvals of Preferred Resource
Strategy
Compare alternative resource portfolios using alternative market
conditions
Compare efficient frontier analysis with additional stochastic
market analysis (i.e. coal plant retirement/Volatile NG)
Further investigate Demand Response cost/benefits
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 628 of 1069
Smart Grid Project Overview
TAC Meeting –April 12, 2011
Curtis Kirkeby, P.E.
Sr. Electrical Engineer –SGDP Principal Investigator
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 629 of 1069
Avista Smart Grid Grants
4
Smart Grid Investment Grant (SGIG)
•Automated switching
devices
•Larger wire
•Energy saving
electronic devices
Spokane, WA
Smart Grid Demonstration Project (SGDP)
Pullman, WA
Smart Grid Workforce Training Grant
Jack Stewart Training Center - Spokane, WA
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 630 of 1069
Five state partnership:Industry, Education, Labor
Benefits to Our Region –
Local facility to train on new technology
Leverage training needs of other Avista grants; build new curriculum
Federal dollars to update existing training and facilities to up-skill current
and future workers
Award:$5.0 m over 3 years
Avista portion of award:$1.3 m over 3 years
Grant Partner match $6.8 m over 3 years
16
Smart Grid Workforce Training Grant
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 631 of 1069
Smart Grid Training Delivery
Smart Grid Training Portal
Share Best Practices on Smart Grid Training
“Create an
effective and
efficient electric
power workforce
proficient in
smart grid
competencies”
18
Grant Objectives
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 632 of 1069
Construct a training substation for training on smart grid
technology
Update training programs to incorporate smart grid
technology
On-line curriculum to be shared by utilities and colleges
19
Avista Objectives
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 633 of 1069
•Target
•59 Distribution Circuits
•110,000 Electric Customers
•14 Substations
Loss Reduction –42,000 Mega watt hours/Year
Green House Gas Reduction: 14,000 Tons
2500 Homes/Year
5
SGIG –Spokane, WA
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 634 of 1069
4,385
34,839
2,827
Capacitors
Conservation Voltage Reduction
Reconductor
Carbon Reduction: 14,360 Tons a year.
•$50/Ton to Sequester
•$718,000/year.
SGIG –Benefits
Savings
(MWh)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 635 of 1069
Communication:
•Wireless to Field Devices
•Fiber to Substations
Field Equipment
•Switches and Reclosers
•Capacitor Banks
•Voltage Regulators
Distribution Management System (DMS)
•Remotely Control and Operate Distribution
Equipment
•Continually Analyzing the System for
Optimization
•Automated Fault Detection Isolation and
Restoration
6
SGIG –Enabling Technologies
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 636 of 1069
15.59 10
50 2716.56
52
141
94
0
20
40
60
80
100
120
140
160
180
200
Reconductor
(miles)
Viper Scadamate Caps
Distribution Construction
To Be Completed Completed
1
129
18
120 125
10
13
27
115
0
20
40
60
80
100
120
140
Substation
Complete To Be Completed
8
SGIG –Construction
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 637 of 1069
$-
$50.0
$100.0
$150.0
$200.0
NWSG SGDP
$89.0
$18.9
$89.0
$14.9
$4.0
Partners
AVA
NWSG
DOE
9
SGDP –Demonstration Project
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 638 of 1069
Battelle
NW
Bonneville
Power
Administration 3 Tier
Areva
IBM
Netezza
Quality LogicUtility Partners
Avista
Benton PUD
City of Ellensburg
Flathead Electric
Idaho Falls Power
Lower Valley Energy
Milton-Freewater
Northwestern Energy
Peninsula Light
PGE
Seattle City Light (UW)
Smart Grid
National
Energy
Technology
Laboratory
10
SGDP –Regional Players
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 639 of 1069
3 substations
Regulator controls
Reclosers/relays
13 circuits
45 automated line switches & reclosers
20 switched and fixed capacitor
Fault Indicators
Low loss transformers w/
communications
Wireless & fiber communications
11
SGDP –System Elements
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 640 of 1069
≈ 14,000 Residential / Commercial Electric Meters
≈ 6000 Residential / Commercial Gas Meter Registers
Wireless Communication w/ Fiber Backhaul
Remote Service Switch
Back Office Software Systems
12
SGDP –Itron Open Way AMI
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 641 of 1069
Customer Web Portals
13 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 642 of 1069
In-Home Displays
14 Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 643 of 1069
Transactional
Signal Engine
Value Wind/Solar
Forecasting
Regional
Generation
Responsive
Assets
Pullman
Area
Load
Value Signal
Response SignalInternet
15
SGDP –Transactional Signal
•WSU Air Handlers
•WSU Chillers
•WSU Generators
•Residential Set
back Thermostat
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 644 of 1069
15
SGDP –Construction
0%
25%
50%
75%
100%
14%
0%0%
25%
82%
0%
67%
0%0%
% Complete
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 645 of 1069
15
Smart Grid Energy Impacts
SGIG (MWh)SGDP (MWh)
Year Cumulative I-937 Cumulative I-937
2010 1500 1500 0 0
2011 7212 5712 286 286
2012 42051 34839 286 0
2013 42051 0 6763 6477
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 646 of 1069
15
Future Programs
FEEDERREBUILDS
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 647 of 1069
Primary Goals
Reconductor
Approximately 4 miles of 3 phase trunk
Approximately 5 miles of lateral
Transformer replacement
~320 OH transformers w. Wildlife Guards
~12 Submersibles
Wood pole management follow up
Vegetation Management
Open Wire Secondary
9th and Central 12F4 (9CE12F4) -2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 648 of 1069
9CE12F4 Reconductor
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 649 of 1069
Good opportunity to move facilities
where it makes sense for reliability
and future maintenance and access
9CE12F4 Realignment
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 650 of 1069
•All pre-2004 OH transformers replaced with new high
efficiency units
•Lower core losses account for ~31 ave. kW
9CE12F4 Transformer Replacement
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 651 of 1069
54 total transformers with Open Wire secondary
9CE12F4 Open Wire Secondary
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 652 of 1069
•Clear understanding of the state of facility
•Understanding of work & resource staging
•Understanding of volt/var and voltage reduction
opportunity
•Baseline for savings validation
•Future rebuilds are warranted
9CE12F4 Outcome
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 653 of 1069
15
Future Programs
FEEDERREBUILDS
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 654 of 1069
15
Feeder Rebuilds
•Detailed analysis has been completed for six feeders
•Results extrapolated to the remaining feeders
•The top 60 feeders targeted for energy savings in IRP
•Schedule is being developed based on resource
availability
•Rebuilds to begin in 2013
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 655 of 1069
Questions?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 656 of 1069
Avista’s 2011 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 6 Agenda
Avista Headquarters – Spokane, Washington

Thursday, June 23, 2011
Avista Conference Room 130

Topic Time Staff
1. Introduction 9:30 Storro

2. High Wind Market Analysis 9:35 Kalich

3. PRS & Scenario Analysis 10:15 Gall

4. IRP Action Items 11:15 Lyons

5. IRP Section Highlights 11:45 Kalich

6. Lunch 12:15

7. Adjourn

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 657 of 1069
High Wind Market Analysis
James Gall
Technical Advisory Committee Meeting #6
2011 Electric Integrated Resource Plan
June 23, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 658 of 1069
Pacific Northwest wind fleet by
balancing authority (~5,200 MW)
2/3 of NW wind fleet is on BPA system
–10,500 MW peak load
–80% exported to other utilities
–BPA balance authority forecast
•5,250 MW in 2012
•8,700 MW in 2020
Wind Turbines Are Getting Bigger
17 m
47 m
80 m
100 m
115 m
19
8
5
19
9
9
20
0
3
20
1
0
St
a
t
e
-of
-
Ar
t
Wind Turbine
Rotor Diameter
Bonneville ~3,500 MW
PacifiCorp ~1,400 MW
Puget Sound Energy *275 MW
Avista 35 MW
* PSE has 430 MW of wind, 155 MW is in Bonneville’s balancing area
Northwest Wind Facts
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 659 of 1069
NW Wind Exports (MW)
NW Wind Fleet Locations
0
200
400
600
800
1,000
WA OR ID MT
1,876 MW
37%of Fleet
Northwest Wind Resource Locations & Exports
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 660 of 1069
Source: RNP.org
Northwest Wind Fleet Locations
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 661 of 1069
Northwest Wind Capacity Past and Future
Historical data provided by RNP website
0
2,000
4,000
6,000
8,000
10,000
12,000
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
Me
g
a
w
a
t
t
s
2011 IRP Forecast
MT
ID
OR
WA
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 662 of 1069
Understand impact to the power system with more than
forecasted amount of wind generation
Uses IRP Expected Case for 2015
Adjust model to allow for negative pricing using -$40/MWh for
Northwest hydro projects and -$10 to -$30/MWh for wind projects
Run 100 iterations for each of these scenarios
–Add 2,000 MW of wind
–Add 5,000 MW of wind
–Add 10,000 MW of wind
Study Scope
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 663 of 1069
Negative Price Impact to IRP Expected Case Market
Forecast
$40
$45
$50
$55
$60
$65
$70
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
$
p
e
r

M
W
h
IRP Expected Case
Expected Case w/ Negative Prices
Annual price change is -0.3%, Q2 would be 2.2% lower
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 664 of 1069
-45%
-40%
-35%
-30%
-25%
-20%
-15%
-10%
-5%
0%
Ja
n
Fe
b
Ma
r
Ap
r
Ma
y
Ju
n
Ju
l
Au
g
Se
p
Oc
t
No
v
De
c
An
n
u
a
l
Pe
r
c
e
n
t

C
h
a
n
g
e
+ 2,000 MW
+ 5,000 MW
+ 10,000 MW
Wind Scenarios: Change to Monthly Average Mid-
Columbia Electric Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 665 of 1069
-
200
400
600
800
1,000
1,200
1,400
1,600
Expected Case + 2,000 MW + 5,000 MW + 10,000 MW
nu
m
b
e
r

o
f

h
o
u
r
s
10th percentile
Avg
Median
90th percentile
Wind Scenarios: Change to Occurrences of Negative
Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 666 of 1069
Wind Scenarios: Negative Price Duration Curve
-40
-35
-30
-25
-20
-15
-10
-5
0
0.
0
%
0.
5
%
1.
0
%
1.
5
%
2.
0
%
2.
5
%
3.
0
%
3.
5
%
Percent of Hours in Year
Expected Case + 2,000 MW
+ 5,000 MW + 10,000 MW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 667 of 1069
-40%
-20%
0%
20%
40%
60%
80%
100%
120%
Hydro
Portfolio
Colstrip Coyote
Springs 2
Boulder Park Rathdrum CT
Pe
r
c
e
n
t

C
h
a
n
g
e
+ 2,000 MW
+ 5,000 MW
+ 10,000 MW
Wind Scenarios: Change to Avista Plant Operating
Margins
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 668 of 1069
Preferred Resource Strategy &
Scenario Analysis
James Gall
Technical Advisory Committee Meeting #6
2011 Electric Integrated Resource Plan
June 23, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 669 of 1069
Natural Gas Price Forecast (Henry Hub)
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
Do
l
l
a
r
s

p
e
r

D
e
c
a
t
h
e
r
m
Expected Case Consultant 1 Consultant 2 Market
$7.30
$8.87
$5.93
Nominal
Levelized
Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 670 of 1069
Expected Case: Mid-Columbia Electric Price Forecast
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
1
2
-31
$
p
e
r

M
W
h
90th Percentile
10th Percentile
TailVar 90
Mean
20 Year Levelized Price of $70.50 ($54 to $87) per MWh
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 671 of 1069
Mid-Columbia Electric Price Forecast
Nominal 20 year Levelized Prices
$70.50
$77.94
$72.34
$65.37
$50.18
$0.00
$20.00
$40.00
$60.00
$80.00
$100.00
Expected
Case
National Cap
& Trade
National
Carbon Tax
Regional
Carbon Policy
No Carbon
Policy
$
p
e
r

M
W
h
Scenarios are deterministic study results
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 672 of 1069
Western Interconnect Greenhouse Gas Forecast
0
50
100
150
200
250
300
350
400
450
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
Mi
l
l
i
o
n
s

o
f

S
h
o
r
t

T
o
n
s
National Cap & Trade
National Carbon Tax
Regional Carbon Policy
No Carbon Policy
Expected Case
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 673 of 1069
Mandatory Coal Retirement Scenario
Coal plants are to be phased out after 40 years of life.
No greenhouse gas penalties
Uses Expected Case’s natural gas forecast
Modeled stochastically using 500 iterations
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 674 of 1069
Mid-Columbia Electric Price Forecast
$0
$20
$40
$60
$80
$100
$120
$140
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
$
p
e
r

M
W
h
Coal Mandaotory Retirement
Expected Case
National Cap & Trade
Unconstrained Carbon Case
$77.94
$70.50
$57.01
$52.86
Levelized
Cost
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 675 of 1069
Greenhouse Gas and Costs of Carbon Mitigation
Scenarios
Market Scenario
Change to
GHG
Emissions
From 2012
by 2031
Added
Levelized
Cost per Year
(Billions)
Unconstrained GHG Gas Case 14%0.0
Expected Case -18%3.5
Coal Mandatory Retirement -22%8.1
National Cap & Trade -29%4.9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 676 of 1069
Mid-Columbia Price Forecast with
Natural Gas Price Sensitivities
$0
$20
$40
$60
$80
$100
$120
$140
$160
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
$
p
e
r

M
W
h
High Natural Gas Prices
Expected Case
Low Natural Gas Prices
$70.50
$82.17
$57.00
Nominal
Levelized
Costs
All cases have the same greenhouse reduction goal, but have different prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 677 of 1069
2011 Draft Preferred Resource Strategy
Year Ending Resource
2012 Wind (~42 aMW REC)
2018 Simple Cycle CT(~83 MW)
2020 Simple Cycle CT (~83 MW)
2018-2019 Thermal Upgrades (~ 7 MW)
2018-2019 Wind (~43 aMW REC)
2023 Combined Cycle CT (~ 270 MW)
2026/27 Combined Cycle CT (~270 MW)
2029 Simple Cycle CT (~46 MW)
2012+Distribution Feeder Upgrades (13 aMW by 2031)
2012+Conservation (310 aMW by 2031)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 678 of 1069
Conservation Projection
0
88
175
263
350
0
5
10
15
20
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Av
e
r
a
e
g

M
e
g
a
w
a
t
t
s
Avista
Regional (NEEA)
Cumulative
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 679 of 1069
Avista Resource’s Greenhouse Gas Emissions
-
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4.00
4.50
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
Sh
o
r
t

T
o
n
s

p
e
r

M
W
h
Sh
o
r
t

M
i
l
l
i
o
n
s
GHG Reduction due to Legislation
New Resources
Existing Resources
Tons per MWh of Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 680 of 1069
Efficient Frontier
$60
$65
$70
$75
$80
$85
$90
$95
$100
$450 $500 $550 $600 $650 $700
20

Y
r

L
e
v
e
l
i
z
e
d

A
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20 Yr Levelized Annual Power Supply Rev. Req.
Capacity
Only
Least
Cost
Least
Risk
PRS
Market
Only
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 681 of 1069
Efficient Frontier with Alternative Greenhouse Gas
Methodologies
$50
$55
$60
$65
$70
$75
$80
$85
$90
$95
$100
$450 $500 $550 $600 $650 $700
20

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20 Yr Levelized Annual Power Supply Rev. Req.
Expected Case Unconstrained CO2 Case Mandatory Coal Retirement Future
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 682 of 1069
Greenhouse Gas Methodologies Summary
Expected Case
Unconstrained
Carbon
Coal
Retirement
2012-2022 Cost NPV 3,094 2,886 2,937
2012-2031 Cost NPV 5,735 5,168 5,458
2022 Expected Cost 636 564 576
2022 Stdev 91 68 71
2022 Stdev/Cost 14%12%12%
2022 CO2 Emissions (000’s)2,894 3,498 3,752
2031 CO2 Emissions (000’s)2,972 4,177 3,560
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 683 of 1069
Power Supply Cost/MWh Index
0
20
40
60
80
100
120
140
160
180
200
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
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1
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)
Historical Energy Crisis
Expected Case Forecast Unconstrained Carbon Forecast
Linear (Historical)
4.1% + Inflation
3.8% + Inflation
2.6% + Inflation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 684 of 1069
Power Supply Costs with Alternative Natural Gas
Prices (Preferred Resource Strategy)
-$400
-$300
-$200
-$100
$0
$100
$200
$300
$400
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
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20
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20
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20
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20
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20
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20
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1
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s
5th Percentile
95th Percentile
High Gas Price Scenario
Low Gas Price Scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 685 of 1069
Efficient Frontier vs Alternative Portfolios
-20%
-15%
-10%
-5%
0%
5%
10%
15%
20%
-15%-10%-5%0%5%10%15%
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S
Annual 20 yr Levelized Cost Percent Change as Compared to PRS
National RES
125% of AC for DSM
CCCT/Wind/Solar post '20
150%of AC for DSM
No DSM PRS "like"
PRS-but no Wind
Pay75%of AC for DSM
PRS NoAppr. RECPRS
Efficient Frontier
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 686 of 1069
Load Growth Sensitivities
Base Case Low Load
Growth
High Load
Growth
Levelized Cost $/MWh 49.75 44.11 54.86
1 Sigma Lower 42.67 36.99 47.80
1 Sigma Higher 56.83 51.23 61.92
$0
$10
$20
$30
$40
$50
$60
$70
$/
M
W
h
0.0%
0.5%
1.0%
1.5%
2.0%
2.5%
3.0%
3.5%
4.0%
Low Load Forecast Expected Case High Load Forecast
an
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No Conservation
Existing Conservation Trends
Includes New & Existing Conservation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 687 of 1069
Portfolio Resources (MW)
Portfolio SC
C
T

(N
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(E
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)
Preferred Resource Strategy 212 540 4 71 0 310 13
Least Cost 747 0 0 71 0 310 13
Least Risk 187 540 17 98 64 310 13
50% Cost/50% Risk 177 540 4 93 9 310 13
75% Cost/ 25% Risk 332 540 0 82 0 310 13
25% Cost/ 75% Risk 83 810 4 95 5 310 13
PRS without Apprentice Credits 212 540 4 96 0 310 13
2009 IRP "Like"0 810 0 102 0 310 13
PRS Without Wind 212 540 4 0 0 310 13
CCCT with Solar after 2015 0 810 10 36 33 310 13
PRS + Wind to meet National RES 212 540 4 177 1 310 13
PRS if no Conservation 475 815 10 94 0 0 13
PRS Conservation A/C 25% Lower 249 540 4 82 0 266 13
PRS Conservation A/C 25% Higher 415 270 7 70 0 334 13
PRS Conservation A/C 50% Higher 129 540 4 70 0 350 13
Low Load Growth 212 0 4 71 0 247 13
High Load Growth 510 810 10 93 1 443 13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 688 of 1069
2011 IRP Action Items
John Lyons
Technical Advisory Committee Meeting #6
2011 Electric Integrated Resource Plan
June 23, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 689 of 1069
2009 IRP Action Item Review
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 690 of 1069
2009 IRP Action Items
Resource Additions and Analysis
Energy Efficiency
Environmental Policy
Modeling and Forecasting Enhancements
Transmission Planning
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 691 of 1069
2009 Action Items –Resource Additions & Analysis
Continue to explore the potential for wind and non-wind
renewable resources.
Issue an RFP for turbines at Reardan and up to 100 MW
of wind or other renewables in 2009.
Finish studies on the costs and environmental benefits of
hydro upgrades at Cabinet Gorge, Long Lake, Post Falls,
and Monroe Street.
Study potential locations for the natural gas-fired
resource identified to be online between 2015 and 2020
Continue participation in the regional IRP processes and
where agreeable find resource opportunities to meet
resource requirements on a collaborative basis.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 692 of 1069
2009 Action Items –Energy Efficiency
Pursue American Reinvestment and Recovery Act of 2009
(ARRA) funding for low income weatherization.
Analyze and report on the results of the July 2007 through
December 2009 demand response pilot in Moscow and
Sandpoint.
Have an external party perform a study on technical, economic,
and achievable potential for energy efficiency in Avista’s entire
service territory.
Study and quantify transmission and distribution efficiency
concepts as they apply to meeting Washington’s RPS goals.
Update processes and protocols for conservation
measurement, evaluation and verification.
Determine the potential impacts and costs of load management
options.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 693 of 1069
2009 Action Items –Environmental Policy
Continue to study the potential impact of state and
federal climate change legislation.
Continue and report on the work of Avista’s Climate
Change Council.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 694 of 1069
2009 Action Items –Modeling & Forecasting
Refine stochastic model cost driver relationships.
Continue PRiSM refinements by developing a resource
retirement capability to solve for other risk measurements
and by adding more resource options.
Continue developing Loss of Load Probability and
Sustained Peaking analysis for inclusion in the IRP
process, and confirm appropriateness of the 15% capacity
planning margin assumed for this IRP.
Continue studying the impacts of climate change on the
load forecast.
Study load growth trends and their correlation to weather
patterns.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 695 of 1069
2009 Action Items –Transmission Planning
Work to maintain/retain existing transmission rights on the Company’s
transmission system, under applicable FERC policies, for transmission
service to bundled retail native load.
Continue to participate in BPA transmission practice processes and
rate proceedings to minimize the costs of integrating existing
resources outside of the Company’s service area.
Continue to participate in regional and sub-regional efforts to establish
new regional transmission structures (ColumbiaGrid and other forums)
to facilitate long-term expansion of the regional transmission system.
Evaluate costs to integrate new resources across Avista’s service
territory and from regions outside of the Northwest.
Study and implement distribution feeder rebuild projects to reduce
system losses.
Study transmission reconfigurations to economically reduce system
losses.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 696 of 1069
2011 IRP Action Items
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 697 of 1069
2011 Action Items Resource Additions & Analysis
Continue to explore and follow potential new resources
opportunities.
Continue studies on the costs, energy, capacity and
environmental benefits of hydro upgrades at Cabinet
Gorge, Long Lake, Post Falls, and Monroe Street.
Study potential locations for the natural gas-fired
resource identified to be online in 2019.
Continue participation in regional IRP processes and,
where agreeable, find opportunities to meet resource
requirements on a collaborative basis with other utilities.
Provide an update on the Little Falls and Nine Mile
hydroelectric project upgrades.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 698 of 1069
2011 Action Items –Energy Efficiency
Study and quantify transmission and distribution
efficiency projects as they apply to Washington RPS
goals.
Update processes and protocols for conservation
measurement, evaluation and verification.
Continue to determine the potential impacts and
costs of load management options.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 699 of 1069
2011 Action Items –Environmental Policy
Continue studies of state and federal climate change
policies.
Continue and report on the work of Avista’s Climate
Change Council.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 700 of 1069
2011 Action Items –Modeling & Forecasting
Continue following regional reliability processes and
develop Avista-centric modeling for possible inclusion in
the 2013 IRP.
Continue studying the impacts of climate change on retail
loads.
Refine the stochastic model for cost driver relationships,
including further analyzing year-to-year hydro correlation
and the correlation between wind, load, and hydro.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 701 of 1069
2011 Action Items –Transmission and
Distribution Planning
Work to maintain existing transmission rights, under applicable
FERC policies, for transmission service to bundled retail native load.
Continue to participate in BPA transmission processes and rate
proceedings to minimize costs of integrating existing resources
outside of Avista’s service area.
Continue to participate in efforts to establish new regional
transmission structures to facilitate long-term expansion of the
regional transmission system.
Evaluate the costs to integrate new resources across Avista’s
service territory and from regions outside of the Northwest.
Study and implement distribution feeder rebuild projects to reduce
system losses.
Study transmission reconfigurations to economically reduce system
losses.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 702 of 1069
2011 IRP Section Highlights
John Lyons
Technical Advisory Committee Meeting #6
2011 Electric Integrated Resource Plan
June 23, 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 703 of 1069
Loads & Resources Highlights
Historic conservation acquisitions are included in the load
forecast; higher acquisition levels anticipated in the IRP reduce
the load forecast further.
Annual electricity sales growth from 2012 to 2031 averages
1.6%.
Expected energy deficits begin in 2020, growing to 475 aMW
by 2031.
Expected capacity deficits begin in 2019, growing to 883 MW
by 2031.
Conservation pushes the need for resources out by one year
for energy and six years for capacity.
Renewable portfolio standard deficiencies drive near-term
resource needs.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 704 of 1069
Energy Efficiency Highlights
Conservation reduces load by 47 percent through the IRP
timeframe.
Avista began offering conservation programs in 1978.
Company-sponsored conservation reduces retail loads by
approximately 10 percent, or 120 aMW.
More than 2,800 equipment options and over 1,500 measure
options covering all major end-use equipment, as well as devices
and actions to reduce energy consumption were evaluated for
this IRP.
This IRP includes a Conservation Potential Assessment of the
Company’s Idaho and Washington service territories.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 705 of 1069
Policy Considerations Highlights
Avista supports national greenhouse gas legislation that
is workable, cost effective and fair.
Avista supports national greenhouse gas legislation that
protects the economy, supports technological innovation,
and addresses emissions from developing nations.
The Company is a member of the Clean Energy Group
Avista’s Climate Change Council monitors greenhouse
gas legislation and environmental regulation issues.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 706 of 1069
Transmission & Distribution Highlights
Avista has received a total of 43 requests for non-Avista resource
integration.
Projected costs of transmission upgrades are included in the 2011
Preferred Resource Strategy.
The Company has received matching federal grants and is
investing in three Smart Grid programs projected to reduce load
by 5.57 aMW by 2013.
Sixty distribution feeders were found to be preliminarily economic
during the IRP timeframe, reducing system losses by 6.1 aMW.
The Company participates in various regional transmission
planning forums.
Various upgrades to our transmission system are planned over
the next five years.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 707 of 1069
Generation Resource Options Highlights
Only resources with well-defined costs and operating
histories were considered in the PRS analysis.
Wind and solar resources were evaluated as the
renewable options available to the Company; other
technologies will be considered in renewable RFP efforts.
Renewable resource costs assume present state and
federal incentive levels, but no extensions.
For the first time, thermal generation upgrades were
considered as resource options.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 708 of 1069
Market Analysis Highlights
Gas and wind resources are expected to dominate new generation
additions in the West for the foreseeable future.
The massive growth in unconventional natural gas has lowered gas
price forecasts and expected future electricity market prices.
Expansion of the Northwest wind fleet is reducing the value of
springtime hydroelectric generation and driving short-term market
prices below zero.
Federal greenhouse gas policy is uncertain; the IRP quantifies this
uncertainty by modeling four different mitigation regimes.
The Expected Case reduces greenhouse gas emissions by 18 percent
and increases overall Western Interconnect costs by $3.5 billion per
year. Absent mitigation, overall emissions are forecast to increase by
14 percent over the next 20 years.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 709 of 1069
Preferred Resource Strategy Highlights
Avista’s first load –driven acquisition is a natural gas-fired
peaking plant in 2019; total gas-fired acquisition is 752 MW
over the IRP timeframe.
The 2011 plan splits natural gas-fired generation between
simple- and combined-cycle plants in anticipation of a growing
need for system flexibility to integrate variable resources.
Efficiency improvements, both on the customer and utility sides
of the meter, are at the highest expected level in our planning
history.
Total capital needs for generation resources in the PRS are
$1.6 billion.
Conservation and system efficiency spending will increase over
time; a total of $1.5 billion will acquire 323 aMW.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 710 of 1069
Remaining 2011 IRP Schedule
July 1, 2011 Management review of Internal Draft 2011
IRP complete
July 8, 2011 distribution of Draft 2011 IRP to TAC
participants
August 1, 2011: External review by TAC complete
August 8, 2011: Final 2011 IRP sent to print
August 30, 2011: 2011 IRP documents sent to the Idaho
and Washington Commissions
August 31, 2011: 2011 IRP available to public, including
publication on the Company’s web site
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 711 of 1069

2011 Electric Integrated
Resource Plan

Appendix B – Work Plan

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 712 of 1069

Work Plan for Avista’s
2011 Electric Integrated Resource
Plan

For the
Washington Utilities and Transportation Commission

August 31, 2010

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 713 of 1069

2011 Integrated Resource Planning Work Plan

This Work Plan is submitted in compliance with the Washington Utilities and Transportation
Commission’s Integrated Resource Planning (IRP) rules (WAC 480-100-238). This work
plan outlines the process Avista will follow to develop its 2011 Integrated Resource Plan to
be filed with Washington and Idaho Commissions by August 31, 2011. Avista uses a public
process to obtain technical expertise and guidance throughout the planning period through a
series of public Technical Advisory Committee (TAC) meetings. The first of these meetings
for the 2011 IRP was held on May 27, 2010.

The 2011 IRP process will be similar to those used to produce the previous three published
plans. AURORAxmp will be used for electric market forecasting, resource valuation, and for
conducting Monte-Carlo style risk analyses. Results from AURORAxmp will be used to select
the Preferred Resource Strategy (PRS) using the proprietary PRiSM 3.0 model. This tool
fills future capacity and energy (physical/renewable) deficits using an efficient frontier
approach to evaluate quantitative portfolio risk versus portfolio cost while accounting for
environmental legislation. Qualitative risk will be evaluated in a separate analysis. The
process timeline is shown in Exhibit 1 and the process to identify the PRS is shown in Exhibit
2.

Avista intends to use both detailed site-specific and generic resource assumptions in this
plan. These assumptions will be determined by using the 6th Power Plan for generic
resources and site-specific assumptions developed by Avista will be used for existing
resource upgrades. This plan will study renewable portfolio standards, environmental costs,
sustained peaking requirements, and energy efficiency programs. This IRP will develop a
strategy that meets or exceeds both the renewable portfolio standards and greenhouse gas
emissions regulations.

Avista intends to test the PRS against several scenarios and stochastic futures. The TAC
meetings will be an important factor to determine the underlying assumptions used in the
scenarios and futures. The IRP process is very technical and data intensive; public
comments are welcome and will require input in a timely manner for appropriate inclusion
into the process so the plan can be submitted according to the tentative schedule.

Topics and meeting times may be changed depending on the availability of and requests for
additional topics from the TAC members. The tentative timeline for public Technical
Advisory Committee meetings:

 May 27, 2010 – Load & resource balance, climate change, loss of load probability
analysis, work plan, and analytical process changes
 September 8, 2010 – Plant tours for TAC members
 September 9, 2010 – Generic resource assumptions, reliability planning, combined
heat & power, sustainability, and energy efficiency
 November 4, 2010 – Load forecast, stochastic assumptions, resource upgrade costs,
and transmission cost studies Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 714 of 1069

 January 20, 2011 – Electric and gas price forecasts, load & resource forecast
 March 10, 2011 – Draft PRS, review of scenarios and futures, and portfolio analysis
 April 28, 2011 – Review of final PRS and action items
 June 23, 2011 – Review of the 2011 IRP

2011 Electric IRP Draft Outline

This section provides a draft outline of the major sections in the 2011 Electric IRP. This
outline will be updated as IRP studies are completed and input from the Technical Advisory
Committee has been received.

1. Executive Summary
2. Introduction and Stakeholder Involvement
3. Loads and Resources
a. Economic Conditions
b. Avista Load Forecast
c. Load Forecast Scenarios
d. Supply Side Resources
e. Reserve Margins
f. Resource Requirements
4. Energy Efficiency and Demand Response
5. Environmental Policy Issues
6. Transmission Planning
7. Modeling Approach
a. Assumptions and Inputs
b. Risk Modeling
c. Resource Alternatives
d. The PRiSM Model
8. Market Modeling Approach
a. Futures
b. Scenarios
c. Avoided Costs
9. Preferred Resource Strategy & Stress Analysis
10. Action Items

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 715 of 1069

Exhibit 1: 2011 Electric IRP Timeline
Task Target Date
Preferred Resource Strategy (PRS)
Finalize load forecast July 2010
Identify regional resource options for electric market price
forecast
September 2010
Identify Avista’s supply & conservation resource options September 2010
Update AURORAxmp database for electric market price
forecast
October 2010
Finalize datasets/statistics variables for risk studies October 2010
Draft transmission study due October 2010
Energy efficiency load shapes input into AURORAxmp October 2010
Final transmission study due November 2010
Select natural gas price forecast December 2010
Finalize deterministic base case December 2010
Base case stochastic study complete January 2011
Finalize PRiSM 3.0 model January 2011
Develop efficient frontier and PRS January 2011
Simulation of risk studies “futures” complete February 2011
Simulate market scenarios in AURORAxmp February 2011
Evaluate resource strategies against market futures and
scenarios
March 2011
Present preliminary study and PRS to TAC March 2011

Writing Tasks
File 2011 IRP work plan August 2010
Prepare report and appendix outline September 2010
Prepare text drafts April 2011
Prepare charts and tables April 2011
Internal draft released at Avista May 2011
External draft released to the TAC June 2011
Final editing and printing August 2011
Final IRP submission to Commissions and distribution to TAC August 31, 2011

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 716 of 1069

Exhibit 2: 2011 Electric IRP Modeling Process

Fuel Prices
Fuel Availability
Resource Availability
Demand
Emission Pricing
Stochastic Inputs
Existing Resources
Resource Options
Transmission
Avoided
Costs
Preferred
Resource
Strategy
Energy,
Capacity
& RPS
Balances
AURORA
“Wholesale Electric
Market”

300 Simulations

PRiSM
“Avista Portfolio”

Efficient Frontier
Deterministic
Inputs
Resource &
Portfolio
Margins
Mid-Columbia
Prices
Capacity
Value
Conservation
Trends
Avista Load
Forecast
Existing
Resources
Cost Effective T&D
Projects/Costs
New Resource
Options & Costs
Cost Effective
Conservation
Measures/Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 717 of 1069

2011 Electric Integrated
Resource Plan

Appendix C – Comprehensive
Energy Efficiency Equipment List
and Measure Options

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 718 of 1069

Global Energy Partners C-1
An EnerNOC Company

APPENDIX C
RESIDENTIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA
This appendix presents detailed information for all residential energy efficiency equipment and
measures that were evaluated in LoadMAP. Several sets of tables are provided.
Table C-1 provides brief descriptions for all equipment and measures that were assessed for
potenital.
Tables C-2 through C-9 list the detailed unit-level data for the equipment measures for each of
the housing type segments — single family, multi-family, mobile home, and limited income —
and for existing and new construction, respectively. Savings are in kWh/yr/household, and
incremental costs are in $/household, unless noted otherwise. The B/C ratio is zero if the
measure represents the baseline technology or if the technology is not available in the first year
of the forecast (2012). The B/C ratio is calculated within LoadMAP for each year of the forecast
and is available once the technology or measure becomes available.
Tables C-10 through C-17 list the detailed unit-level data for the non-equipment energy
efficiency measures for each of the housing type segments and for existing and new
construction, respectively. Because these measures can produce energy-use savings for multiple
end-use loads (e.g., insulation affects heating and cooling energy use) savings are expressed as
a percentage of the end-use loads. Base saturation indicates the percentage of homes in which
the measure is already installed. Applicability/Feasibility is the product of two factors that
account for whether the measure is applicable to the building. Cost is expressed in $/household.
The detailed measure-level tables present the results of the benefit/cost (B/C) analysis for the
first year of the forecast. The B/C ratio is zero if the measure represents the baseline technology
or if the measure is not available in the first year of the forecast (2012). The B/C ratio is
calculated within LoadMAP for each year of the forecast and is available once the technology or
measure becomes available.
Note that Tables C-2 through C-17 present information for Washington. For Idaho, savings and
B/C ratios may be slightly different due to weather-related usage, differences in the states’
market profiles, and different retail electricity prices. Although Idaho-specific values are not
presented here, they are available within the LoadMAP files.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 719 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-2 www.gepllc.com

Table C–1 Residential Energy Efficiency Equipment/Measure Descriptions
End‐Use 
Equipment/ 
Measure Description 
Cooling Air Conditioner — 
Central (CAC) 
Central air conditioners consist of a refrigeration system using a direct 
expansion cycle. Equipment includes a compressor, an air‐cooled condenser 
(located outdoors), an expansion valve, and an evaporator coil. A supply fan 
near the evaporator coil distributes supply air through air ducts to the building. 
Cooling efficiencies vary based on materials used, equipment size, condenser 
type, and system configuration. CACs may be unitary (all components housed 
in a factory‐built assembly) or split system (an outdoor condenser section and 
an indoor evaporator section connected by refrigerant lines and with the 
compressor either indoors or outdoors). Energy efficiency is rated according to 
the size of the unit using the Seasonal Energy Efficiency Rating (SEER). Systems 
with Variable Refrigerant Flow further improve the operating efficiency. A 
high‐efficiency option for a ductless mini‐split system was also analyzed.  
Cooling Central Air 
Conditioner, Early 
Replacement 
CAC systems currently on the market are significantly more efficient that older 
units, due to technology improvement and stricter appliance standards. This 
measure incents homeowners to replace an aging but still working unit with a 
new, higher‐efficiency one. 
Cooling Central Air 
Conditioner 
Maintenance and 
Tune Up 
An air conditioner's filters, coils, and fins require regular cleaning and 
maintenance for the unit to function effectively and efficiently throughout its 
life. Neglecting necessary maintenance leads to a steady decline in 
performance, requiring the AC unit to use more energy for the same cooling 
load.  
Cooling Air Conditioner ‐ 
Room, ENERGY STAR 
or better 
Room air conditioners are designed to cool a single room or space. They 
incorporate a complete air‐cooled refrigeration and air‐handling system in an 
individual package. Room air conditioners come in several forms, including 
window, split‐type, and packaged terminal units. Energy efficiency is rated 
according to the size of the unit using the Energy Efficiency Rating (EER).  
Cooling Room AC — Removal 
of Second Unit 
Homeowners may have a second room AC unit that is extremely inefficient. 
This measure incents homeowners to recycle the second unit and thus also 
eliminates associated electricity use. 
Cooling Attic Fan 

Attic Fan, 
Photovoltaic 
Attic fans can reduce the need for AC by reducing heat transfer from the attic 
through the ceiling of the house. A well‐ventilated attic can be several degrees 
cooler than a comparable, unventilated attic. An option for an attic fan 
equipped with a small solar photovoltaic generator was also modeled. 
Cooling Ceiling Fan Ceiling fans can reduce the need for air conditioning. However, the house 
occupants must also select a ceiling fan with a high‐efficiency motor and either 
shutoff the AC system or setup the thermostat temperature of the air 
conditioning system to realize the potential energy savings. Some ceiling fans 
also come with lamps. In this analysis, it is assumed that there are no lamps, 
and installing a ceiling fan will allow occupants to increase the thermostat 
cooling setpoint up by 2°F. 
Cooling Whole‐House Fan Whole‐house fans can reduce the need for AC on moderate‐weather days or 
on cool evenings. The fan facilitates a quick air change throughout the entire 
house. Several windows must be open to achieve the best results. The fan is 
mounted on the top floor of the house, usually in a hallway ceiling. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 720 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-3
An EnerNOC Company
End‐Use 
Equipment/ 
Measure Description 
Space Heating Convert to Gas This fuel‐switching measure is the replacement of an electric furnace with a 
gas‐fired furnace. This measure will eliminate all electricity consumption and 
demand due to electric space heating. In this study, it is assumed that this 
measure can be implemented only in homes within 500 feet of a gas main. 
Heat/Cool Air Source Heat 
Pump 
A central heat pump consists of components similar to a CAC system, but is 
usually designed to function both as a heat pump and an air conditioner. It 
consists of a refrigeration system using a direct expansion (DX) cycle. 
Equipment includes a compressor, an air‐cooled condenser (located outdoors), 
an expansion valve, and an evaporator coil (located in the supply air duct near 
the supply fan) and a reversing valve to change the DX cycle from cooling to 
heating when required. The cooling and heating efficiencies vary based on the 
materials used, equipment size, condenser type, and system configuration. 
Heat pumps may be unitary (all components housed in a factory‐built 
assembly) or a split system (an outdoor condenser section and an indoor 
evaporator section connected by refrigerant lines, with either outdoors or 
indoors. A high‐efficiency option for a ductless mini‐split system was also 
analyzed. 
Heat / Cool Geothermal Heat 
Pump 
Geothermal heat pumps are similar to air‐source heat pumps, but use the 
ground or groundwater instead of outside air to provide a heat source/sink. A 
geothermal heat pump system generally consists of three major subsystems or 
parts: a geothermal heat pump to move heat between the building and the 
fluid in the earth connection, an earth connection for transferring heat 
between the fluid and the earth, and a distribution subsystem for delivering 
heating or cooling to the building. The system may also have a desuperheater 
to supplement the building's water heater, or a full‐demand water heater to 
meet all of the building's hot water needs.  
Heat / Cool Air Source Heat 
Pump Maintenance 
A heat pump's filters, coils, and fins require regular cleaning and maintenance 
for the unit to function effectively and efficiently throughout its life. Neglecting 
necessary maintenance ensures a steady decline in performance while energy 
use steadily increases.  
HVAC (all) Insulation – Ducting Air distribution ducts can be insulated to reduce heating or cooling losses. Best 
results can be achieved by covering the entire surface area with insulation. 
Several types of ducts and duct insulation are available, including flexible duct, 
pre‐insulated duct, duct board, duct wrap, tacked, or glued rigid insulation, and 
waterproof hard shell materials for exterior ducts.  This analysis assumes that 
installing duct insulation can reduce the temperature drop/gain in ducts by 
50%. 
HVAC (all) Repair and Sealing –
Ducting 
An ideal duct system would be free of leaks. Leakage in unsealed ducts varies 
considerably because of differences in fabricating machinery used, methods 
for assembly, installation workmanship, and age of the ductwork. Air leaks 
from the system to the outdoors result in a direct loss proportional to the 
amount of leakage and the difference in enthalpy between the outdoor air and 
the conditioned air. This analysis assumes that over time air loss from ducts 
has doubled, and conducting repair and sealing of the ducts will restore 
leakage from ducts to the original baseline level. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 721 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-4 www.gepllc.com

End‐Use 
Equipment/ 
Measure Description 
HVAC (all) Thermostat — 
Clock/Programmable 

A programmable thermostat can be added to most heating/cooling systems.  
They are typically used during winter to lower temperatures at night and in 
summer to increase temperatures during the afternoon. The energy savings 
from this type of thermostat are identical to those of a "setback" strategy with 
standard thermostats, but the convenience of a programmable thermostat 
makes it a much more attractive option.  In this analysis, the baseline is 
assumed to have no thermostat setback. 
HVAC (all) Doors — Storm and 
Thermal 
Like other components of the shell, doors are subject to several types of heat 
loss: conduction, infiltration, and radiant losses. Similar to a storm window, a 
storm door creates an insulating air space between the storm and primary 
doors. A tight fitting storm door can also help reduce air leakage or infiltration.  
Thermal doors have exceptional thermal insulation properties and also are 
provided with weather‐stripping on the doorframe to reduce air leakage. 
HVAC (all) Insulation — 
Infiltration Control 

Lowering the air infiltration rate by caulking small leaks and weather‐stripping 
around window frames, doorframes, power outlets, plumbing, and wall 
corners can provide significant energy savings. Weather‐stripping doors and 
windows will create a tight seal and further reduce air infiltration.  
HVAC (all) Insulation —Ceiling Thermal insulation is material or combinations of materials that are used to 
inhibit the flow of heat energy by conductive, convective, and radiative 
transfer modes. Thus, thermal insulation above ceilings can conserve energy by 
reducing the heat loss or gain into attics and/or through roofs. The type of 
building construction defines insulating possibilities. Typical insulating 
materials include:  loose‐fill (blown) cellulose, loose‐fill (blown) fiberglass, and 
rigid polystyrene. 
HVAC (all) Insulation — Radiant 
Barrier 
Radiant barriers are materials installed to reduce the heat gain in buildings. 
Radiant barriers are made from materials that are highly reflective and have 
low emissivity like aluminum. The closer the emissivity is to 0 the better they 
will perform.  Radiant barriers can be placed above the insulation or on the 
roof rafters.   
HVAC (all) Insulation — 
Foundation  
Insulation  — Wall 
Cavity 
Insulation  — Wall 
Sheathing 
Thermal insulation is material or combinations of materials that are used to 
inhibit the flow of heat energy by conductive, convective, and radiative 
transfer modes. Thus, thermal insulation can conserve energy by reducing heat 
loss or gain from a building. The type of building construction defines insulating 
possibilities. Typical insulating materials include:  loose‐fill (blown) cellulose, 
loose‐fill (blown) fiberglass, and rigid polystyrene. Foundation, insulation, wall 
cavity insulation, and wall sheathing were modeled for new construction / 
major retrofits only. 
Cooling Roof — High 
Reflectivity 
The color and material of a building structure surface determine the amount of 
solar radiation absorbed by that surface and subsequently transferred into a 
building. This is called solar absorptance. Using a roofing material with low 
solar absorptance or painting the roof a light color reduces the cooling load.  
This analysis assumes that implementing high reflectivity roofs will decrease 
the roof’s absorptance of solar radiation by 45%. 
Cooling Windows — 
Reflective Film 
Reflective films applied to the window interior help reduce solar gain into the 
space and thus lower cooling energy use. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 722 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-5
An EnerNOC Company
End‐Use 
Equipment/ 
Measure Description 
HVAC (all) Windows — High 
Efficiency / ENERGY 
STAR 
High‐efficiency windows, such as those labeled under the ENERGY STAR 
Program, are designed to reduce energy use and increase occupant comfort.  
High‐efficiency windows reduce the amount of heat transfer through the 
glazing surface. For example, some windows have a low‐E coating, a thin film 
of metallic oxide coating on the glass surface that allows passage of short‐wave 
solar energy through glass and prevents long‐wave energy from escaping. 
Another example is double‐pane glass that reduces conductive and convective 
heat transfer.  Some double‐pane windows are gas‐filled (usually argon) to 
further increase the insulating properties of the window. 
Water Heating Water Heater ‐ 
Electric, High 
Efficiency 
For electric hot water heating, the most common type is a storage heater, 
which incorporates an electric heating element, storage tank, outer jacket, 
insulation, and controls in a single unit. Efficient units are characterized by a 
high recovery or thermal efficiency and low standby losses (the ratio of heat 
lost per hour to the content of the stored water). Electric instantaneous water 
heaters are available, but are excluded from this study due to potentially high 
instantaneous demand concerns. 
Water Heating Water Heater, Heat 
Pump 
An electric heat pump water heater (HPWH) uses a vapor‐compression 
thermodynamic cycle similar to that found in an air‐conditioner or refrigerator. 
Electrical work input allows a heat pump water heater to extract heat from an 
available source (e.g., air) and reject that heat to a higher temperature sink, in 
this case, the water in the water heater. Because a HPWH makes use of 
available ambient heat, the coefficient of performance is greater than one —
typically in the range of 2 to 3. These devices are available as an alternative to 
conventional tank water heaters of 55 gallons or larger. By utilizing the earth as 
a thermal reservoir, ground source HPWH systems can reach even higher levels 
of efficiency. The heat pump can be integrated with a traditional water storage 
tank or installed remote to the storage tank.  
Water Heating Water Heating, Solar Solar water heating systems can be used in residential buildings that have an 
appropriate near‐south‐facing roof or nearby unshaded grounds for installing a 
collector. Although system types vary, in general these systems use a solar 
absorber surface within a solar collector or an actual storage tank. Either a 
heat‐transfer fluid or the actual potable water flows through tubes attached to 
the absorber and transfers heat from it. (Systems with a separate heat‐
transfer‐fluid loop include a heat exchanger that then heats the potable 
water.) The heated water is stored in a separate preheat tank or a 
conventional water heater tank. If additional heat is needed, it is provided by a 
conventional water‐heating system. 
Water Heating Convert to Gas This fuel‐switching measure is the replacement of an electric water heater with 
a gas‐fired water heater. This measure will eliminate all electricity consumption 
and demand due to electric water heating.  In this study, it is assumed that this 
measure can be implemented only in home within 500 feet of a gas main. 
Water Heating Faucet Aerators Water faucet aerators are threaded screens that attach to existing faucets. 
They reduce the volume of water coming out of faucets while introducing air 
into the water stream. This measure provides energy saving by reducing hot 
water use, as well as water conservation for both hot and cold water. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 723 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-6 www.gepllc.com

End‐Use 
Equipment/ 
Measure Description 
Water Heating Pipe Insulation Insulating hot water pipes decreases energy losses from piping that distributes 
hot water throughout the building. I also results in quicker delivery of hot 
water and may allow lower the hot water set point, which saves energy. The 
most common insulation materials for this purpose are polyethylene and 
neoprene.       
Water Heating Low‐Flow 
Showerheads 
Similar to faucet aerators, low‐flow showerheads reduce the consumption of 
hot water, which in turn decreases water heating energy use.   
Water Heating Tank Blanket Insulating hot water tanks decreases standby energy losses from the tank. Pre‐
fitted insulating blankets are readily available. 
Water Heating Thermostat Setback 
/ Timer 
These measures use either a programmable thermostat or a timer to adjust the 
water heater setpoint at times of low usage, typically when a home is 
unoccupied. 
Water Heating Hot Water Saver A hot water saver is a plumbing device that attaches to the showerhead and 
that pauses the flow of water until the water is hot enough for use. The water 
is re‐started by the flip of a switch. 
Interior Lighting 
/ Exterior 
Lighting  
Infrared Halogen 
Lamps 
Infrared halogen lamps are designed to be a replacement for standards 
incandescent lamps. Also referred to as advanced incandescent lamps, these 
products meet the Energy Independence and Security Act (EISA) lighting 
standards and are phased in as the baseline technology screw‐in lamp 
technology to reflect the timeline over which the EISA lighting standards take 
effect. 
Interior Lighting 
/ Exterior 
Lighting 
Compact Fluorescent 
Lamps 
Compact fluorescent lamps are designed to be a replacement for standard 
incandescent lamps and use about 25% of the energy used by standard 
incandescent lamps to produce the same lumen output. The can use either 
electronic or magnetic ballasts. Integral compact fluorescent lamps have the 
ballast integrated into the base of the lamp and have a standard screw‐in base 
that permits installation into existing incandescent fixtures. 
Interior Lighting 
/ Exterior 
Lighting 
Solid State Lighting, 
LEDs (Screw‐in and 
linear) 
Light‐emitting diode (LED) lighting has seen recent penetration in specific 
applications such as traffic lights and exit signs. With the potential for 
extremely high efficiency, LEDs show promise to provide general‐use lighting 
for interior spaces. Current models commercially available have efficacies 
comparable to CFLs. However, theoretical efficiencies are significantly higher. 
LED models under development are expected to provide improved efficacies. 
Interior Lighting Fluorescent, T8, 
Super T8, and T5 
Lamps and Electronic 
Ballasts 
T8 fluorescent lamps are smaller in diameter than standard T12 lamps, 
resulting in greater light output per watt. T8 lamps also operate at a lower 
current and wattage, which increases the efficiency of the ballast but requires 
the lamps to be compatible with the ballast. Fluorescent lamp fixtures can 
include a reflector that increases the light output from the fixture, and thus 
make it possible to use a fewer number of lamps in each fixture. T5 lamps 
further increase efficiency by reducing the lamp diameter to 5/8”. 
Exterior Lighting Metal Halide and 
High Pressure 
Sodium 
These lamps technologies can provide slightly higher efficiencies than CFLs in 
exterior applications. 
Interior Lighting Occupancy Sensors Occupancy sensors turn lights off when a space is unoccupied. They are 
appropriate for areas with intermittent use, such as bathrooms or storage 
areas.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 724 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-7
An EnerNOC Company
End‐Use 
Equipment/ 
Measure Description 
Exterior Lighting Photovoltaic 
Installation 
Solar photovoltaic generation may be used to power exterior lighting and thus 
eliminate all or part of the electrical energy use.  
Exterior Lighting Photosensor Control Photosensor controls turn exterior lighting on or off based on ambient lighting 
levels. Compared with manual operation, this can reduce the operation of 
exterior lighting during daylight hours.  
Exterior Lighting Timeclock 
Installation 
Lighting timers turn exterior lighting on or off based on a preset schedule. 
Compared with manual operation, this can reduce the operation of exterior 
lighting during daylight hours. 
Appliances Refrigerator/Freezer, 
ENERGY STAR or 
better 
Energy‐efficient refrigerators/freezers incorporate features such as improved 
cabinet insulation, more efficient compressors and evaporator fans, defrost 
controls, mullion heaters, oversized condenser coils, and improved door seals.  
Further efficiency increases can be obtained by reducing the volume of 
refrigerated space, or adding multiple compartments to reduce losses from 
opening doors. 
Appliances Refrigerator/Freezer 
—  
Early Replacement  
Refrigerators/freezers currently on the market are significantly more efficient 
that older units, due to technology improvement and stricter appliance 
standards. This measure incents homeowners to replace an aging but still 
working unit with a new, higher‐efficiency one. 
Appliances Refrigerator/Freezer 
—  
Remove Second Unit 
Homeowners may have a second refrigerator or freezer that is not used to full 
capacity and that, because of its age, is extremely inefficient. This measure 
incents homeowners to recycle the second unit and thus also eliminates 
associated electricity use. 
Appliances Dishwasher, ENERGY 
STAR or better 
ENERGY STAR labeled dishwashers save by using both improved technology for 
the primary wash cycle, and by using less hot water. Construction includes 
more effective washing action, energy‐efficient motors, and other advanced 
technology such as sensors that determine the length of the wash cycle and 
the temperature of the water necessary to clean the dishes.  
Appliances Clothes Washer, 
ENERGY STAR or 
better 
ENERGY STAR labeled clothes washers use superior designs that require less 
water. Sensors match the hot water needs to the size and soil level of the load, 
preventing energy waste. Further energy and water savings can be achieved 
through advanced technologies such as inverter‐drive or combination washer‐
dryer units. 
Appliances Clothes Dryer – 
Electric, High 
Efficiency 
An energy‐efficient clothes dryer has a moisture‐sensing device to terminate 
the drying cycle rather than using a timer, and an energy‐efficient motor is 
used for spinning the dryer tub. Application of a heat pump cycle for extracting 
the moisture from clothes leads to additional energy savings. 
Appliances Range and Oven – 
Electric, High 
Efficiency 
These products have additional insulation in the oven compartment and 
tighter‐fitting oven door gaskets and hinges to save energy. Conventional 
ovens must first heat up about 35 pounds of steel and a large amount of air 
before they heat up the food. Tests indicate that only 6% of the energy output 
of a typical oven is actually absorbed by the food.  
Electronics Color TVs and Home 
Electronics, ENERGY 
STAR or better 
In the average home, electronic products consumed significant energy, even 
when they are turn off, to maintain features like clocks, remote control, and 
channel/station memory. ENERGY STAR labeled consumer electronics can 
drastically reduce consumption during standby mode, in addition to saving 
energy through advanced power management during normal use.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 725 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-8 www.gepllc.com

End‐Use 
Equipment/ 
Measure Description 
Electronics Personal Computers, 
ENERGY STAR or 
better 
Improved power management can significantly reduce the annual energy 
consumption of PCs and monitors in both standby and normal operation. 
ENERGY STAR and Climate Savers labeled products provide increasing level of 
energy efficiency. 
Electronics Reduce Standby 
Wattage 
Representing a growing portion of home electricity consumption, plug‐in 
electronics such as set‐top boxes, DVD players, gaming systems, digital video 
recorders, and even battery chargers for mobile phones and laptop computers 
are often designed to supply a set voltage. When the units are not in use, this 
voltage could be dropped significantly (~1 W) and thereby generate a 
significant energy savings, assumed for this analysis to be between 4‐5% on 
average. These savings are in excess of the measures already discussed for 
computers and televisions.  
Misc. Furnace Fans, 
Electronically 
Commutating Motor 
In homes heated by a furnace, there is still substantial energy use by the fan 
responsible for moving the hot air throughout the ductwork.  Application of an 
Electronically Commutating Motor (ECM) ensures that motor speed matches 
the heating requirements of the system and saves energy when compared to a 
continuously operating standard motor. 
Miscellaneous Pool Pump  High‐efficiency motors and two‐speed pumps provide improved energy 
efficiency for this load.  
Miscellaneous Pool Pump Timer A pool pump timer allows the pump to turn off automatically, eliminating the 
wasted energy associated with unnecessary pumping.   
Miscellaneous Trees for Shading Planting of shade trees, suitable to the local climate, can reduce the need for 
air conditioning and provide non‐energy benefits as well.  
Cooling / Space 
Heating / 
Interior Lighting 
Home Energy 
Management System 
A centralized home energy management system can be used to control and 
schedule cooling, space heating, lighting, and possibly appliances as well. Some 
designs also allow the homeowner to remotely control loads via the Internet. 
Cooling / Space 
Heating  
Solar Photovoltaic Adding a solar photovoltaic (PV) system to the home can meet a portion of the 
home’s electric load and in some cases nearly the entire load, depending on 
the PV system size, orientation, solar resource, and other factors. For this 
analysis, we assume a grid‐connected system and apply the electricity savings 
to the home’s cooling and space heating loads. 
Cooling / Space 
Heating / 
Interior Lighting 
Advanced New 
Construction Designs 
Advanced new construction designs use an integrated approach to the design 
of new buildings to account for the interaction of building systems. Typically, 
designs specify the building orientation, building shell, building mechanical 
systems, and controls strategies with the goal of optimizing building energy 
efficiency and comfort. Options that may be evaluated and incorporated 
include passive solar strategies, increased thermal mass, natural ventilation, 
daylighting strategies, and shading strategies, This measure was modeled for 
new construction only. 
Cooling / Space 
Heating / 
Interior Lighting 
ENERGY STAR Homes 

This measure was modeled for new construction only. 
Cooling / Space 
Heating / 
Interior Lighting 
Energy‐Efficient 
Manufactured 
Homes 
This measure was modeled for new construction only. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 726 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-9
An EnerNOC Company
Table C-2 Energy Efficiency Equipment Data — Single Family, Existing Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                  $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)134               $278 15 0.41          
Cooling Central AC SEER 15 (CEE Tier 2)184               $556 15 0.28          
Cooling Central AC SEER 16 (CEE Tier 3)226               $834 15 0.23          
Cooling Central AC Ductless Mini‐Split System 405               $4,399 20 0.14          
Cooling Room AC EER 9.8 ‐                  $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)62                  $104 10 0.33          
Cooling Room AC EER 11 73                  $282 10 0.15          
Cooling Room AC EER 11.5 99                  $626 10 0.09          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                  $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star) 492               $1,000 15 0.43          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 675               $2,318 15 0.26          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 829               $3,505 15 0.21          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 1,486            $5,655 20 0.45          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                  $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 516               $1,500 14 0.28          
Space Heating Electric Resistance Electric Resistance ‐                  $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                  $0 15 ‐            
Space Heating Supplemental Supplemental ‐                  $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                  $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 173               $41 15 5.79          
Water Heating Water Heater Geothermal Heat Pump 2,269            $6,586 15 0.47          
Water Heating Water Heater Solar 2,493            $5,653 15 0.60          
Interior Lighting* Screw‐in Incandescent  ‐                  $0 4 ‐            
Interior Lighting* Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting* Screw‐in CFL 38                  $2 6 14.44       
Interior Lighting* Screw‐in LED 40                  $80 12 0.90          
Interior Lighting* Linear Fluorescent T12 ‐                  $0 6 ‐            
Interior Lighting* Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting* Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting* Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting* Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting* Pin‐based Halogen ‐                  $0 4 ‐            
Interior Lighting* Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting* Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                  $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 22.43       
Exterior Lighting* Screw‐in LED 37                  $79 12 0.89          
Exterior Lighting* High Intensity/Flood Incandescent ‐                  $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                  $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)45                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 88                  $487 10 0.16          
Appliances Clothes Dryer Baseline ‐                  $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 98                  $48 13 2.39          
Appliances Dishwasher Baseline ‐                  $0 9 ‐            
Appliances Dishwasher Energy Star 41                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)53                  $1 9 31.05       
Appliances Refrigerator Baseline ‐                  $0 13 ‐            
Appliances Refrigerator Energy Star 108               $89 13 1.28          
Appliances Refrigerator Baseline (2014)144               $0 13 ‐            
Appliances Refrigerator Energy Star (2014)230               $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 727 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-10 www.gepllc.com

Table C-2 Energy Efficiency Equipment Data — Single Family, Existing Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                  $0 11 ‐            
Appliances Freezer Energy Star 114               $32 11 3.03          
Appliances Freezer Baseline (2014)152               $0 11 ‐            
Appliances Freezer Energy Star (2014)243               $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                  $0 13 ‐            
Appliances Second Refrigerator Energy Star 111               $89 13 1.31          
Appliances Second Refrigerator Baseline (2014)148               $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)237               $89 13 ‐            
Appliances Stove Baseline ‐                  $0 13 ‐            
Appliances Stove Convection Oven 9                    $2 13 7.00          
Appliances Stove Induction (High Efficiency) 46                  $1,432 13 0.05          
Appliances Microwave Baseline ‐                  $0 9 ‐            
Electronics Personal Computers Baseline ‐                  $0 5 ‐            
Electronics Personal Computers Energy Star 108               $1 5 35.63       
Electronics Personal Computers Climate Savers 154               $175 5 0.35          
Electronics TVs Baseline ‐                  $0 11 ‐            
Electronics TVs Energy Star 87                  $1 11 133.21     
Electronics Devices and Gadgets Devices and Gadgets ‐                  $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                  $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 138               $85 15 1.96          
Miscellaneous Pool Pump Two‐Speed Pump 551               $579 15 1.15          
Miscellaneous Furnace Fan Baseline ‐                  $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 127               $1 18 281.65     
Miscellaneous Miscellaneous Miscellaneous ‐                  $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 728 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-11
An EnerNOC Company
Table C-3 Energy Efficiency Equipment Data — Multi Family, Existing Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)67                  $93 15 0.62          
Cooling Central AC SEER 15 (CEE Tier 2)133                $185 15 0.61          
Cooling Central AC SEER 16 (CEE Tier 3)187                $278 15 0.57          
Cooling Central AC Ductless Mini‐Split System 245                $2,012 20 0.19          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)32                  $52 10 0.35          
Cooling Room AC EER 11 38                  $141 10 0.15          
Cooling Room AC EER 11.5 52                  $313 10 0.09          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)238                $1,246 15 0.17          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)467                $2,315 15 0.18          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)659                $3,277 15 0.18          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 862                $5,022 20 0.27          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 248                $1,500 14 0.14          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 107                $41 15 3.61          
Water Heating Water Heater Solar 1,539            $5,653 15 0.38          
Interior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting* Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting* Screw‐in CFL 38                  $2 6 10.47       
Interior Lighting* Screw‐in LED 40                  $80 12 0.65          
Interior Lighting* Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting* Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting* Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting* Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting* Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting* Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting* Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting* Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 32.52       
Exterior Lighting* Screw‐in LED 37                  $79 12 1.29          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)23                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 44                  $487 10 0.08          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 93                  $48 13 2.28          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 15                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)19                  $1 9 11.14       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 92                  $89 13 1.09          
Appliances Refrigerator Baseline (2014)123                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)196                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 729 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-12 www.gepllc.com

Table C-3 Energy Efficiency Equipment Data—Multi Family, Existing Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 108                $32 11 2.88          
Appliances Freezer Baseline (2014)145                $0 11 ‐            
Appliances Freezer Energy Star (2014)231                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 93                  $89 13 1.11          
Appliances Second Refrigerator Baseline (2014)124                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)199                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 4                    $2 13 2.99          
Appliances Stove Induction (High Efficiency) 20                  $1,432 13 0.02          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 86                  $1 5 29.28       
Electronics Personal Computers Climate Savers 123                $175 5 0.29          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 43                  $1 11 67.65       
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump ‐                   $85 15 ‐            
Miscellaneous Pool Pump Two‐Speed Pump ‐                   $579 15 ‐            
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 10                  $1 18 21.87       
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 730 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-13
An EnerNOC Company
Table C-4 Energy Efficiency Equipment Data — Mobile Home, Existing Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)80                  $278 15 0.24          
Cooling Central AC SEER 15 (CEE Tier 2)110                $556 15 0.17          
Cooling Central AC SEER 16 (CEE Tier 3)134                $834 15 0.14          
Cooling Central AC Ductless Mini‐Split System 241                $4,399 20 0.08          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)37                  $52 10 0.40          
Cooling Room AC EER 11 44                  $141 10 0.17          
Cooling Room AC EER 11.5 59                  $313 10 0.11          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)282                $1,246 15 0.20          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)387                $2,315 15 0.15          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)475                $3,277 15 0.13          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 852                $5,022 20 0.27          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 295                $1,500 14 0.16          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95)88                  $41 15 2.95          
Water Heating Water Heater Solar 1,271            $5,653 15 0.31          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 13.00       
Interior Lighting*Screw‐in LED 40                  $80 12 0.81          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.04          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.64          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.13          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.70          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 20.19       
Exterior Lighting* Screw‐in LED 37                  $79 12 0.80          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 6.66          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 3.63          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 8.23          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.74          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)46                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 89                  $487 10 0.16          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 99                  $48 13 2.43          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 41                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)54                  $1 9 31.57       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 110                $89 13 1.30          
Appliances Refrigerator Baseline (2014)146                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)234                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 731 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-14 www.gepllc.com

Table C-4 Energy Efficiency Equipment Data — Mobile Home, Existing Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 116                $32 11 3.08          
Appliances Freezer Baseline (2014)155                $0 11 ‐            
Appliances Freezer Energy Star (2014)248                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 113                $89 13 1.34          
Appliances Second Refrigerator Baseline (2014)150                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)241                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 8                    $2 13 6.30          
Appliances Stove Induction (High Efficiency) 41                  $1,432 13 0.04          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 101                $1 5 33.39       
Electronics Personal Computers Climate Savers 144                $175 5 0.33          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 87                  $1 11 133.21     
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 138                $85 15 1.96          
Miscellaneous Pool Pump Two‐Speed Pump 551                $579 15 1.15          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 127                $1 18 281.65     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 732 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-15
An EnerNOC Company
Table C-5 Energy Efficiency Equipment Data — Limited Income, Existing Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)76                  $185 15 0.35          
Cooling Central AC SEER 15 (CEE Tier 2)104                $370 15 0.24          
Cooling Central AC SEER 16 (CEE Tier 3)127                $556 15 0.19          
Cooling Central AC Ductless Mini‐Split System 229                $2,394 20 0.15          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)65                  $104 10 0.35          
Cooling Room AC EER 11 77                  $282 10 0.15          
Cooling Room AC EER 11.5 104                $626 10 0.09          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)192                $1,246 15 0.13          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)263                $2,315 15 0.10          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)323                $3,277 15 0.09          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 579                $5,022 20 0.18          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 201                $1,500 14 0.11          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 116                $41 15 3.94          
Water Heating Water Heater Solar 1,679            $5,653 15 0.41          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 13.85       
Interior Lighting*Screw‐in LED 40                  $80 12 0.86          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 32.52       
Exterior Lighting* Screw‐in LED 37                  $79 12 1.29          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)20                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 38                  $487 10 0.07          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 104                $48 13 2.56          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 12                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)15                  $1 9 9.07          
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 92                  $89 13 1.09          
Appliances Refrigerator Baseline (2014)123                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)196                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 733 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-16 www.gepllc.com

Table C-5 Energy Efficiency Equipment Data — Limited Income, Existing Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 108                $32 11 2.88          
Appliances Freezer Baseline (2014)145                $0 11 ‐            
Appliances Freezer Energy Star (2014)231                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 93                  $89 13 1.11          
Appliances Second Refrigerator Baseline (2014)124                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)199                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 5                    $2 13 3.59          
Appliances Stove Induction (High Efficiency) 24                  $1,432 13 0.02          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 89                  $1 5 30.10       
Electronics Personal Computers Climate Savers 127                $175 5 0.29          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 49                  $1 11 77.80       
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 57                  $85 15 0.83          
Miscellaneous Pool Pump Two‐Speed Pump 226                $579 15 0.49          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 54                  $1 18 123.18     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 734 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-17
An EnerNOC Company
Table C-6 Energy Efficiency Equipment Data —Single Family, New Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)180                $278 15 0.55          
Cooling Central AC SEER 15 (CEE Tier 2)240                $556 15 0.36          
Cooling Central AC SEER 16 (CEE Tier 3)290                $834 15 0.29          
Cooling Central AC Ductless Mini‐Split System 543                $4,399 20 0.19          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)76                  $104 10 0.41          
Cooling Room AC EER 11 90                  $282 10 0.18          
Cooling Room AC EER 11.5 122                $626 10 0.11          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)588                $1,000 15 0.51          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)783                $2,318 15 0.30          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)946                $3,505 15 0.24          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 1,775            $5,655 20 0.54          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 630                $1,500 14 0.35          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 219                $41 15 7.35          
Water Heating Water Heater Geothermal Heat Pump 2,878            $6,586 15 0.60          
Interior Lighting*Water Heater Solar 3,163            $5,653 15 0.77          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 14.05       
Interior Lighting*Screw‐in LED 40                  $80 12 0.87          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Exterior Lighting* Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 21.82       
Exterior Lighting* Screw‐in LED 37                  $79 12 0.87          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)58                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 112                $487 10 0.21          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 117                $48 13 2.86          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 47                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)62                  $1 9 36.25       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 102                $89 13 1.20          
Appliances Refrigerator Baseline (2014)135                $0 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 735 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-18 www.gepllc.com

Table C-6 Energy Efficiency Equipment Data —Single Family, New Vintage (cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Refrigerator Energy Star (2014)217                $89 13 ‐            
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 116                $32 11 3.08          
Appliances Freezer Baseline (2014)155                $0 11 ‐            
Appliances Freezer Energy Star (2014)248                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 116                $89 13 1.37          
Appliances Second Refrigerator Baseline (2014)154                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)247                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 11                  $2 13 8.51          
Appliances Stove Induction (High Efficiency) 56                  $1,432 13 0.06          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 111                $1 5 36.63       
Electronics Personal Computers Climate Savers 158                $175 5 0.36          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 96                  $1 11 148.53     
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 156                $85 15 2.22          
Miscellaneous Pool Pump Two‐Speed Pump 623                $579 15 1.30          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 155                $1 18 345.87     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 736 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-19
An EnerNOC Company
Table C-7 Energy Efficiency Equipment Data — Multi Family, New Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)85                  $93 15 0.78          
Cooling Central AC SEER 15 (CEE Tier 2)166                $185 15 0.76          
Cooling Central AC SEER 16 (CEE Tier 3)234                $278 15 0.71          
Cooling Central AC Ductless Mini‐Split System 308                $2,012 20 0.24          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)37                  $52 10 0.39          
Cooling Room AC EER 11 43                  $141 10 0.17          
Cooling Room AC EER 11.5 59                  $313 10 0.10          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)292                $1,246 15 0.21          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)571                $2,315 15 0.22          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)804                $3,277 15 0.21          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 1,058            $5,022 20 0.33          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 282                $1,500 14 0.15          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 124                $41 15 4.19          
Water Heating Water Heater Solar 1,786            $5,653 15 0.44          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 10.18       
Interior Lighting*Screw‐in LED 40                  $80 12 0.63          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 31.63       
Exterior Lighting* Screw‐in LED 37                  $79 12 1.26          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)26                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 51                  $487 10 0.09          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 105                $48 13 2.56          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 16                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)21                  $1 9 12.38       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 108                $89 13 1.28          
Appliances Refrigerator Baseline (2014)144                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)230                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 737 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-20 www.gepllc.com

Table C-7 Energy Efficiency Equipment Data — Multi Family, New Vintage (cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 115                $32 11 3.06          
Appliances Freezer Baseline (2014)154                $0 11 ‐            
Appliances Freezer Energy Star (2014)246                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 103                $89 13 1.21          
Appliances Second Refrigerator Baseline (2014)137                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)219                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 4                    $2 13 3.31          
Appliances Stove Induction (High Efficiency) 22                  $1,432 13 0.02          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 88                  $1 5 29.69       
Electronics Personal Computers Climate Savers 125                $175 5 0.29          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 45                  $1 11 71.54       
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump ‐                   $85 15 ‐            
Miscellaneous Pool Pump Two‐Speed Pump ‐                   $579 15 ‐            
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 11                  $1 18 24.36       
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 738 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-21
An EnerNOC Company
Table C-8 Energy Efficiency Equipment Data — Mobile Home, New Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)100                $278 15 0.30          
Cooling Central AC SEER 15 (CEE Tier 2)133                $556 15 0.20          
Cooling Central AC SEER 16 (CEE Tier 3)161                $834 15 0.16          
Cooling Central AC Ductless Mini‐Split System 301                $4,399 20 0.11          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)42                  $52 10 0.45          
Cooling Room AC EER 11 50                  $141 10 0.20          
Cooling Room AC EER 11.5 67                  $313 10 0.12          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)313                $1,246 15 0.22          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)417                $2,315 15 0.16          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)505                $3,277 15 0.13          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 946                $5,022 20 0.30          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 336                $1,500 14 0.18          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 102                $41 15 3.42          
Water Heating Water Heater Solar 1,474            $5,653 15 0.36          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 12.64       
Interior Lighting*Screw‐in LED 40                  $80 12 0.79          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.04          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.64          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.13          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.70          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 19.63       
Exterior Lighting* Screw‐in LED 37                  $79 12 0.78          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 6.66          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 3.63          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 8.23          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.74          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)54                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 104                $487 10 0.19          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 111                $48 13 2.73          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 46                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)60                  $1 9 35.11       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 129                $89 13 1.52          
Appliances Refrigerator Baseline (2014)172                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)275                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 739 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-22 www.gepllc.com

Table C-8 Energy Efficiency Equipment Data — Mobile Home, New Vintage (cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 124                $32 11 3.28          
Appliances Freezer Baseline (2014)165                $0 11 ‐            
Appliances Freezer Energy Star (2014)263                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 124                $89 13 1.47          
Appliances Second Refrigerator Baseline (2014)165                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)264                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 9                    $2 13 6.98          
Appliances Stove Induction (High Efficiency) 46                  $1,432 13 0.05          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 103                $1 5 33.86       
Electronics Personal Computers Climate Savers 146                $175 5 0.33          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 91                  $1 11 140.87     
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 154                $85 15 2.20          
Miscellaneous Pool Pump Two‐Speed Pump 617                $579 15 1.29          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 141                $1 18 313.76     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 740 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-23
An EnerNOC Company
Table C-9 Energy Efficiency Equipment Data — Limited Income, New Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)95                  $185 15 0.43          
Cooling Central AC SEER 15 (CEE Tier 2)126                $370 15 0.29          
Cooling Central AC SEER 16 (CEE Tier 3)152                $556 15 0.23          
Cooling Central AC Ductless Mini‐Split System 286                $2,394 20 0.18          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)74                  $104 10 0.40          
Cooling Room AC EER 11 87                  $282 10 0.17          
Cooling Room AC EER 11.5 118                $626 10 0.11          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)213                $1,246 15 0.15          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)284                $2,315 15 0.11          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)343                $3,277 15 0.09          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 643                $5,022 20 0.20          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 228                $1,500 14 0.13          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 135                $41 15 4.57          
Water Heating Water Heater Solar 1,949            $5,653 15 0.48          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 13.47       
Interior Lighting*Screw‐in LED 40                  $80 12 0.84          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 31.63       
Exterior Lighting* Screw‐in LED 37                  $79 12 1.26          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)23                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 44                  $487 10 0.08          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 117                $48 13 2.87          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 13                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)17                  $1 9 10.08       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 108                $89 13 1.28          
Appliances Refrigerator Baseline (2014)144                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)230                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 741 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-24 www.gepllc.com

Table C-9 Energy Efficiency Equipment Data — Limited Income, New Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 115                $32 11 3.06          
Appliances Freezer Baseline (2014)154                $0 11 ‐            
Appliances Freezer Energy Star (2014)246                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 103                $89 13 1.21          
Appliances Second Refrigerator Baseline (2014)137                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)219                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 5                    $2 13 3.98          
Appliances Stove Induction (High Efficiency) 26                  $1,432 13 0.03          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 90                  $1 5 30.52       
Electronics Personal Computers Climate Savers 129                $175 5 0.30          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 52                  $1 11 82.28       
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 63                  $85 15 0.93          
Miscellaneous Pool Pump Two‐Speed Pump 254                $579 15 0.54          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 60                  $1 18 137.23     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 742 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-25
An EnerNOC Company
Table C-10 Energy-Efficiency Measure Data—Single Family, Existing Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Early Replacement Cooling 10% 0% 0% 8% $2,895 15 0.05
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 41% 100% $125 4 0.70
Room AC ‐ Removal of Second Unit Cooling 100% 0% 0% 25% $75 5 2.45
Attic Fan ‐ Installation Cooling 1% 0% 12% 23% $116 18 0.08
Attic Fan ‐ Photovoltaic ‐ Installation Cooling 1% 0% 13% 45% $350 19 0.06
Ceiling Fan ‐ Installation Cooling 11% 0% 51% 75% $160 15 0.81
Whole‐House Fan ‐ Installation Cooling 9% 0% 7% 19% $200 18 0.62
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 1.49
Insulation ‐ Ducting Cooling 3% 0% 15% 75% $500 18 0.78
Insulation ‐ Ducting Space Heating 4% 4% 15% 75% $500 18 0.78
Repair and Sealing ‐ Ducting Cooling 10% 0% 12% 50% $500 18 2.08
Repair and Sealing ‐ Ducting Space Heating 15% 15% 12% 50% $500 18 2.08
Thermostat ‐ Clock/Programmable Cooling 8% 0% 55% 56% $114 11 2.89
Thermostat ‐ Clock/Programmable Space Heating 9% 5% 55% 56% $114 11 2.89
Doors ‐ Storm and Thermal Cooling 1% 0% 38% 75% $320 12 0.25
Doors ‐ Storm and Thermal Space Heating 2% 2% 38% 75% $320 12 0.25
Insulation ‐ Infiltration Control Cooling 3% 0% 46% 90% $266 12 1.72
Insulation ‐ Infiltration Control Space Heating 10% 10% 46% 90% $266 12 1.72
Insulation ‐ Ceiling Cooling 3% 0% 68% 72% $594 20 1.11
Insulation ‐ Ceiling Space Heating 10% 5% 68% 72% $594 20 1.11
Insulation ‐ Radiant Barrier Cooling 5% 0% 5% 90% $923 12 0.41
Insulation ‐ Radiant Barrier Space Heating 2% 1% 5% 90% $923 12 0.41
Roofs ‐ High Reflectivity Cooling 6% 0% 5% 10% $1,550 15 0.05
Windows ‐ Reflective Film Cooling 7% 0% 5% 45% $267 10 0.21
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 83% 90% $7,500 25 0.38
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 83% 90% $7,500 25 0.38
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 24% 25% $750 15 0.10
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 80% $2,975 15 0.03
Exterior Lighting ‐ Photosensor Control Exterior Lighting 15% 0% 24% 45% $90 8 0.21
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 10% 45% $72 8 0.35
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 53% 90% $24 25 8.78
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 17% 38% $180 13 1.05
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 75% 80% $96 10 4.56
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 54% 75% $15 10 15.53
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 17% 75% $40 5 2.99
Water Heater ‐ Timer Water Heating 8% 4% 17% 40% $194 10 1.06
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 3.28
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 1.76
Refrigerator ‐ Early Replacement Appliances 15% 15% 0% 20% $1,203 13 0.08
Refrigerator ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.99
Freezer ‐ Early Replacement Appliances 15% 15% 0% 20% $484 11 0.18
Freezer ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.76
Home Energy Management System Cooling 10% 0% 20% 38% $300 20 2.46
Home Energy Management System Space Heating 10% 5% 20% 38% $300 20 2.46
Home Energy Management System Interior Lighting 10% 5% 20% 38% $300 20 2.46
Photovoltaics Cooling 50% 0% 0% 48% $17,000 15 0.10
Photovoltaics Space Heating 25% 25% 0% 48% $17,000 15 0.10
Pool ‐ Pump Timer Miscellaneous 60% 0% 59% 90% $160 15 4.92
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.43
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 25% $1,500 15 0.75
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $3,675 15 1.22
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $13,769 15 0.95
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 743 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-26 www.gepllc.com

Table C-11 Energy-Efficiency Measure Data — Multi Family, Existing Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Early Replacement Cooling 10% 0% 0% 8% $2,895 15 0.02
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 33% 100% $100 4 0.59
Room AC ‐ Removal of Second Unit Cooling 100% 0% 0% 25% $75 5 1.28
Ceiling Fan ‐ Installation Cooling 11% 0% 32% 75% $80 15 0.49
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $100 4 1.05
Insulation ‐ Ducting Cooling 3% 0% 13% 75% $375 18 1.16
Insulation ‐ Ducting Space Heating 4% 4% 13% 75% $375 18 1.16
Repair and Sealing ‐ Ducting Cooling 4% 0% 12% 50% $500 18 0.95
Repair and Sealing ‐ Ducting Space Heating 4% 4% 12% 50% $500 18 0.95
Thermostat ‐ Clock/Programmable Cooling 8% 0% 27% 68% $114 11 2.39
Thermostat ‐ Clock/Programmable Space Heating 6% 3% 27% 68% $114 11 2.39
Doors ‐ Storm and Thermal Cooling 1% 0% 17% 75% $320 12 0.35
Doors ‐ Storm and Thermal Space Heating 2% 2% 17% 75% $320 12 0.35
Insulation ‐ Infiltration Control Cooling 1% 0% 19% 90% $266 12 2.95
Insulation ‐ Infiltration Control Space Heating 13% 13% 19% 90% $266 12 2.95
Insulation ‐ Ceiling Cooling 13% 0% 27% 30% $215 20 5.67
Insulation ‐ Ceiling Space Heating 13% 13% 27% 30% $215 20 5.67
Insulation ‐ Radiant Barrier Cooling 4% 0% 5% 90% $923 12 0.52
Insulation ‐ Radiant Barrier Space Heating 4% 4% 5% 90% $923 12 0.52
Roofs ‐ High Reflectivity Cooling 13% 0% 3% 10% $1,550 15 0.03
Windows ‐ Reflective Film Cooling 7% 0% 5% 45% $167 10 0.10
Windows ‐ High Efficiency/Energy Star Cooling 13% 0% 70% 90% $2,500 25 0.56
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 70% 90% $2,500 25 0.56
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 6% 10% $256 15 0.14
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 50% $2,975 15 0.00
Exterior Lighting ‐ Photosensor Control Exterior Lighting 20% 0% 7% 45% $90 8 0.04
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 6% 45% $72 8 0.05
Water Heater ‐ Faucet Aerators Water Heating 5% 2% 43% 90% $24 25 6.63
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 6% 38% $180 13 0.65
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 71% 75% $96 10 2.84
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 54% 75% $15 10 9.66
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 17% 75% $40 5 1.86
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.66
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 2.04
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 0.58
Refrigerator ‐ Early Replacement Appliances 15% 15% 0% 20% $1,203 13 0.07
Refrigerator ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.36
Freezer ‐ Early Replacement Appliances 15% 15% 0% 20% $484 11 0.17
Freezer ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.57
Home Energy Management System Cooling 10% 0% 5% 13% $300 20 2.46
Home Energy Management System Space Heating 10% 5% 5% 13% $300 20 2.46
Home Energy Management System Interior Lighting 10% 5% 5% 13% $300 20 2.46
Photovoltaics Cooling 50% 0% 0% 12% $8,500 15 0.22
Photovoltaics Space Heating 25% 25% 0% 12% $8,500 15 0.22
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.13
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 10% $1,500 15 0.47
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,845 15 0.99
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $10,946 15 0.72
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 744 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-27
An EnerNOC Company
Table C-12 Energy-Efficiency Measure Data — Mobile Home, Existing Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Early Replacement Cooling 10% 0% 0% 8% $2,895 15 0.03
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 59% 100% $100 4 0.63
Room AC ‐ Removal of Second Unit Cooling 100% 0% 0% 25% $75 5 1.46
Ceiling Fan ‐ Installation Cooling 11% 0% 60% 75% $80 15 0.79
Whole‐House Fan ‐ Installation Cooling 9% 0% 5% 19% $150 18 0.41
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 1.02
Insulation ‐ Ducting Cooling 3% 0% 15% 75% $375 18 0.94
Insulation ‐ Ducting Space Heating 4% 4% 15% 75% $375 18 0.94
Repair and Sealing ‐ Ducting Cooling 10% 0% 12% 50% $500 18 2.08
Repair and Sealing ‐ Ducting Space Heating 15% 15% 12% 50% $500 18 2.08
Thermostat ‐ Clock/Programmable Cooling 8% 0% 51% 56% $114 11 2.78
Thermostat ‐ Clock/Programmable Space Heating 9% 5% 51% 56% $114 11 2.78
Doors ‐ Storm and Thermal Cooling 1% 0% 38% 75% $320 12 0.25
Doors ‐ Storm and Thermal Space Heating 2% 2% 38% 75% $320 12 0.25
Insulation ‐ Infiltration Control Cooling 3% 0% 46% 90% $266 12 1.80
Insulation ‐ Infiltration Control Space Heating 10% 10% 46% 90% $266 12 1.80
Insulation ‐ Ceiling Cooling 3% 0% 79% 81% $707 20 1.00
Insulation ‐ Ceiling Space Heating 10% 5% 79% 81% $707 20 1.00
Insulation ‐ Radiant Barrier Cooling 2% 0% 5% 90% $923 12 0.35
Insulation ‐ Radiant Barrier Space Heating 1% 1% 5% 90% $923 12 0.35
Roofs ‐ High Reflectivity Cooling 6% 0% 5% 10% $1,550 15 0.02
Windows ‐ Reflective Film Cooling 7% 0% 5% 45% $167 10 0.16
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 47% 90% $7,500 25 0.37
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 47% 90% $7,500 25 0.37
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 67% 72% $750 15 0.09
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 80% $2,975 15 0.03
Exterior Lighting ‐ Photosensor Control Exterior Lighting 15% 0% 23% 45% $90 8 0.19
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 10% 45% $72 8 0.32
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 79% 90% $24 25 4.47
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 17% 38% $180 13 0.53
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 92% 95% $96 10 2.32
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 54% 75% $15 10 7.91
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 17% 75% $40 5 1.52
Water Heater ‐ Timer Water Heating 8% 4% 17% 40% $194 10 0.54
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 1.67
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 1.65
Refrigerator ‐ Early Replacement Appliances 15% 15% 0% 20% $1,203 13 0.08
Refrigerator ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 4.06
Freezer ‐ Early Replacement Appliances 15% 15% 0% 20% $484 11 0.18
Freezer ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.82
Home Energy Management System Cooling 10% 0% 20% 38% $300 20 2.28
Home Energy Management System Space Heating 10% 5% 20% 38% $300 20 2.28
Home Energy Management System Interior Lighting 10% 5% 20% 38% $300 20 2.28
Photovoltaics Cooling 50% 0% 0% 48% $17,000 15 0.09
Photovoltaics Space Heating 25% 25% 0% 48% $17,000 15 0.09
Pool ‐ Pump Timer Miscellaneous 60% 0% 50% 90% $160 15 4.92
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.21
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 10% $1,500 15 0.38
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,616 15 0.88
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $11,135 15 0.62
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 745 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-28 www.gepllc.com

Table C-13 Energy-Efficiency Measure Data — Limited Income, Existing Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Early Replacement Cooling 10% 0% 0% 8% $2,895 15 0.03
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 25% 100% $100 4 0.61
Room AC ‐ Removal of Second Unit Cooling 100% 0% 0% 25% $75 5 2.56
Attic Fan ‐ Installation Cooling 1% 0% 3% 23% $116 18 0.05
Attic Fan ‐ Photovoltaic ‐ Installation Cooling 1% 0% 2% 11% $350 19 0.03
Ceiling Fan ‐ Installation Cooling 11% 0% 41% 75% $80 15 0.89
Whole‐House Fan ‐ Installation Cooling 9% 0% 5% 19% $150 18 0.46
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 0.82
Insulation ‐ Ducting Cooling 3% 0% 13% 75% $395 18 0.90
Insulation ‐ Ducting Space Heating 4% 4% 13% 75% $395 18 0.90
Repair and Sealing ‐ Ducting Cooling 10% 0% 12% 50% $500 18 2.07
Repair and Sealing ‐ Ducting Space Heating 15% 15% 12% 50% $500 18 2.07
Thermostat ‐ Clock/Programmable Cooling 8% 0% 27% 68% $114 11 2.63
Thermostat ‐ Clock/Programmable Space Heating 9% 5% 27% 68% $114 11 2.63
Doors ‐ Storm and Thermal Cooling 1% 0% 17% 75% $320 12 0.25
Doors ‐ Storm and Thermal Space Heating 2% 2% 17% 75% $320 12 0.25
Insulation ‐ Infiltration Control Cooling 3% 0% 19% 90% $266 12 1.78
Insulation ‐ Infiltration Control Space Heating 10% 10% 19% 90% $266 12 1.78
Insulation ‐ Ceiling Cooling 3% 0% 36% 41% $215 20 2.44
Insulation ‐ Ceiling Space Heating 10% 5% 36% 41% $215 20 2.44
Insulation ‐ Radiant Barrier Cooling 2% 0% 5% 90% $923 12 0.35
Insulation ‐ Radiant Barrier Space Heating 1% 1% 5% 90% $923 12 0.35
Roofs ‐ High Reflectivity Cooling 6% 0% 3% 10% $1,550 15 0.03
Windows ‐ Reflective Film Cooling 7% 0% 5% 45% $167 10 0.18
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 68% 90% $2,500 25 0.51
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 68% 90% $2,500 25 0.51
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 8% 10% $256 15 0.16
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 50% 10% 50% $2,975 15 0.01
Exterior Lighting ‐ Photosensor Control Exterior Lighting 15% 0% 8% 45% $90 8 0.06
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 6% 45% $72 8 0.10
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 46% 90% $24 25 5.95
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 6% 38% $180 13 0.71
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 73% 75% $96 10 3.09
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 54% 75% $15 10 10.53
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 17% 75% $40 5 2.03
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.72
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 2.23
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 0.77
Refrigerator ‐ Early Replacement Appliances 15% 15% 0% 20% $1,203 13 0.07
Refrigerator ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.36
Freezer ‐ Early Replacement Appliances 15% 15% 0% 20% $484 11 0.17
Freezer ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.57
Home Energy Management System Cooling 10% 0% 5% 13% $300 20 2.00
Home Energy Management System Space Heating 10% 5% 5% 13% $300 20 2.00
Home Energy Management System Interior Lighting 10% 5% 5% 13% $300 20 2.00
Photovoltaics Cooling 50% 0% 0% 48% $8,500 15 0.17
Photovoltaics Space Heating 25% 25% 0% 48% $8,500 15 0.17
Pool ‐ Pump Timer Miscellaneous 60% 0% 50% 90% $160 15 2.02
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.24
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 20% $1,500 15 0.51
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,970 15 1.03
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $10,798 15 0.69
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 746 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-29
An EnerNOC Company
Table C-14 Energy-Efficiency Measure Data — Single Family, New Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 41% 100% $125 4 0.78
Attic Fan ‐ Installation Cooling 1% 0% 13% 23% $97 18 0.15
Attic Fan ‐ Photovoltaic ‐ Installation Cooling 1% 0% 4% 11% $200 19 0.15
Ceiling Fan ‐ Installation Cooling 10% 0% 53% 75% $160 15 1.09
Whole‐House Fan ‐ Installation Cooling 9% 0% 4% 19% $200 18 0.92
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 1.69
Insulation ‐ Ducting Cooling 3% 0% 50% 75% $250 18 1.31
Insulation ‐ Ducting Space Heating 4% 4% 50% 75% $250 18 1.31
Thermostat ‐ Clock/Programmable Cooling 8% 0% 91% 95% $114 11 2.91
Thermostat ‐ Clock/Programmable Space Heating 8% 4% 91% 95% $114 11 2.91
Doors ‐ Storm and Thermal Cooling 1% 0% 13% 75% $180 12 0.45
Doors ‐ Storm and Thermal Space Heating 2% 2% 13% 75% $180 12 0.45
Insulation ‐ Ceiling Cooling 3% 0% 68% 71% $634 20 0.99
Insulation ‐ Ceiling Space Heating 8% 6% 68% 71% $634 20 0.99
Insulation ‐ Radiant Barrier Cooling 2% 0% 25% 90% $923 12 0.37
Insulation ‐ Radiant Barrier Space Heating 1% 1% 25% 90% $923 12 0.37
Insulation ‐ Foundation Cooling 3% 0% 20% 90% $358 20 1.35
Insulation ‐ Foundation Space Heating 6% 6% 20% 90% $358 20 1.35
Insulation ‐ Wall Cavity Cooling 2% 0% 20% 90% $236 20 1.15
Insulation ‐ Wall Cavity Space Heating 3% 3% 20% 90% $236 20 1.15
Insulation ‐ Wall Sheathing Cooling 1% 0% 64% 90% $300 20 0.89
Insulation ‐ Wall Sheathing Space Heating 3% 3% 64% 90% $300 20 0.89
Roofs ‐ High Reflectivity Cooling 5% 0% 5% 90% $517 15 0.17
Windows ‐ Reflective Film Cooling 7% 0% 2% 45% $267 10 0.31
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 100% 100% $2,200 25 0.62
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 100% 100% $2,200 25 0.62
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 24% 27% $500 15 0.16
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 80% $2,975 15 0.04
Exterior Lighting ‐ Photosensor Control Exterior Lighting 13% 0% 13% 45% $90 8 0.19
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 16% 45% $72 8 0.36
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 38% 90% $24 25 11.03
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 8% 41% $50 13 4.71
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 90% 95% $48 10 11.33
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $15 10 19.30
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 5% 75% $40 5 3.70
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 1.31
Water Heater ‐ Drainwater Heat Reocvery Water Heating 9% 5% 1% 90% $899 15 0.47
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 4.06
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 1.99
Home Energy Management System Cooling 10% 0% 20% 68% $250 20 3.16
Home Energy Management System Space Heating 10% 5%20% 68% $250 20 3.16
Home Energy Management System Interior Lighting 10% 5% 20% 68% $250 20 3.16
Photovoltaics Cooling 50% 0% 1% 48% $15,800 15 0.12
Photovoltaics Space Heating 25% 25% 1% 48% $15,800 15 0.12
Pool ‐ Pump Timer Miscellaneous 60% 0% 55% 90% $160 15 5.43
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.64
Advanced New Construction Designs Cooling 40% 0% 2% 45% $4,500 18 1.09
Advanced New Construction Designs Space Heating 40% 40% 2% 45% $4,500 18 1.09
Advanced New Construction Designs Interior Lighting 20% 20% 2% 45% $4,500 18 1.09
Energy Star Homes Cooling 20% 0% 12% 75% $5,000 18 0.75
Energy Star Homes Space Heating 20% 20% 12% 75% $5,000 18 0.75
Energy Star Homes Interior Lighting 20% 20% 12% 75% $5,000 18 0.75
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 25% $1,500 15 0.94
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $3,675 15 1.53
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $13,769 15 1.14
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 747 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-30 www.gepllc.com

Table C-15 Energy-Efficiency Measure Data — Multi Family, New Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 33% 100% $100 4 0.62
Ceiling Fan ‐ Installation Cooling 10% 0% 18% 75% $80 15 0.77
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $100 4 1.12
Insulation ‐ Ducting Cooling 2% 0% 50% 75% $200 18 1.18
Insulation ‐ Ducting Space Heating 2% 2% 50% 75% $200 18 1.18
Thermostat ‐ Clock/Programmable Cooling 8% 0% 77% 80% $114 11 2.29
Thermostat ‐ Clock/Programmable Space Heating 5% 3% 77% 80% $114 11 2.29
Doors ‐ Storm and Thermal Cooling 1% 0% 19% 75% $180 12 0.66
Doors ‐ Storm and Thermal Space Heating 2% 2% 19% 75% $180 12 0.66
Insulation ‐ Ceiling Cooling 12% 0% 27% 48% $152 20 10.12
Insulation ‐ Ceiling Space Heating 16% 16% 27% 48% $152 20 10.12
Insulation ‐ Radiant Barrier Cooling 2% 0% 5% 90% $923 12 0.50
Insulation ‐ Radiant Barrier Space Heating 3% 3% 5% 90% $923 12 0.50
Insulation ‐ Wall Cavity Cooling 2% 0% 4% 90% $63 20 6.14
Insulation ‐ Wall Cavity Space Heating 4% 4% 4% 90% $63 20 6.14
Insulation ‐ Wall Sheathing Cooling 1% 0% 55% 90% $210 20 1.59
Insulation ‐ Wall Sheathing Space Heating 3% 3% 55% 90% $210 20 1.59
Roofs ‐ High Reflectivity Cooling 8% 0% 0% 90% $517 15 0.10
Windows ‐ Reflective Film Cooling 7% 0% 2% 45% $167 10 0.17
Windows ‐ High Efficiency/Energy Star Cooling 13% 0% 100% 100% $2,200 25 0.63
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 100% 100% $2,200 25 0.63
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 6% 9% $256 15 0.14
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 50% $2,975 15 0.01
Exterior Lighting ‐ Photosensor Control Exterior Lighting 20% 0% 1% 45% $90 8 0.04
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 11% 45% $72 8 0.05
Water Heater ‐ Faucet Aerators Water Heating 5% 2% 11% 90% $24 25 7.63
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 41% $50 13 2.68
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 66% 75% $48 10 6.45
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $15 10 10.99
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 5% 75% $40 5 2.11
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.75
Water Heater ‐ Drainwater Heat Reocvery Water Heating 9% 5% 1% 90% $899 15 0.27
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 2.31
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 0.63
Home Energy Management System Cooling 10% 0% 5% 68% $250 20 3.19
Home Energy Management System Space Heating 10% 5% 5% 68% $250 20 3.19
Home Energy Management System Interior Lighting 10% 5% 5% 68% $250 20 3.19
Photovoltaics Cooling 50% 0% 0% 12% $7,900 15 0.26
Photovoltaics Space Heating 25% 25% 0% 12% $7,900 15 0.26
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.23
Advanced New Construction Designs Cooling 40% 0% 2% 45% $2,500 18 1.47
Advanced New Construction Designs Space Heating 40% 40% 2% 45% $2,500 18 1.47
Advanced New Construction Designs Interior Lighting 20% 20% 2% 45% $2,500 18 1.47
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 10% $1,500 15 0.53
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,845 15 1.13
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $10,946 15 0.84
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 748 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-31
An EnerNOC Company
Table C-16 Energy-Efficiency Measure Data — Mobile Home, New Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 59% 100% $100 4 0.66
Ceiling Fan ‐ Installation Cooling 10% 0% 57% 75% $80 15 0.95
Whole‐House Fan ‐ Installation Cooling 9% 0% 4% 19% $150 18 0.53
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 1.09
Insulation ‐ Ducting Cooling 3% 0% 50% 75% $200 18 1.59
Insulation ‐ Ducting Space Heating 4% 4% 50% 75% $200 18 1.59
Thermostat ‐ Clock/Programmable Cooling 8% 0% 57% 75% $114 11 2.77
Thermostat ‐ Clock/Programmable Space Heating 8% 4% 57% 75% $114 11 2.77
Doors ‐ Storm and Thermal Cooling 1% 0% 13% 75% $180 12 0.49
Doors ‐ Storm and Thermal Space Heating 2% 2% 13% 75% $180 12 0.49
Insulation ‐ Ceiling Cooling 3% 0% 79% 81% $176 20 3.02
Insulation ‐ Ceiling Space Heating 8% 6% 79% 81% $176 20 3.02
Insulation ‐ Radiant Barrier Cooling 2% 0% 25% 90% $923 12 0.36
Insulation ‐ Radiant Barrier Space Heating 1% 1% 25% 90% $923 12 0.36
Insulation ‐ Wall Cavity Cooling 2% 0% 20% 90% $197 20 1.35
Insulation ‐ Wall Cavity Space Heating 3% 3% 20% 90% $197 20 1.35
Insulation ‐ Wall Sheathing Cooling 1% 0% 64% 90% $300 20 0.96
Insulation ‐ Wall Sheathing Space Heating 3% 3% 64% 90% $300 20 0.96
Roofs ‐ High Reflectivity Cooling 5% 0% 5% 90% $517 15 0.07
Windows ‐ Reflective Film Cooling 7% 0% 2% 45% $167 10 0.21
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 85% 90% $2,200 25 0.57
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 85% 90% $2,200 25 0.57
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 67% 72% $500 15 0.14
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 50% 10% 80% $2,975 15 0.03
Exterior Lighting ‐ Photosensor Control Exterior Lighting 13% 0% 13% 45% $90 8 0.17
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 16% 45% $72 8 0.32
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 57% 90% $24 25 5.14
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 8% 41% $50 13 2.20
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 92% 95% $48 10 5.28
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $15 10 9.00
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 5% 75% $40 5 1.72
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.61
Water Heater ‐ Drainwater Heat Reocvery Water Heating 9% 5% 1% 90% $899 15 0.22
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 1.89
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 1.79
Home Energy Management System Cooling 10% 0% 20% 68% $250 20 2.94
Home Energy Management System Space Heating 10% 5% 20% 68% $250 20 2.94
Home Energy Management System Interior Lighting 10% 5% 20% 68% $250 20 2.94
Photovoltaics Cooling 50% 0% 1% 48% $15,800 15 0.10
Photovoltaics Space Heating 25% 25% 1% 48% $15,800 15 0.10
Pool ‐ Pump Timer Miscellaneous 60% 0% 35% 90% $160 15 5.38
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.28
Advanced New Construction Designs Cooling 30% 0% 2% 45% $4,500 18 0.52
Advanced New Construction Designs Space Heating 30% 30% 2% 45% $4,500 18 0.52
Advanced New Construction Designs Interior Lighting 20% 20% 2% 45% $4,500 18 0.52
Energy Efficient Manufactured Homes Cooling 20% 0% 10% 75% $3,500 18 0.88
Energy Efficient Manufactured Homes Space Heating 20% 20% 10% 75% $3,500 18 0.88
Energy Efficient Manufactured Homes Interior Lighting 20% 20% 10% 75% $3,500 18 0.88
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 10% $1,500 15 0.44
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,616 15 1.00
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $11,738 15 0.69
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 749 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-32 www.gepllc.com

Table C-17 Energy-Efficiency Measure Data — Limited Income, New Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 25% 100% $100 4 0.65
Attic Fan ‐ Installation Cooling 1% 0% 15% 23% $97 18 0.07
Attic Fan ‐ Photovoltaic ‐ Installation Cooling 1% 0% 5% 11% $200 19 0.07
Ceiling Fan ‐ Installation Cooling 10% 0% 33% 75% $80 15 1.03
Whole‐House Fan ‐ Installation Cooling 9% 0% 4% 19% $150 18 0.58
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 0.87
Insulation ‐ Ducting Cooling 3% 0% 50% 75% $210 18 1.47
Insulation ‐ Ducting Space Heating 4% 4% 50% 75% $210 18 1.47
Thermostat ‐ Clock/Programmable Cooling 8% 0% 29% 30% $114 11 2.54
Thermostat ‐ Clock/Programmable Space Heating 8% 4% 29% 30% $114 11 2.54
Doors ‐ Storm and Thermal Cooling 1% 0% 19% 75% $180 12 0.46
Doors ‐ Storm and Thermal Space Heating 2% 2% 19% 75% $180 12 0.46
Insulation ‐ Ceiling Cooling 3% 0% 36% 48% $152 20 3.20
Insulation ‐ Ceiling Space Heating 8% 6% 36% 48% $152 20 3.20
Insulation ‐ Radiant Barrier Cooling 2% 0% 5% 90% $923 12 0.36
Insulation ‐ Radiant Barrier Space Heating 1% 1% 5% 90% $923 12 0.36
Insulation ‐ Foundation Cooling 3% 0% 4% 90% $358 20 1.37
Insulation ‐ Foundation Space Heating 6% 6% 4% 90% $358 20 1.37
Insulation ‐ Wall Cavity Cooling 2% 0% 4% 90% $63 20 3.46
Insulation ‐ Wall Cavity Space Heating 3% 3% 4% 90% $63 20 3.46
Insulation ‐ Wall Sheathing Cooling 1% 0% 59% 90% $210 20 1.19
Insulation ‐ Wall Sheathing Space Heating 3% 3% 59% 90% $210 20 1.19
Roofs ‐ High Reflectivity Cooling 5% 0% 0% 90% $517 15 0.08
Windows ‐ Reflective Film Cooling 7% 0% 2% 45% $167 10 0.23
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 78% 90% $2,200 25 0.55
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 78% 90% $2,200 25 0.55
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 8% 9% $256 15 0.17
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 50% 10% 50% $2,975 15 0.01
Exterior Lighting ‐ Photosensor Control Exterior Lighting 13% 0% 0% 45% $90 8 0.06
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 11% 45% $72 8 0.10
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 11% 90% $24 25 6.84
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 41% $50 13 2.92
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 21% 75% $48 10 7.03
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $15 10 11.97
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 5% 75% $40 5 2.29
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.81
Water Heater ‐ Drainwater Heat Reocvery Water Heating 9% 5% 1% 90% $899 15 0.29
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 2.52
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 0.83
Home Energy Management System Cooling 10% 0% 5% 68% $250 20 2.50
Home Energy Management System Space Heating 10% 5%5% 68% $250 20 2.50
Home Energy Management System Interior Lighting 10% 5% 5% 68% $250 20 2.50
Photovoltaics Cooling 50% 0% 0% 48% $7,900 15 0.20
Photovoltaics Space Heating 25% 25% 0% 48% $7,900 15 0.20
Pool ‐ Pump Timer Miscellaneous 60% 0% 35% 90% $160 15 2.21
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.30
Advanced New Construction Designs Cooling 30% 0% 2% 45% $2,500 18 1.25
Advanced New Construction Designs Space Heating 30% 30% 2% 45% $2,500 18 1.25
Advanced New Construction Designs Interior Lighting 20% 20% 2% 45% $2,500 18 1.25
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 20% $1,500 15 0.58
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,970 15 1.18
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $10,798 15 0.81
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 750 of 1069

Global Energy Partners D-1
An EnerNOC Company

APPENDIX D
COMMERCIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA
This appendix presents detailed information for all commercial and industrial energy efficiency
equipment and measures that were evaluated in LoadMAP. Several sets of tables are provided.
Table D-1 provides brief descriptions for all equipment and measures that were assessed for
potenital.
Tables D-2 through D-9 list the detailed unit-level data for the equipment measures for each of
the C&I segments — small/medium commercial, large commercial, extra-large commercial, and
extra-large industial — and for existing and new construction, respectively. Savings are in
kWh/yr/sq.ft., and incremental costs are in $/sq.ft. The B/C ratio is zero if the measure
represents the baseline technology or if the technology is not available in the first year of the
forecast (2012). The B/C ratio is calculated within LoadMAP for each year of the forecast and is
available once the technology or measure becomes available.
Tables D-10 through D-17 list the detailed unit-level data for the non-equipment energy
efficiency measures for each of the segments and for existing and new construction,
respectively. Because these measures can produce energy-use savings for multiple end-use loads
(e.g., insulation affects heating and cooling energy use) savings are expressed as a percentage
of the end-use loads. Base saturation indicates the percentage of buildings in which the measure
is already installed. Applicability/Feasibility is the product of two factors that account for whether
the measure is applicable to the building. Cost is expressed in $/sq.ft. The detailed measure-level
tables present the results of the benefit/cost (B/C) analysis for the first year of the forecast. The
B/C ratio is zero if the measure represents the baseline technology or if the measure is not
available in the first year of the forecast (2012). The B/C ratio is calculated within LoadMAP for
each year of the forecast and is available once the technology or measure becomes available.
Note that Tables D-2 through D-17 present information for Washington. For Idaho, savings and
B/C ratios may be slightly different due to weather-related usage, differences in the states’
market profiles, and different retail electricity prices. Although Idaho-specific values are not
presented here, they are available within the LoadMAP files.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 751 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-2 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling Central Cooling Systems Commercial buildings are often cooled with a central chiller plant that 
creates chilled water for distribution throughout the facility. Chillers can 
be air source or water source, which include heat rejection via a 
condenser loop and cooling tower. Because of the wide variety of 
system types and sizes, savings and cost values for efficiency 
improvements in chiller systems represent an average over air‐ and 
water‐cooled systems, as well as screw, reciprocating, and centrifugal 
technologies. Under this simplified approach, each central system is 
characterized by an aggregate efficiency value (inclusive of chiller, 
pumps, motors and condenser loop equipment), in kW/ton with a 
further efficiency upgrade through the application of variable 
refrigerant flow technology.  
Cooling Chilled Water Variable Flow 
System 
The chilled water variable flow system is essentially a single chilled 
water loop with variable volume and speed. A single set of pumps 
operated by a VSD eliminates the need for separate distribution pumps 
and makes the chilled water flow throughout the entire system be 
variable. The use of adjustable flow limiting valves is designed to 
optimize water flow. Such valves provide flow limiting, shut‐off and 
adjustment functions, automatically compensating for changes in 
system pressure to maximize energy efficiency. 
Cooling Packaged Cooling Systems / 
Rooftop Units (RTUs) and 
Heat Pumps   
Packaged cooling systems are simple to install and maintain, and are 
commonly used in small and medium‐sized commercial buildings.  
Applications range from a single supply system with air intake filters, 
supply fan, and cooling coil, or can become more complex with the 
addition of a return air duct, return air fan, and various controls to 
optimize performance. For packaged RTUs, varying Energy Efficiency 
Ratios (EER) were considered, as well as ductless or “mini‐split” systems 
with variable refrigerant flow. For heat pumps, units with increasing EER 
and COP levels were evaluated, as well as a ductless mini‐split system.  
Cooling Packaged Terminal Air 
Conditioners (PTAC) 
Window (or wall) mounted room air conditioners (and heat pumps) are 
designed to cool (or heat) a single room or space.  This type of unit 
incorporates a complete air‐cooled refrigeration and air‐handling 
system in an individual package.  Conditioned air is discharged in 
response to thermostatic control to meet room requirements.  Each 
unit has a self‐contained, air‐cooled direct expansion (DX) cooling 
system, a heat pump or other fuel‐based heating system and associated 
controls. The energy savings increase with each incremental increase in 
efficiency, measured in terms of EER level.   
Space Heating Convert to Gas This fuel‐switching measure is the replacement of an electric furnace 
with a gas furnace. This measure eliminates all prior electricity 
consumption and demand due to electric space heating. In this study, it 
is assumed this measure can be implemented only in buildings within 
500 feet of a gas main. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 752 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-3
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling, Space 
Heating, 
Interior 
Lighting 
Energy Management 
System 
An energy management system (EMS) allows managers/owners to 
monitor and control the major energy‐consuming systems within a 
commercial building.  At the minimum, the EMS can be used to monitor 
and record energy consumption of the different end‐uses in a building, 
and can control operation schedules of the HVAC and lighting systems.  
The monitoring function helps building managers/owners to identify 
systems that are operating inefficiently so that actions can be taken to 
correct the problem.  The EMS can also provide preventive maintenance 
scheduling that will reduce the cost of operations and maintenance in 
the long run.  The control functionality of the EMS allows the building 
manager/owner to operate building systems from one central location.  
The operation schedules set via the EMS help to prevent building 
systems from operating during unwanted or unoccupied periods. This 
analysis assumes that this measure is limited to buildings with a central 
HVAC system. 
Cooling, Space 
Heating 
Economizer Economizers allow outside air (when it is cool and dry enough) to be 
brought into the building space to meet cooling loads instead of using 
mechanically cooled interior air.  A dual enthalpy economizer consists of 
indoor and outdoor temperature and humidity sensors, dampers, 
motors, and motor controls.  Economizers are most applicable to 
temperate climates and savings will be smaller in extremely hot or 
humid areas. 
Cooling VSD on Water Pumps The part‐load efficiency of chilled water loop pumps can be improved 
substantially by varying the speed of the motor drive according to the 
building demand for cooling.  There is also a reduction in piping losses 
associated with this measure that has a major impact on the energy use 
for a building.  However, pump speeds can generally only be reduced to 
a minimum specified rate, because chillers and the control valves may 
require a minimum flow rate to operate.  There are two major types of 
variable speed drives:  mechanical and electronic.  An additional benefit 
of variable‐speed drives is the ability to start and stop the motor 
gradually, thus extending the life of the motor and associated 
machinery.  This analysis assumes that electronic variable speed drives 
are installed. 
Cooling Turbocor Compressor Turbocor compressors use oil‐free magnetic bearings to reduce friction 
losses and couples that with a two‐stage centrifugal compressor to 
reduce central chiller energy consumption. 
Cooling High‐Efficiency Cooling 
Tower Fans 
High efficiency cooling tower fans utilize variable frequency drives in the 
cooling tower design. VFDs improve fan performance by adjusting fan 
speed and rotation as conditions change. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 753 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-4 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling Condenser Water 
Temperature Reset 
Chilled water reset controls save energy by improving chiller 
performance through increasing the supply chilled water temperature, 
which allows increased suction pressure during low load periods.  
Raising the chilled water temperature also reduces chilled water piping 
losses.  However, the primary savings from the chilled water reset 
measure results from chiller efficiency improvement.  This is due partly 
to the smaller temperature difference between chilled water and 
ambient air, and partly due to the sensitivity of chiller performance to 
suction temperature. 
Cooling Maintenance  Filters, coils, and fins require regular cleaning and maintenance for the 
heat pump or roof top unit to function effectively and efficiently 
throughout its years of service. Neglecting necessary maintenance leads 
to a steady decline in performance while energy use increases.  
Maintenance can increase the efficiency of poorly performing 
equipment by as much as 10%. 
Cooling Evaporative Precooler Evaporative precooling can improve the performance of air conditioning 
systems, most commonly RTUs. These systems typically use indirect 
evaporative cooling as a first stage to pre‐cool outside air. If the 
evaporative system cannot meet the full cooling load, the air steam is 
further cooled with conventional refrigerative air conditioning 
technology.    
Cooling Roof‐ High Reflectivity 
(Cool Roof) 
The color and material of a building structure surface will determine the 
amount of solar radiation absorbed by that surface and subsequently 
transferred into a building. This is called solar absorptance. By using a 
material or painting the roof with a light color (and a lower solar 
absorptance), the roof will absorb less solar radiation and consequently 
reduce the cooling load.  
Cooling, Space 
Heating 
Green Roofs A green roof covers a section or the entire building roof with a 
waterproof membrane and vegetative material. Like cool roofs, green 
roofs can reduce solar absorptance and they can also provide insulation. 
They also provide non‐energy benefits by absorbing rainwater and thus 
reducing storm water run‐off, providing wildlife habitat, and reducing 
so‐called urban heat island effects. 
Cooling, Space 
Heating, 
Ventilation 
HVAC Retrocommissioning Over time, the performance of complex mechanical systems providing 
heating and cooling to existing commercial spaces degrades as a result 
of inappropriate changes to or overrides of controls, deteriorating 
equipment, clogged filters, changing demands and schedules, and 
pressure imbalances. Retrocommissioning is a comprehensive analysis 
of an entire system in which an engineer assesses shortcomings in 
system performance, and then optimizes through a process of tune‐up, 
maintenance, and reprogramming of control or automation software. 
Energy efficiency programs throughout the country promote 
retrocommissioning as a means of greatly reducing energy consumption 
in existing buildings. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 754 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-5
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling, Space 
Heating, 
Ventilation, 
Interior 
Lighting 
Comprehensive 
Retrocommissioning 
Comprehensive retrocommissioning covers not only HVAC and lighting, 
but other existing building systems as well. For example, it can improve 
efficiency of non‐HVAC motors, vertical transport systems, and 
domestic hot water systems.  
Cooling, Space 
Heating, 
Ventilation, 
Interior 
Lighting/Exteri
or Lighting 
HVAC Commissioning  

Lighting Commissioning  

Comprehensive 
Commissioning 
For new construction and major renovations, commissioning ensures 
that building systems are properly designed, specified, and installed to 
meet the design intent and provide high‐efficiency performance. As the 
names suggests, HVAC Commissioning and Lighting Commissioning 
focus only on HVAC and lighting equipment and controls. 
Comprehensive commissioning addresses these systems but usually 
begins earlier in the design process, and may also address domestic hot 
water, non‐HVAC fans, vertical transport, telecommunications, fire 
protection, and other building systems. 
Cooling, Space 
Heating, 
Interior 
Lighting 
Advanced New 
Construction Designs 
Advanced new construction designs use an integrated approach to the 
design of new buildings to account for the interaction of building 
systems. Typically, architects and engineers work closely to specify the 
building orientation, building shell, building mechanical systems, and 
controls strategies with the goal of optimizing building energy efficiency 
and comfort. Options that may be evaluated and incorporated include 
passive solar strategies, increased thermal mass, daylighting strategies, 
and shading strategies, This measure was modeled for new construction 
only. 
Cooling, Space 
Heating 
Programmable Thermostat A programmable thermostat can be added to most heating/cooling 
systems.  They are typically used during winter to lower temperatures 
at night and in summer to increase temperatures during the afternoon.  
There are two‐setting models, and well as models that allow separate 
programming for each day of the week.  The energy savings from this 
type of thermostat are identical to those of a "setback" strategy with 
standard thermostats, but the convenience of a programmable 
thermostat makes it a much more attractive option.  In this analysis, the 
baseline is assumed to have no thermostat setback. 
Cooling, Space 
Heating 
Duct Repair and Sealing An ideal duct system would be free of leaks.  Leakage in unsealed ducts 
varies considerably because of the differences in fabricating machinery 
used, the methods for assembly, installation workmanship, and age of 
the ductwork.  Air leaks from the system to the outdoors result in a 
direct loss proportional to the amount of leakage and the difference in 
enthalpy between the outdoor air and the conditioned air.  To seal 
ducts, a wide variety of sealing methods and products exist.  Each has a 
relatively short shelf life, and no documented research has identified 
the aging characteristics of sealant applications.  This analysis assumes 
that the baseline air loss from ducts has doubled, and conducting repair 
and sealing of the ducts will restore leakage from ducts to the original 
baseline level. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 755 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-6 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling, Space 
Heating 
Duct Insulation Air distribution ducts can be insulated to reduce heating or cooling 
losses.  Best results can be achieved by covering the entire surface area 
with insulation.  Insulation material inhibits the transfer of heat through 
the air‐supply duct.  Several types of ducts and duct insulation are 
available, including flexible duct, pre‐insulated duct, duct board, duct 
wrap, tacked, or glued rigid insulation, and waterproof hard shell 
materials for exterior ducts.   
Cooling, Space 
Heating 
Insulation – Radiant Barrier Radiant barriers inhibit heat transfer by thermal radiation. When a 
radiant barrier is installed beneath the roofing material much of the 
heat radiated from a hot roof is reflected back to the roof limiting the 
amount of heat emitted downwards.  
Cooling, Space 
Heating 
High‐Efficiency Windows High‐efficiency windows, such as those labeled under the ENERGY STAR 
Program, are designed to reduce a building's energy bill while increasing 
comfort for the occupants at the same time.  High‐efficiency windows 
have reducing properties that reduce the amount of heat transfer 
through the glazing surface.  For example, some windows have a low‐E 
coating, which is a thin film of metallic oxide coating on the glass 
surface that allows passage of short‐wave solar energy through glass 
and prevents long‐wave energy from escaping.  Another example is 
double‐pane glass that reduces conductive and convective heat 
transfer.  There are also double‐pane glasses that are gas‐filled (usually 
argon) to further increase the insulating properties of the window. 
Cooling, Space 
Heating 
Ceiling and Wall Cavity  
Insulation 
Thermal insulation is material or combinations of materials that are 
used to inhibit the flow of heat energy by conductive, convective, and 
radiative transfer modes.  Thus, thermal insulation can conserve energy 
by reducing the heat loss or gain of a building.  The type of building 
construction defines insulating possibilities.  Typical insulating materials 
include:  loose‐fill (blown) cellulose; loose‐fill (blown) fiberglass; and 
rigid polystyrene. 
Ventilation Cooking – Exhaust Hoods 
with Sensor Controls 
Improved exhaust hoods involve installing variable‐speed controls on 
commercial kitchen hoods. These controls provide ventilation based on 
actual cooking loads. When grills, broilers, stoves, fryers or other 
kitchen appliances are not being used, the controls automatically sense 
the reduced load and decrease the fan speed accordingly. This results in 
lower energy consumption because the system is only running as 
needed rather than at 100% capacity at all times. 
Ventilation Variable Air Volume A variable air volume ventilation system modulates the air flow rate as 
needed based on the interior conditions of the building to reduce fan 
load, improve dehumidification, and reduce energy usage. 
Ventilation Fans – Energy Efficient 
Motors 
High‐efficiency motors are essentially interchangeable with standard 
motors, but differences in construction make them more efficient.  
Energy‐efficient motors achieve their improved efficiency by reducing 
the losses that occur in the conversion of electrical energy to 
mechanical energy.  This analysis assumes that the efficiency of supply 
fans is increased by 5% due to installing energy‐efficient motors. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 756 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-7
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Ventilation Fans – Variable Speed 
Control (VSD) 
The part‐load efficiency of ventilation fans can be improved 
substantially by varying the speed of the motor drive.  There are two 
major types of variable speed controls:  mechanical and electronic.  An 
additional benefit of variable‐speed controls is the ability to start and 
stop the motor gradually, thus extending the life of the motor and 
associated machinery. This analysis assumes that electronic variable 
speed controls are installed. 
Water Heating High‐Efficiency Water 
Heater Systems 
Efficient electric water heaters are characterized by a high recovery or 
thermal efficiency (percentage of delivered electric energy which is 
transferred to the water) and low standby losses (the ratio of heat lost 
per hour to the content of the stored water). Included in the savings 
associated with high‐efficiency electric water heaters are timers that 
allow temperature setpoints to change with hot water demand 
patterns. For example, the heating element could be shut off 
throughout the night, increasing the overall energy factor of the unit. In 
addition, tank and pipe insulation reduces standby losses and therefore 
reduces the demands on the water heater. This analysis considers 
conventional electric water heaters with efficiency greater than 96%, as 
well as geothermal heat pump water heaters for effective efficiency 
greater than one. Solar water heating was evaluated as well. 
Water Heating Convert to Gas This fuel‐switching measure is the replacement of an electric water 
heater with a gas‐fired water heater. This measure will eliminate all 
prior electricity consumption and demand due to electric water heating. 
In this study, it is assumed that this measure can be implemented only 
in buildings within 500 feet of a gas main. 
Water Heating Heat Pump Water Heater Heat pump water heaters use heat pump technology to extract heat 
from the ambient surroundings and transfer it to a hot water tank. 
These devices are available as an alternative to conventional tank water 
heaters of 55 gallons or larger.   
Water Heating Faucet Aerators/Low Flow 
Nozzles 
A faucet aerator or low flow nozzle spreads the stream from a faucet 
helping to reduce water usage. The amount of water passing through 
the aerator is measured in gallons per minute (GPM) and the lower the 
GPM the more water the aerator conserves.  
Water Heating Pipe Insulation Insulating hot water pipes decreases the amount of energy lost during 
distribution of hot water throughout the building. Insulating pipes will 
result in quicker delivery of hot water and allows lowering the water 
heating set point. There are several different types of insulation, the 
most common being polyethylene and neoprene.       
Water Heating High‐Efficiency Circulation 
Pump 
A high efficiency circulation pump uses an electronically commutated 
motor (ECM) to improve motor efficiency over a larger range of partial 
loads. In addition, an ECM allows for improved low RPM performance 
with greater torque and smaller pump dimensions. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 757 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-8 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Water Heating Tank Blanket/Insulation Insulation levels on domestic hot water heaters can be increased by 
installing a fiberglass blanket on the outside of the tank. This increase in 
insulation reduces standby losses and thus saves energy.  Water heater 
insulation is available either by the blanket or by square foot of 
fiberglass insulation with R‐values ranging from 5 to 14.   
Water Heating Thermostat Setback Installing a setback thermostat on the water heater can lead to 
significant energy savings during periods when there is no one in the 
building.   
Water Heating Hot Water Saver A hot water saver is a plumbing device that attaches to the showerhead 
and that pauses the flow of water until the water is hot enough for use. 
The water is re‐started by the flip of a switch. 
Interior 
Lighting, 
Exterior 
Lighting 
Lamp Replacement 
(Interior Screw‐in, HID, and 
Linear Fluorescent 
 Exterior Screw‐in, HID, and 
Linear Fluorescent) 
Commercial lighting differs from the residential sector in that efficiency 
changes typically require more than the simple purchase and quick 
installation of a screw‐in compact fluorescent lamp. Restrictions 
regarding ballasts, fixtures, and circuitry limit the potential for direct 
substitution of one lamp type for another. However, such replacements 
do exist. For example, screw‐in incandescent lamps can readily be 
replaced with CFLs or LEDs. Also, during the buildout for a leased office 
space, the management could decide to replace all T12 lamps and 
magnetic ballasts with T8/electronic ballast configurations. This type of 
decision‐making is modeled on a stock turnover basis because of the 
time between opportunities for upgrades. 
Interior 
Lighting, 
Exterior 
Lighting 
Lighting 
Retrocommissioning 
Lighting retrocommissioning projects in existing commercial buildings 
do not require an event such as a tenant turnover, a major renovation, 
or an update to electrical circuits to drive its adoption. Rather, a 
decision‐maker can decide at any time to perform a comprehensive 
audit of a facility's lighting systems, followed by an upgrade of 
equipment (lamps, ballasts, fixtures, reflectors), controls (occupancy 
sensors, daylighting controls, and central automation).  
Interior 
Lighting  
Delamping and Install 
Reflectors 
While sometimes included in lighting retrofit projects, delamping is 
often performed as a separate energy efficiency measure in which a 
lighting engineer analyzes the lighting provided by current systems 
compared to the requirements of building occupants. This often leads 
to the removal of unnecessary lamps corresponding to an overall 
reduction in energy usage. .In addition, installing a reflector in each 
fixture can improve light distribution from the remaining lamps.   
Interior 
Lighting, 
Exterior 
Lighting 
Lighting Time Clocks and 
Timers 
While outdoor lighting is typically required only at night, in many cases 
lighting remains on during daylight hours. A simple timer can set a 
diurnal schedule for outdoor lighting and thus reduce the operating 
hours by as much as 50%. 
Interior 
Lighting 
Central Lighting Controls Central lighting control systems provide building‐wide control of interior 
lighting to ensure that lights are properly scheduled based on expected 
building occupancy. Individual zones or circuits can be controlled. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 758 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-9
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Interior 
Lighting 
Photocell Controlled T8 
Dimming Ballasts 
Photocells, in concert with dimming ballasts, can detect when adequate 
daylighting is available and dim or turn off lights to reduce electricity 
consumption. Usually one photocell is used to control a group of 
fixtures, a zone, or a circuit.  
Interior 
Lighting 
Bi‐Level Fixture with 
Occupancy  Sensor 
Bi‐level fixtures with occupancy sensors detect when a space is 
unoccupied and reduce light output to a lower level. These devices  
Interior 
Lighting 
High Bay Fixtures Fluorescent fixtures designed for high‐bay applications have several 
advantages over similar HID fixtures: lower energy consumption, lower 
lumen depreciation rates, better dimming options, faster start‐up and 
restrike, better color rendition, more pupil lumens, and reduced glare.  
Interior 
Lighting 
Occupancy Sensor The installation of occupancy sensors allows lights to be turned off 
during periods when a space is unoccupied, virtually eliminating the 
wasted energy due to lights being left on. There are several types of 
occupancy sensors in the market.  
Interior 
Lighting 
LED Exit Lighting The lamps inside exit signs represent a significant energy end‐use, since 
they usually operate 24 hours per day.  Many old exit signs use 
incandescent lamps, which consume approximately 40 watts per sign.  
The incandescent lamps can be replaced with LED lamps that are 
specially designed for this specific purpose.  In comparison, the LED 
lamps consume approximately 2‐5 watts. 
Interior 
Lighting 
Task Lighting In commercial facilities, individual work areas can use task lighting 
instead of brightly lighting the entire area.  Significant energy savings 
can be realized by focusing light directly where it is needed and 
lowering the general lighting level.  An example of task lighting is the 
common desk lamp.  A 25W desk lamp can be installed in place of a 
typical lamp in a fixture. 
Interior 
Lighting, 
Cooling 
Hotel Guestroom Controls Hotel guestrooms can be fitted with occupancy controls that turn off 
energy‐using equipment when the guest is not using the room.  The 
occupancy controls comes in several forms, but this analysis assumes 
the simplest kind, which is a simple switch near the room’s entry where 
the guest can deposit their room key or card. If the key or card is 
present, then lights, TV, and air conditioning can receive power and 
operate. When the guest leaves and takes the key, all equipment shuts 
off. 
Exterior 
Lighting 
Daylighting Controls Daylighting controls use a photosensor to detect ambient light and turn 
off exterior lights accordingly.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 759 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-10 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Exterior 
Lighting 
Photovoltaic Lighting Outdoor photovoltaic (PV) lighting systems use PV panels (or modules), 
which convert sunlight to electricity.  The electricity is stored in 
batteries for use at night.  They can be cost effective relative to 
installing power cables and/or step down transformers for relatively 
small lighting loads. The "nightly run time" listings on most "off‐the‐
shelf" products are based on specific sunlight conditions. Systems 
located in places that receive less sunlight than the system is designed 
for will operate for fewer hours per night than expected. Nightly run 
times may also vary depending on how clear the sky is on any given day. 
Shading of the PV panel by landscape features (vegetation, buildings, 
etc.) will also have a large impact on battery charging and performance.  
Open areas with no shading, such as parking lots, are ideal places where 
PV lighting systems can be used. 
Exterior 
Lighting 
Cold Cathode Lighting Cold cathode lighting does not use an external heat source to provide 
thermionic emission of electrons. Cold cathode lighting is typically used 
for exterior signage or where temperatures are likely to drop below 
freezing. 
Exterior 
Lighting 
Induction Lamps Induction lamps use a contactless bulb and rely on electromagnetic 
fields to transfer power. This allows for the lamp to utilize more 
efficient materials that would otherwise react with metal electrodes. In 
addition, the lack of an electrode significantly extends lamp life while 
reducing lumen depreciation. 
Office 
Equipment 
Desktop and Laptop 
Computing Equipment 
ENERGY STAR labeled office equipment saves energy by powering down 
and "going to sleep" when not in use.  ENERGY STAR labeled computers 
automatically power down to 15 watts or less when not in use and may 
actually last longer than conventional products because they spend a 
large portion of time in a low‐power sleep mode.  ENERGY STAR labeled 
computers also generate less heat than conventional models. The 
ClimateSavers Initiative, made up of leading computer processor 
manufacturers, has stated a goal of reducing power consumption in 
active mode by 50% by integrating innovative power management into 
the chip design process. 
Office 
Equipment 
Monitors ENERGY STAR labeled office equipment saves energy by powering down 
and "going to sleep" when not in use.  ENERGY STAR labeled monitors 
automatically power down to 15 watts or less when not in use. 
Office 
Equipment 
Servers In addition to the "sleep" mode a reductions and the efficient 
processors being designed by members of the ClimateSavers Initiative, 
servers have additional energy‐saving opportunities through 
"virtualization" and other architecture solutions that involve optimal 
matching of computation tasks to hardware requirements 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 760 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-11
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Office 
Equipment 
Printers/Copiers/ Fax/ POS 
Terminals 
ENERGY STAR labeled office equipment saves energy by powering down 
and "going to sleep" when not in use.  ENERGY STAR labeled copiers are 
equipped with a feature that allows them to automatically turn off after 
a period of inactivity, reducing a copier's annual electricity costs by over 
60%.  High‐speed copiers that include a duplexing unit that is set to 
automatically make double‐sided copies can reduce paper costs and 
help to save trees. 
Office 
Equipment 
ENERGY STAR Power 
Supply 
Power supplies with an efficient ac‐dc or ac‐ac conversion process can 
obtain the ENERGY STAR label. These devices can be used to power 
computers, phones, and other office equipment.  
Refrigeration Walk‐in Refrigeration 
Systems 
Standard compressors typically operate at approximately 65% 
efficiency. High‐efficiency models are available that can improve 
compressor efficiency by 15%. 
Refrigeration Glass Door and Solid Door 
Refrigeration Units (Reach‐
in /Open Display 
Case/Vending Machine) 

Door Gasket Replacement 

High Efficiency Case 
Lighting 
In addition to walk‐in, "cold‐storage" refrigeration, a significant amount 
of energy in the commercial sector can be attributed to "reach‐in" units. 
These stand‐alone appliances can range from a residential‐style 
refrigerator/freezer unit in an office kitchen or the breakroom of a retail 
store to the refrigerated display cases in some grocery or convenience 
stores. As in the case of residential units, these refrigerators can be 
designed to perform at higher efficiency through a combination of 
compressor equipment upgrades, default temperature settings, and 
defrost patterns.  
Other measures for these units are replacing aging door gaskets that no 
longer adequately seal the case, and replacing inefficient display lights 
with CFL or LED systems to reduce internal heat gains in the cases.  
Refrigeration Open Display Case Glass doors can be used to enclose multi‐deck display cases for 
refrigerated items in supermarkets.  In addition, more efficient units are 
designed to perform at higher efficiency through a combination of 
compressor equipment upgrades, default temperature settings, and 
defrost patterns. 
Refrigeration Anti‐Sweat Heater/ Auto 
Door Closer Controls 
Anti‐sweat heaters are used in virtually all low‐temperature display 
cases and many medium‐temperature cases to control humidity and 
prevent the condensation of water vapor on the sides and doors and on 
the products contained in the cases.  Typically, these heaters stay on all 
the time, even though they only need to be on about half the time. 
Anti‐sweat heater controls can come in the form of humidity sensors or 
time clocks. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 761 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-12 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Refrigeration Floating Head Pressure 
Controls 
Floating head pressure control allows the pressure in the condenser to 
"float" with ambient temperatures. This method reduces refrigeration 
compression ratios, improves system efficiency and extends the 
compressor life. The greatest savings with a floating head pressure 
approach occurs when the ambient temperatures are low, such as in 
the winter season.  Floating head pressure control is most practical for 
new installations. However, retrofits installation can be completed with 
some existing refrigeration systems. Installing floating head pressure 
control increases the capacity of the compressor when temperatures 
are low, which may lead to short cycling. 
Refrigeration Bare Suction Lines Insulating bare suction lines reduces heat  
Refrigeration Night Covers Night covers can be used on open refrigeration cases when a facility is 
closed or few customers are in the store.  
Refrigeration Strip Curtain Strip curtains at the entrances to large walk‐in coolers or freezers, such 
as those used in supermarkets, reduce air transfer between the 
refrigerated space and the surrounding space.  
Refrigeration Icemakers In certain building types (restaurant, hotel), the production of ice is a 
significant usage of electricity. By optimizing the timing of ice 
production and the type of output to the specific application, icemakers 
are assumed to deliver electricity savings. 
Refrigeration Vending Machine ‐ 
Controller 
Cold beverage vending machines usually operate 24 hours a day 
regardless of whether the surrounding area is occupied or not.  The 
result is that the vending machine consumes energy unnecessarily, 
because it will operate all night to keep the beverage cold even when 
there would be no customer until the next morning.  A vending machine 
controller can reduce energy consumption without compromising the 
temperature of the vended product. The controller uses an infrared 
sensor to monitor the surrounding area’s occupancy and will power 
down the vending machine when the area is unoccupied.  It will also 
monitor the room’s temperature and will re ‐power the machine at one 
to three hour intervals independent of occupancy to ensure that the 
product stays cold.   
Food Service Kitchen Equipment Commercial cooking and food preparation equipment represent a 
significant contribution to energy consumption in restaurants and other 
food service applications. By replacing old units with efficient ones, this 
energy consumption can be greatly reduced. These measures include 
fryers, commercial ovens, dishwashers, hot food containers and 
miscellaneous other food preparation equipment. Savings range 
between 15 and 65%, depending on the specific unit being replaced. 
Cooling, Space 
Heating, 
Interior 
Lighting, Food 
Preparation, 
Refrigeration 
Custom Measures Custom measures were included in the CPA analysis to serve as a “catch 
all” for measures for which costs and savings are not easily quantified 
and that could be part of a program such as Avista’s existing Site‐
Specific incentive program. Costs and energy savings were assumed 
such that the measures passed the economic screen.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 762 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-13
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Miscellaneous Non‐HVAC motor Because the Small/Medium Commercial and Large Commercial 
segments include some industrial customers, the CPA analysis included 
equipment upgrades for non‐HVAC motors. This equipment measure 
also incorporates improvements for vertical transport. Premium 
efficiency motors reduce the amount of lost energy going into heat 
rather than power.  Since less heat is generated, less energy is needed 
to cool the motor with a fan.  Therefore, the initial cost of energy 
efficient motors is generally higher than for standard motors. However 
their life‐cycle costs can make them far more economical because of 
savings they generate in operating expense. 
Premium efficiency motors can provide savings of 0.5% to 3% over 
standard motors.  The savings results from the fact that energy efficient 
motors run cooler than their standard counterparts, resulting in an 
increase in the life of the motor insulation and bearing.  In general, an 
efficient motor is a more reliable motor because there are fewer 
winding failures, longer periods between needed maintenance, and 
fewer forced outages.  For example, using copper instead of aluminum 
in the windings, and increasing conductor cross‐sectional area, lowers a 
motor’s I2R losses. 
Miscellaneous Pumps – Variable Speed 
Control 
The part‐load efficiency of chilled and hot water loop pumps can be 
improved substantially by varying the speed of the motor drive 
according to the building demand for heating or cooling. There is also a 
reduction in piping losses associated with this measure that has a major 
impact on the heating loads and energy use for a building. However, 
pump speeds can generally only be reduced to a minimum specified 
rate, because chillers, boilers, and the control valves may require a 
minimum flow rate to operate. There are two major types of variable 
speed controls:  mechanical and electronic.  An additional benefit of 
variable‐speed drives is the ability to start and stop the motor gradually, 
thus extending the life of the motor and associated machinery. This 
analysis assumes that electronic variable speed controls are installed. 
Miscellaneous Laundry – High Efficiency  
Clothes Washer 
High efficiency clothes washers use designs that require less water.  
These machines use sensors to match the hot water needs to the load, 
preventing energy waste. There are two designs:  top‐loading and front‐
loading. Further energy and water savings can be achieved through 
advanced technologies such as inverter‐drive or combination washer‐
dryer units. 
Miscellaneous ENERGY STAR Water Cooler An ENERGY STAR water cooler has more insulation and improved 
chilling mechanisms, resulting in about half the energy use of a standard 
cooler. 
Miscellaneous Industrial Process 
Improvements  
Because the Avista C&I sector segmentation was based on Avista’s rate 
classes, the commercial building segments include a small percentage 
or industrial business types. This measure was included to account for 
energy efficiency potential that could be achieved through various 
process improvements at these customers.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 763 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-14 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Machine Drive. Motors, Premium 
Efficiency 
Premium efficiency motors reduce the amount of lost energy going into 
heat rather than power.  Since less heat is generated, less energy is 
needed to cool the motor with a fan.  Therefore, the initial cost of 
energy efficient motors is generally higher than for standard motors.  
However their life‐cycle costs can make them far more economical 
because of savings they generate in operating expense. 
Premium efficiency motors can provide savings of 0.5% to 3% over 
standard motors.  The savings results from the fact that energy efficient 
motors run cooler than their standard counterparts, resulting in an 
increase in the life of the motor insulation and bearing.  In general, an 
efficient motor is a more reliable motor because there are fewer 
winding failures, longer periods between needed maintenance, and 
fewer forced outages.  For example, using copper instead of aluminum 
in the windings, and increasing conductor cross‐sectional area, lowers a 
motor’s I2R losses. 
This analysis assumes 75% loading factor (for peak efficiency) for 1800 
rpm motor.  Hours of operation vary depending on horsepower size. In 
addition, improved drives and controls are assumed to be implemented 
along with the motors, resulting in savings as high as 10% of annual 
energy consumption 
Machine Drive Motors – Variable 
Frequency Drive 
In addition to energy savings, VFDs increase motor and system life and 
provide a greater degree of control over the motor system. Especially 
for motor systems handling fluids, VFDs can efficiently respond to 
changing operating conditions.  
Machine Drive Magnetic Adjustable 
Speed Drive 
To allow for adjustable speed operation, this technology uses magnetic 
induction to couple a drive to its load. Varying the magnetic slip within 
the coupling controls the speed of the output shaft.  Magnetic drives 
perform best at the upper end of the speed range due to the energy 
consumed by the slip. Unlike traditional ASDs, magnetically coupled 
ASDs create no power distortion on the electrical system. However, 
magnetically coupled ASD efficiency is best when power needs are 
greatest. VFDs may show greater efficiency when the average load 
speed is below 90% of the motor speed, however this occurs when 
power demands are reduced. 
Machine Drive Compressed Air – System 
Controls, Optimization and 
Improvements, 
Maintenance 
Controls for compressed air systems can shift load from two partially 
loaded compressors to one compressor in order to maximize 
compression efficiency and may also involve the addition of VFDs. 
Improvements include installing high‐efficiency motors. Maintenance 
includes fixing air leaks and replacing air filters. 
Machine Drive Fan Systems – Controls, 
Optimization and 
Maintenance 
Certain practices require a consistent flow rate, such as indoor air 
quality and clean room ventilation. To achieve this, fan flow controls 
can be used to maintain precise volume flow control ensuring a 
constant air delivery even on fluctuating pressure conditions. This is 
done through programmable circuitry to electronically control fan 
motor speed. Motors can be configured to accept a signal from a 
controller that would vary the flow rate in direct proportion to the 
signal. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 764 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-15
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Machine Drive Pumping Systems – 
Controls, Optimization and 
Maintenance 
Pumping systems optimization includes installing VFDs, correctly 
resizing the motors, and installing timers and automated on‐off 
controls. Maintenance includes repairing diaphragms and fixing piping 
leaks. 
Process Process 
Cooling/Refrigeration 
Because of the customized nature of industrial cooling and refrigeration 
applications, a variety of opportunities are summarized as a general 
improvement in cooling and cold storage equipment. Costs and savings 
were developed using average values for this group of measures from 
the Sixth Plan industrial supply curve workbooks. 
Process Process Heating Because of the customized nature of industrial heating applications, a 
variety of opportunities are summarized as a general improvement in 
process heating equipment, such as arc furnaces. Costs and savings 
were developed using average values for this group of measures from 
the Sixth Plan industrial supply curve workbooks. 
Process Electrochemical Process Because of the customized nature of industrial electrochemical 
applications, a variety of opportunities are summarized as a general 
improvement in equipment and processes. Costs and savings were 
developed using average values for this group of measures from the 
Sixth Plan industrial supply curve workbooks. 
Process Refrigeration – System 
Controls, Maintenance, 
and Optimization 
Because refrigeration equipment performance degrades over time and 
control settings are frequently overridden, these measures account for 
savings that can be achieved through system maintenance and controls 
optimization. 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 765 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-16 www.gepllc.com

Table D-2 Energy Efficiency Equipment Data — Small/Medium Comm., Existing Vintage

Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 1.5 kw/ton, COP 2.3 ‐               $0.00 20 ‐            
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.29             $0.39 20 ‐            
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.35             $0.50 20 0.51          
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.73             $0.62 20 1.90          
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.77             $0.74 20 1.39          
Cooling Central Chiller Variable Refrigerant Flow 1.01             $11.57 20 0.07          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.22             $0.18 16 ‐            
Cooling RTU EER 11.2 0.43             $0.35 16 ‐            
Cooling RTU EER 12.0 0.57             $0.58 16 0.49          
Cooling RTU Ductless VRF 0.69             $5.12 16 0.05          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.09             $0.08 14 0.86          
Cooling PTAC EER 10.8 0.21             $0.16 14 1.00          
Cooling PTAC EER 11 0.25             $0.43 14 0.43          
Cooling PTAC EER 11.5 0.33             $0.96 14 0.27          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.57             $0.39 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.90             $1.18 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 1.20             $1.57 15 0.98          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.31             $1.96 15 0.68          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.46             $11.50 20 0.10          
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.30             $1.22 15 1.07          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.23             $0.09 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.94             $0.03 7 16.50       
Interior Lighting Interior Screw‐in LED 1.04             $1.18 12 0.84          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.30             ($0.07) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.30             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.91             $0.25 6 1.73          
Interior Lighting Linear Fluorescent T5 0.95             $0.43 6 1.06          
Interior Lighting Linear Fluorescent LED 0.99             $3.74 15 0.33          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.14             $0.05 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.60             $0.02 7 17.60       
Exterior Lighting Exterior Screw‐in Metal Halides 0.60             $0.05 4 3.16          
Exterior Lighting Exterior Screw‐in LED 0.66             $0.64 12 0.90          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.22             ($0.13) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.24             $0.55 9 0.37          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.01             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.04             $0.02 6 1.12          
Exterior Lighting Linear Fluorescent T5 0.04             $0.03 6 0.69          
Exterior Lighting Linear Fluorescent LED 0.05             $0.24 15 0.22          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.10             $0.02 15 5.23          
Water Heating Water Heater Geothermal Heat Pump 1.33             $3.53 15 0.43          
Water Heating Water Heater Solar 1.46             $3.03 15 0.55          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.03             $0.04 12 0.80          
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 766 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-17
An EnerNOC Company
Table D-2 Energy Efficiency Equipment Data — Small/Med. Comm., Existing Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Oven Efficient 0.39             $0.36 12 1.02          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.02             $0.05 12 0.36          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.40             $0.16 12 2.29          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.00             $0.03 12 0.07          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient ‐               $0.09 18 ‐            
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.16             $0.00 18 56.08       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.19             $0.02 18 9.87          
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.00             $0.00 18 0.24          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.11             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.20             $0.00 10 46.48       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.05             $0.00 12 12.76       
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.19             $0.00 4 23.04       
Office Equipment Desktop Computer Climate Savers 0.27             $0.36 4 0.23          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 7.34          
Office Equipment Laptop Computer Climate Savers 0.03             $0.12 4 0.08          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.12             $0.01 3 2.14          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.22             $0.00 4 19.68       
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.09             $0.04 6 0.98          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.03             $0.00 4 2.96          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.05             $0.06 15 0.95          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.06             $0.06 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.07             $0.11 15 0.72          
Miscellaneous Non‐HVAC Motor Premium (2015)0.08             $0.11 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 767 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-18 www.gepllc.com

Table D-3 Energy Efficiency Equipment Data — Large Commercial, Existing Vintage

Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 1.5 kw/ton, COP 2.3 ‐               $0.00 20 ‐            
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.30             $0.26 20 ‐            
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.36             $0.33 20 0.83          
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.75             $0.41 20 3.11          
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.79             $0.49 20 2.28          
Cooling Central Chiller Variable Refrigerant Flow 1.04             $7.63 20 0.11          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.22             $0.13 16 ‐            
Cooling RTU EER 11.2 0.45             $0.25 16 ‐            
Cooling RTU EER 12.0 0.59             $0.41 16 0.75          
Cooling RTU Ductless VRF 0.72             $3.67 16 0.07          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.09             $0.09 14 0.86          
Cooling PTAC EER 10.8 0.21             $0.17 14 1.00          
Cooling PTAC EER 11 0.25             $0.46 14 0.43          
Cooling PTAC EER 11.5 0.34             $1.03 14 0.27          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.46             $0.18 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.73             $0.55 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 0.97             $0.73 15 1.85          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.07             $0.91 15 1.28          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.19             $5.35 20 0.19          
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.03             $1.22 15 0.86          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.19             $0.08 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.78             $0.03 7 14.13       
Interior Lighting Interior Screw‐in LED 0.87             $1.11 12 0.72          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.31             ($0.08) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.30             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.89             $0.25 6 1.66          
Interior Lighting Linear Fluorescent T5 0.92             $0.42 6 1.02          
Interior Lighting Linear Fluorescent LED 0.97             $3.67 15 0.32          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.08             $0.01 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.34             $0.01 7 34.02       
Exterior Lighting Exterior Screw‐in Metal Halides 0.34             $0.02 4 6.10          
Exterior Lighting Exterior Screw‐in LED 0.38             $0.19 12 1.73          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.19             ($0.11) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.20             $0.45 9 0.37          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.01             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.04             $0.02 6 1.18          
Exterior Lighting Linear Fluorescent T5 0.04             $0.03 6 0.72          
Exterior Lighting Linear Fluorescent LED 0.05             $0.24 15 0.23          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.12             $0.02 15 5.71          
Water Heating Water Heater Geothermal Heat Pump 1.54             $3.53 15 0.46          
Water Heating Water Heater Solar 1.69             $3.03 15 0.60          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.07             $0.02 12 3.52          
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 768 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-19
An EnerNOC Company
Table D-3 Energy Efficiency Equipment Data — Large Commercial, Existing Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Oven Efficient 0.75             $0.46 12 1.43          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.07             $0.10 12 0.58          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.35             $0.30 12 0.99          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.01             $0.03 12 0.24          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient 0.15             $1.26 18 0.13          
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.13             $0.01 18 24.96       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.30             $0.08 18 4.39          
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.00             $0.04 18 0.16          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.15             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.23             $0.00 10 20.70       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.11             $0.02 12 5.62          
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.35             $0.00 4 47.46       
Office Equipment Desktop Computer Climate Savers 0.50             $0.32 4 0.46          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 15.12       
Office Equipment Laptop Computer Climate Savers 0.04             $0.06 4 0.17          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.13             $0.01 3 4.41          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.19             $0.01 4 9.14          
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.08             $0.02 6 2.02          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.01             $0.00 4 2.94          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.06             $0.06 15 0.92          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.06             $0.06 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.08             $0.13 15 0.69          
Miscellaneous Non‐HVAC Motor Premium (2015)0.09             $0.13 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 769 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-20 www.gepllc.com

Table D-4 Energy Efficiency Equipment Data — Extra Large Commercial, Existing Vintage

Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 0.75 kw/ton, COP 4.7 ‐               $0.00 20 ‐            
Cooling Central Chiller 0.60 kw/ton, COP 5.9 0.43             $0.09 20 ‐            
Cooling Central Chiller 0.58 kw/ton, COP 6.1 0.49             $0.18 20 0.66          
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 0.57             $0.25 20 0.91          
Cooling Central Chiller 0.51 kw/ton, COP 6.9 0.69             $0.44 20 0.78          
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 0.72             $0.53 20 0.69          
Cooling Central Chiller 0.48 kw/ton, COP 7.3 0.77             $0.62 20 0.68          
Cooling Central Chiller Variable Refrigerant Flow 1.00             $10.92 20 0.05          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.20             $0.24 16 ‐            
Cooling RTU EER 11.2 0.41             $0.45 16 ‐            
Cooling RTU EER 12.0 0.53             $0.75 16 0.37          
Cooling RTU Ductless VRF 0.65             $6.64 16 0.03          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.08             $0.06 14 1.09          
Cooling PTAC EER 10.8 0.19             $0.12 14 1.28          
Cooling PTAC EER 11 0.22             $0.32 14 0.55          
Cooling PTAC EER 11.5 0.30             $0.71 14 0.34          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.50             $0.24 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.79             $0.73 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 1.06             $0.97 15 1.34          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.16             $1.21 15 0.93          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.29             $7.10 20 0.14          
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.21             $1.22 15 1.01          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.30             $0.14 4 ‐            
Interior Lighting Interior Screw‐in CFL 1.25             $0.06 7 13.22       
Interior Lighting Interior Screw‐in LED 1.38             $1.90 12 0.67          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.13             ($0.05) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.20             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.59             $0.21 6 1.31          
Interior Lighting Linear Fluorescent T5 0.61             $0.35 6 0.80          
Interior Lighting Linear Fluorescent LED 0.64             $3.08 15 0.25          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.02             $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.10             $0.00 7 37.00       
Exterior Lighting Exterior Screw‐in Metal Halides 0.10             $0.00 4 6.64          
Exterior Lighting Exterior Screw‐in LED 0.11             $0.05 12 1.89          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.26             ($0.16) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.28             $0.64 9 0.37          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.00             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.01             $0.00 6 1.12          
Exterior Lighting Linear Fluorescent T5 0.01             $0.01 6 0.69          
Exterior Lighting Linear Fluorescent LED 0.01             $0.06 15 0.22          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.19             $0.02 15 9.79          
Water Heating Water Heater Geothermal Heat Pump 2.47             $3.53 15 0.80          
Water Heating Water Heater Solar 2.72             $3.03 15 1.02          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 770 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-21
An EnerNOC Company
Table D-4 Energy Efficiency Equipment Data — Extra Large Commercial, Existing Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Fryer Efficient 0.03             $0.00 12 6.02          
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Food Preparation Oven Efficient 0.85             $0.38 12 2.11          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.03             $0.04 12 0.57          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.17             $0.22 12 0.73          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.00             $0.03 12 0.15          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient 0.06             $0.05 18 1.42          
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.04             $0.00 18 78.11       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.27             $0.02 18 12.81       
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.01             $0.03 18 0.34          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.16             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.24             $0.00 10 68.21       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.05             $0.00 12 17.60       
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.25             $0.00 4 32.37       
Office Equipment Desktop Computer Climate Savers 0.35             $0.33 4 0.32          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 10.31       
Office Equipment Laptop Computer Climate Savers 0.04             $0.10 4 0.12          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.06             $0.00 3 3.01          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.11             $0.01 4 6.80          
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.02             $0.01 6 1.38          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.00             $0.00 4 2.01          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.03             $0.03 15 1.02          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.04             $0.03 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.05             $0.07 15 0.76          
Miscellaneous Non‐HVAC Motor Premium (2015)0.05             $0.07 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 771 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-22 www.gepllc.com

Table D-5 Energy Efficiency Equipment Data — Extra Large Industrial, Existing Vintage

  Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 0.75 kw/ton, COP 4.7 ‐               $0.00 20 ‐            
Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.61             $0.33 20 ‐            
Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.82             $0.66 20 0.68          
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.15             $0.93 20 0.94          
Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.58             $1.59 20 0.80          
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.68             $1.92 20 0.71          
Cooling Central Chiller 0.48 kw/ton, COP 7.3 2.90             $2.25 20 0.70          
Cooling Central Chiller Variable Refrigerant Flow 3.74             $39.62 20 0.06          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.56             $0.39 16 ‐            
Cooling RTU EER 11.2 1.12             $0.73 16 ‐            
Cooling RTU EER 12.0 1.47             $1.22 16 0.62          
Cooling RTU Ductless VRF 1.79             $10.83 16 0.06          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.20             $0.06 14 2.79          
Cooling PTAC EER 10.8 0.47             $0.11 14 3.27          
Cooling PTAC EER 11 0.55             $0.31 14 1.41          
Cooling PTAC EER 11.5 0.75             $0.69 14 0.87          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 1.07             $0.92 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 1.69             $2.75 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 2.25             $3.66 15 0.75          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 2.47             $4.58 15 0.52          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 2.74             $26.86 20 0.08          
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 7.66             $1.22 15 6.38          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.09             $0.04 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.38             $0.02 7 14.80       
Interior Lighting Interior Screw‐in LED 0.42             $0.52 12 0.75          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.46             ($0.14) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.10             ($0.01) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.31             $0.08 6 1.73          
Interior Lighting Linear Fluorescent T5 0.32             $0.14 6 1.06          
Interior Lighting Linear Fluorescent LED 0.33             $1.21 15 0.33          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.01             $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.02             $0.00 7 15.02       
Exterior Lighting Exterior Screw‐in Metal Halides 0.02             $0.00 4 2.69          
Exterior Lighting Exterior Screw‐in LED 0.03             $0.03 12 0.77          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.07             ($0.04) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.08             $0.18 9 0.37          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.00             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.00             $0.00 6 1.16          
Exterior Lighting Linear Fluorescent T5 0.00             $0.00 6 0.71          
Exterior Lighting Linear Fluorescent LED 0.00             $0.01 15 0.22          
Process Process Cooling/Refrigera Standard ‐               $0.00 10 ‐            
Process Process Cooling/Refrigera Efficient 18.88           $5.59 10 2.49          
Process Process Heating Standard ‐               $0.00 10 ‐            
Process Process Heating Efficient 6.18             $0.57 10 7.97          
Process Electrochemical Process Standard ‐               $0.00 10 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 772 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-23
An EnerNOC Company
Table D-5 Energy Efficiency Equipment Data — Extra Large Industrial, Existing Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Process Electrochemical Process Efficient 13.16           $2.64 10 3.67          
Machine Drive Less than 5 HP Standard ‐               $0.00 10 ‐            
Machine Drive Less than 5 HP High Efficiency 0.05             $0.02 10 2.08          
Machine Drive Less than 5 HP Standard (2015)0.07             $0.00 10 ‐            
Machine Drive Less than 5 HP Premium 0.07             $0.03 10 1.66          
Machine Drive Less than 5 HP High Efficiency (2015)0.11             $0.02 10 ‐            
Machine Drive Less than 5 HP Premium (2015)0.14             $0.03 10 ‐            
Machine Drive 5‐24 HP Standard ‐               $0.00 10 ‐            
Machine Drive 5‐24 HP High 0.11             $0.02 10 5.09          
Machine Drive 5‐24 HP Premium 0.18             $0.03 10 4.07          
Machine Drive 25‐99 HP Standard ‐               $0.00 10 ‐            
Machine Drive 25‐99 HP High 0.31             $0.02 10 13.72       
Machine Drive 25‐99 HP Premium 0.49             $0.03 10 10.97       
Machine Drive 100‐249 HP Standard ‐               $0.00 10 ‐            
Machine Drive 100‐249 HP High 0.12             $0.02 10 5.17          
Machine Drive 100‐249 HP Premium 0.15             $0.03 10 3.44          
Machine Drive 250‐499 HP Standard ‐               $0.00 10 ‐            
Machine Drive 250‐499 HP High 0.35             $0.02 10 15.66       
Machine Drive 250‐499 HP Premium 0.47             $0.03 10 10.44       
Machine Drive 500 and more HP Standard ‐               $0.00 10 ‐            
Machine Drive 500 and more HP High 0.59             $0.02 10 26.28       
Machine Drive 500 and more HP Premium 0.78             $0.03 10 17.52       
Miscellaneous Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 773 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-24 www.gepllc.com

Table D-6 Energy Efficiency Equipment Data — Small/Medium Commercial, New Vintage

  Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 1.5 kw/ton, COP 2.3 ‐               $0.00 20 ‐            
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.29             $0.39 20 ‐            
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.35             $0.50 20 0.51          
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.73             $0.62 20 1.90          
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.77             $0.74 20 1.39          
Cooling Central Chiller Variable Refrigerant Flow 1.01             $11.57 20 0.07          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.22             $0.18 16 ‐            
Cooling RTU EER 11.2 0.43             $0.35 16 ‐            
Cooling RTU EER 12.0 0.57             $0.58 16 0.49          
Cooling RTU Ductless VRF 0.69             $5.12 16 0.05          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.09             $0.08 14 0.86          
Cooling PTAC EER 10.8 0.21             $0.16 14 1.00          
Cooling PTAC EER 11 0.25             $0.43 14 0.43          
Cooling PTAC EER 11.5 0.33             $0.96 14 0.27          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.57             $0.39 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.90             $1.18 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 1.20             $1.57 15 0.98          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.31             $1.96 15 0.68          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.46             $11.50 20 0.10          
Combined Heating/Cooling Heat Pump Geothermal Heat Pump 1.75             $20.69 20 ‐            
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.64             $1.22 15 1.35          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.20             $0.09 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.85             $0.03 7 14.85       
Interior Lighting Interior Screw‐in LED 0.93             $1.18 12 0.76          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.27             ($0.07) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.27             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.82             $0.25 6 1.56          
Interior Lighting Linear Fluorescent T5 0.85             $0.43 6 0.95          
Interior Lighting Linear Fluorescent LED 0.89             $3.74 15 0.30          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.13             $0.05 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.54             $0.02 7 15.84       
Exterior Lighting Exterior Screw‐in Metal Halides 0.54             $0.05 4 2.84          
Exterior Lighting Exterior Screw‐in LED 0.60             $0.64 12 0.81          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.20             ($0.13) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.22             $0.55 9 0.33          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.01             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.04             $0.02 6 1.01          
Exterior Lighting Linear Fluorescent T5 0.04             $0.03 6 0.62          
Exterior Lighting Linear Fluorescent LED 0.04             $0.24 15 0.20          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.10             $0.02 15 5.23          
Water Heating Water Heater Geothermal Heat Pump 1.33             $3.53 15 0.43          
Water Heating Water Heater Solar 1.46             $3.03 15 0.55          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.03             $0.04 12 0.80          
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 774 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-25
An EnerNOC Company
Table D-6 Energy Efficiency Equipment Data — Small/Medium Commercial, New Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Food Preparation Oven Efficient 0.39             $0.36 12 1.02          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.02             $0.05 12 0.36          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.40             $0.16 12 2.29          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.00             $0.03 12 0.07          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient ‐               $0.09 18 ‐            
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.16             $0.00 18 56.08       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.19             $0.02 18 9.87          
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.00             $0.00 18 0.24          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.11             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.20             $0.00 10 46.48       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.05             $0.00 12 12.76       
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.19             $0.00 4 23.04       
Office Equipment Desktop Computer Climate Savers 0.27             $0.36 4 0.23          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 7.34          
Office Equipment Laptop Computer Climate Savers 0.03             $0.12 4 0.08          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.12             $0.01 3 2.14          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.22             $0.00 4 19.68       
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.09             $0.04 6 0.98          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.03             $0.00 4 2.96          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.05             $0.06 15 0.95          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.06             $0.06 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.07             $0.11 15 0.72          
Miscellaneous Non‐HVAC Motor Premium (2015)0.08             $0.11 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 775 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-26 www.gepllc.com

Table D-7 Energy Efficiency Equipment Data — Large Commercial, New Vintage

Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 1.5 kw/ton, COP 2.3 ‐               $0.00 20 ‐            
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.32             $0.24 20 ‐            
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.39             $0.31 20 0.97          
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.80             $0.38 20 3.62          
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.85             $0.45 20 2.66          
Cooling Central Chiller Variable Refrigerant Flow 1.12             $7.06 20 0.12          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.22             $0.13 16 ‐            
Cooling RTU EER 11.2 0.45             $0.25 16 ‐            
Cooling RTU EER 12.0 0.59             $0.41 16 0.75          
Cooling RTU Ductless VRF 0.72             $3.67 16 0.07          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.09             $0.09 14 0.86          
Cooling PTAC EER 10.8 0.21             $0.17 14 1.00          
Cooling PTAC EER 11 0.25             $0.46 14 0.43          
Cooling PTAC EER 11.5 0.34             $1.03 14 0.27          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.46             $0.18 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.73             $0.55 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 0.97             $0.73 15 1.85          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.07             $0.91 15 1.28          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.19             $5.35 20 0.19          
Combined Heating/Cooling Heat Pump Geothermal Heat Pump 1.42             $9.62 20 ‐            
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.30             $1.22 15 1.09          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.17             $0.08 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.71             $0.03 7 12.72       
Interior Lighting Interior Screw‐in LED 0.78             $1.11 12 0.65          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.28             ($0.08) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.27             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.80             $0.25 6 1.49          
Interior Lighting Linear Fluorescent T5 0.83             $0.42 6 0.92          
Interior Lighting Linear Fluorescent LED 0.87             $3.67 15 0.29          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.07             $0.01 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.31             $0.01 7 30.62       
Exterior Lighting Exterior Screw‐in Metal Halides 0.31             $0.02 4 5.49          
Exterior Lighting Exterior Screw‐in LED 0.34             $0.19 12 1.56          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.17             ($0.11) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.18             $0.45 9 0.34          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.01             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.04             $0.02 6 1.06          
Exterior Lighting Linear Fluorescent T5 0.04             $0.03 6 0.65          
Exterior Lighting Linear Fluorescent LED 0.04             $0.24 15 0.20          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.12             $0.02 15 5.71          
Water Heating Water Heater Geothermal Heat Pump 1.54             $3.53 15 0.46          
Water Heating Water Heater Solar 1.69             $3.03 15 0.60          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.07             $0.02 12 3.52          
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 776 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-27
An EnerNOC Company
Table D-7 Energy Efficiency Equipment Data — Large Commercial, New Vintage (Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Food Preparation Oven Efficient 0.75             $0.46 12 1.43          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.07             $0.10 12 0.58          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.35             $0.30 12 0.99          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.01             $0.03 12 0.24          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient 0.15             $1.26 18 0.13          
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.13             $0.01 18 24.96       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.30             $0.08 18 4.39          
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.00             $0.04 18 0.16          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.15             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.23             $0.00 10 20.70       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.11             $0.02 12 5.62          
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.35             $0.00 4 47.46       
Office Equipment Desktop Computer Climate Savers 0.50             $0.32 4 0.46          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 15.12       
Office Equipment Laptop Computer Climate Savers 0.04             $0.06 4 0.17          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.13             $0.01 3 4.41          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.19             $0.01 4 9.14          
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.08             $0.02 6 2.02          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.01             $0.00 4 2.94          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.06             $0.06 15 0.92          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.06             $0.06 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.08             $0.13 15 0.69          
Miscellaneous Non‐HVAC Motor Premium (2015)0.09             $0.13 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 777 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-28 www.gepllc.com

Table D-8 Energy Efficiency Equipment Data — Extra Large Commercial, New Vintage

  Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 0.75 kw/ton, COP 4.7 ‐               $0.00 20 ‐            
Cooling Central Chiller 0.60 kw/ton, COP 5.9 0.43             $0.09 20 ‐            
Cooling Central Chiller 0.58 kw/ton, COP 6.1 0.49             $0.18 20 0.66          
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 0.57             $0.25 20 0.91          
Cooling Central Chiller 0.51 kw/ton, COP 6.9 0.69             $0.44 20 0.78          
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 0.72             $0.53 20 0.69          
Cooling Central Chiller 0.48 kw/ton, COP 7.3 0.77             $0.62 20 0.68          
Cooling Central Chiller Variable Refrigerant Flow 1.00             $10.92 20 0.05          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.20             $0.24 16 ‐            
Cooling RTU EER 11.2 0.41             $0.44 16 ‐            
Cooling RTU EER 12.0 0.53             $0.73 16 0.37          
Cooling RTU Ductless VRF 0.65             $6.51 16 0.04          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.08             $0.06 14 1.09          
Cooling PTAC EER 10.8 0.19             $0.12 14 1.28          
Cooling PTAC EER 11 0.22             $0.32 14 0.55          
Cooling PTAC EER 11.5 0.30             $0.71 14 0.34          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.50             $0.24 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.79             $0.73 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 1.06             $0.97 15 1.34          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.16             $1.21 15 0.93          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.29             $7.10 20 0.14          
Combined Heating/Cooling Heat Pump Geothermal Heat Pump 1.55             $12.77 20 ‐            
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.52             $1.22 15 1.27          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.27             $0.14 4 ‐            
Interior Lighting Interior Screw‐in CFL 1.13             $0.06 7 11.90       
Interior Lighting Interior Screw‐in LED 1.24             $1.90 12 0.61          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.11             ($0.05) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.18             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.53             $0.21 6 1.18          
Interior Lighting Linear Fluorescent T5 0.55             $0.35 6 0.72          
Interior Lighting Linear Fluorescent LED 0.58             $3.08 15 0.23          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.02             $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.09             $0.00 7 33.30       
Exterior Lighting Exterior Screw‐in Metal Halides 0.09             $0.00 4 5.97          
Exterior Lighting Exterior Screw‐in LED 0.10             $0.05 12 1.70          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.24             ($0.16) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.25             $0.64 9 0.33          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.00             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.01             $0.00 6 1.01          
Exterior Lighting Linear Fluorescent T5 0.01             $0.01 6 0.62          
Exterior Lighting Linear Fluorescent LED 0.01             $0.06 15 0.19          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.19             $0.02 15 9.79          
Water Heating Water Heater Geothermal Heat Pump 2.47             $3.53 15 0.80          
Water Heating Water Heater Solar 2.72             $3.03 15 1.02          
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 778 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-29
An EnerNOC Company
Table D-9 Energy Efficiency Equipment Data — Extra Large Commercial, New Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.03             $0.00 12 6.02          
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Food Preparation Oven Efficient 0.85             $0.38 12 2.11          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.03             $0.04 12 0.57          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.17             $0.22 12 0.73          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.00             $0.03 12 0.15          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient 0.06             $0.05 18 1.42          
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.04             $0.00 18 78.11       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.27             $0.02 18 13.75       
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.01             $0.03 18 0.34          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.16             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.24             $0.00 10 68.21       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.05             $0.00 12 17.60       
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.25             $0.00 4 32.37       
Office Equipment Desktop Computer Climate Savers 0.35             $0.33 4 0.32          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 10.31       
Office Equipment Laptop Computer Climate Savers 0.04             $0.10 4 0.12          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.06             $0.00 3 3.01          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.11             $0.01 4 6.80          
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.02             $0.01 6 1.38          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.00             $0.00 4 2.01          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.03             $0.03 15 1.02          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.04             $0.03 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.05             $0.07 15 0.76          
Miscellaneous Non‐HVAC Motor Premium (2015)0.05             $0.07 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 779 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-30 www.gepllc.com

Table D-9 Energy Efficiency Equipment Data — Extra Large Industrial, New Vintage

  Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 0.75 kw/ton, COP 4.7 ‐               $0.00 20 ‐            
Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.61             $0.33 20 ‐            
Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.82             $0.66 20 0.68          
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.15             $0.93 20 0.94          
Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.58             $1.59 20 0.80          
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.68             $1.92 20 0.71          
Cooling Central Chiller 0.48 kw/ton, COP 7.3 2.90             $2.25 20 0.70          
Cooling Central Chiller Variable Refrigerant Flow 3.74             $39.62 20 0.06          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.56             $0.39 16 ‐            
Cooling RTU EER 11.2 1.12             $0.74 16 ‐            
Cooling RTU EER 12.0 1.47             $1.23 16 0.62          
Cooling RTU Ductless VRF 1.79             $10.88 16 0.06          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.20             $0.06 14 2.79          
Cooling PTAC EER 10.8 0.47             $0.11 14 3.27          
Cooling PTAC EER 11 0.55             $0.31 14 1.41          
Cooling PTAC EER 11.5 0.75             $0.69 14 0.87          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 1.07             $0.92 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 1.69             $2.75 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 2.25             $3.66 15 0.75          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 2.47             $4.58 15 0.52          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 2.74             $26.86 20 0.08          
Combined Heating/Cooling Heat Pump Geothermal Heat Pump 3.29             $48.32 20 ‐            
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 9.66             $1.22 15 8.05          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.08             $0.04 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.34             $0.02 7 13.32       
Interior Lighting Interior Screw‐in LED 0.38             $0.52 12 0.68          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.41             ($0.14) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.09             ($0.01) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.28             $0.08 6 1.56          
Interior Lighting Linear Fluorescent T5 0.29             $0.14 6 0.96          
Interior Lighting Linear Fluorescent LED 0.30             $1.21 15 0.30          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.01             $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.02             $0.00 7 13.52       
Exterior Lighting Exterior Screw‐in Metal Halides 0.02             $0.00 4 2.42          
Exterior Lighting Exterior Screw‐in LED 0.02             $0.03 12 0.69          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.07             ($0.04) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.07             $0.18 9 0.33          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.00             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.00             $0.00 6 1.05          
Exterior Lighting Linear Fluorescent T5 0.00             $0.00 6 0.64          
Exterior Lighting Linear Fluorescent LED 0.00             $0.01 15 0.20          
Process Process Cooling/Refrigera Standard ‐               $0.00 10 ‐            
Process Process Cooling/Refrigera Efficient 18.88           $5.59 10 2.49          
Process Process Heating Standard ‐               $0.00 10 ‐            
Process Process Heating Efficient 6.18             $0.57 10 7.97          
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 780 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-31
An EnerNOC Company
Table D-9 Energy Efficiency Equipment Data — Extra Large Industrial, New Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Process Electrochemical Process Standard ‐               $0.00 10 ‐            
Process Electrochemical Process Efficient 13.16           $2.64 10 3.67          
Machine Drive Less than 5 HP Standard ‐               $0.00 10 ‐            
Machine Drive Less than 5 HP High Efficiency 0.05             $0.02 10 2.08          
Machine Drive Less than 5 HP Standard (2015)0.07             $0.00 10 ‐            
Machine Drive Less than 5 HP Premium 0.07             $0.03 10 1.66          
Machine Drive Less than 5 HP High Efficiency (2015)0.11             $0.02 10 ‐            
Machine Drive Less than 5 HP Premium (2015)0.14             $0.03 10 ‐            
Machine Drive 5‐24 HP Standard ‐               $0.00 10 ‐            
Machine Drive 5‐24 HP High 0.11             $0.02 10 5.09          
Machine Drive 5‐24 HP Premium 0.18             $0.03 10 4.07          
Machine Drive 25‐99 HP Standard ‐               $0.00 10 ‐            
Machine Drive 25‐99 HP High 0.31             $0.02 10 13.72       
Machine Drive 25‐99 HP Premium 0.49             $0.03 10 10.97       
Machine Drive 100‐249 HP Standard ‐               $0.00 10 ‐            
Machine Drive 100‐249 HP High 0.12             $0.02 10 5.17          
Machine Drive 100‐249 HP Premium 0.15             $0.03 10 3.44          
Machine Drive 250‐499 HP Standard ‐               $0.00 10 ‐            
Machine Drive 250‐499 HP High 0.35             $0.02 10 15.66       
Machine Drive 250‐499 HP Premium 0.47             $0.03 10 10.44       
Machine Drive 500 and more HP Standard ‐               $0.00 10 ‐            
Machine Drive 500 and more HP High 0.59             $0.02 10 26.28       
Machine Drive 500 and more HP Premium 0.78             $0.03 10 17.52       
Miscellaneous Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 781 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-32 www.gepllc.com

Table D-10 Energy Efficiency Measure Data — Small/Med. Comm., Existing Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 14% 90% $0.08 4 0.75
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.20
Chiller ‐ Chilled Water Reset Cooling 14% 0% 0% 0% $0.86 4 0.08
Chiller ‐ Chilled Water Variable‐Flow System Cooling 5% 0% 0% 0% $0.86 10 0.07
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 0% $0.90 20 0.70
Chiller ‐ VSD Cooling 27% 0% 0% 0% $1.17 20 0.48
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 0% 0% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 10% 0% 0% 0% $0.87 14 0.18
Cooling ‐ Economizer Installation Cooling 6% 0% 45% 49% $0.15 15 0.71
Heat Pump ‐ Maintenance Combined Heating/Cooling 7% 7% 10% 95% $0.03 4 5.00
Insulation ‐ Ducting Cooling 6% 0% 9% 50% $0.41 20 0.71
Insulation ‐ Ducting Space Heating 3% 1% 9% 50% $0.41 20 0.71
Repair and Sealing ‐ Ducting Cooling 2% 0% 5% 25% $0.38 15 0.45
Repair and Sealing ‐ Ducting Space Heating 2% 1% 5% 25% $0.38 15 0.45
Energy Management System Cooling 6% 0% 24% 75% $0.35 14 0.72
Energy Management System Space Heating 5% 3% 24% 75% $0.35 14 0.72
Energy Management System Interior Lighting 2% 1% 24% 75% $0.35 14 0.72
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 25% 13% 1% 15% $0.04 10 7.36
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.38
Fans ‐ Variable Speed Control Ventilation 15% 5% 8% 90% $0.20 10 0.89
Retrocommissioning ‐ HVAC Cooling 9% 0% 15% 90% $0.60 4 0.50
Retrocommissioning ‐ HVAC Space Heating 9% 6% 15% 90% $0.60 4 0.50
Retrocommissioning ‐ HVAC Ventilation 9% 6% 15% 90% $0.60 4 0.50
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 0% 34% $0.44 10 1.01
Thermostat ‐ Clock/Programmable Cooling 5% 0% 34% 50% $0.13 11 1.12
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 34% 50% $0.13 11 1.12
Insulation ‐ Ceiling Cooling 2% 0% 10% 18% $0.64 20 0.70
Insulation ‐ Ceiling Space Heating 17% 4% 10% 18% $0.64 20 0.70
Insulation ‐ Radiant Barrier Cooling 3% 0% 7% 13% $0.26 20 0.81
Insulation ‐ Radiant Barrier Space Heating 5% 2% 7% 13% $0.26 20 0.81
Roofs ‐ High Reflectivity Cooling 15% 0% 2% 95% $0.18 15 1.47
Windows ‐ High Efficiency Cooling 5% 0% 61% 75% $0.44 20 0.63
Windows ‐ High Efficiency Space Heating 3% 2% 61% 75% $0.44 20 0.63
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 81% 90% $0.65 8 0.34
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 1% 45% $0.50 8 0.90
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 2% 50% $0.11 8 1.36
Interior Fluorescent ‐ Delamp and Install Reflectors Interior Lighting 20% 10% 18% 25% $0.50 11 0.97
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.50 8 0.36
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.70 11 1.73
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 7% 45% $0.20 8 1.11
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.26
Interior Screw‐in ‐ Task Lighting Interior Lighting 7% 4% 25% 75% $0.24 5 0.09
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 9% 56% $0.20 8 0.56
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 8% 90% $0.01 9 4.28
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 46% 50% $0.28 15 0.37
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 0% $0.11 10 0.64
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 40% 50% $0.02 10 5.87
Water Heater ‐ Thermostat Setback Water Heating 4% 2% 5% 75% $0.11 10 0.47
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 0% $0.02 5 1.56
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 0% 75% $0.20 16 1.10
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 18% 38% $0.35 16 1.25
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.10
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.21
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 1.02
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.00
Retrocommissioning ‐ Comprehensive Cooling 12% 0% 40% 90% $0.70 4 0.71
Retrocommissioning ‐ Comprehensive Space Heating 12% 9% 40% 90% $0.70 4 0.71
Retrocommissioning ‐ Comprehensive Interior Lighting 12% 9% 40% 90% $0.70 4 0.71
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 61.20
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.09
LED Exit Lighting Interior Lighting 2% 2% 9% 86% $0.00 10 12.75
Retrocommissioning ‐ Lighting Interior Lighting 9% 6% 5% 90% $0.10 5 1.59
Retrocommissioning ‐ Lighting Exterior Lighting 9% 6% 5% 90% $0.10 5 1.59
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.00
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.37
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 8.10
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 36.95
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 0% 0% $0.14 8 0.33
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.95
Industrial Process Improvements Miscellaneous 10% 8% 0% 23% $0.52 10 1.16
Custom Measures Cooling 10% 0% 10% 45% $1.50 15 0.59
Custom Measures Space Heating 10% 8% 10% 45% $1.50 15 0.59
Custom Measures Interior Lighting 10% 6% 10% 45% $1.50 15 0.59
Custom Measures Food Preparation 10% 7% 10% 45% $1.50 15 0.59
Custom Measures Refrigeration 10% 5% 10% 45% $1.50 15 0.59
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 19% $0.80 15 0.69
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $4.00 15 0.54
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 47% $8.04 15 1.08
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 782 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-33
An EnerNOC Company
Table D-11 Energy Efficiency Measure Data — Large Commercial, Existing Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 27% 90% $0.06 4 1.30
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.21
Chiller ‐ Chilled Water Reset Cooling 19% 0% 15% 75% $0.18 4 0.50
Chiller ‐ Chilled Water Variable‐Flow System Cooling 5% 0% 30% 34% $0.18 10 0.31
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 66% $0.90 20 0.64
Chiller ‐ VSD Cooling 32% 0% 15% 66% $1.17 20 0.52
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 15% 41% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 9% 0% 5% 75% $0.18 14 0.76
Cooling ‐ Economizer Installation Cooling 11% 0% 44% 49% $0.15 15 1.29
Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 10% 95% $0.06 4 3.04
Insulation ‐ Ducting Cooling 3% 0% 8% 50% $0.41 20 0.52
Insulation ‐ Ducting Space Heating 3% 1% 8% 50% $0.41 20 0.52
Repair and Sealing ‐ Ducting Cooling 2% 0% 5% 25% $0.38 15 0.43
Repair and Sealing ‐ Ducting Space Heating 2% 1% 5% 25% $0.38 15 0.43
Energy Management System Cooling 23% 0% 37% 90% $0.35 14 2.63
Energy Management System Space Heating 18% 12% 37% 90% $0.35 14 2.63
Energy Management System Interior Lighting 9% 6% 37% 90% $0.35 14 2.63
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 13% 7% 1% 11% $0.04 10 2.97
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.11
Fans ‐ Variable Speed Control Ventilation 15% 5% 2% 90% $0.20 10 0.71
Retrocommissioning ‐ HVAC Cooling 12% 0% 15% 90% $0.30 4 0.72
Retrocommissioning ‐ HVAC Space Heating 12% 9% 15% 90% $0.30 4 0.72
Retrocommissioning ‐ HVAC Ventilation 9% 6% 15% 90% $0.30 4 0.72
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 0% 34% $0.13 10 1.05
Thermostat ‐ Clock/Programmable Cooling 5% 0% 33% 50% $0.13 11 1.02
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 33% 50% $0.13 11 1.02
Insulation ‐ Ceiling Cooling 1% 0% 9% 30% $0.85 20 0.45
Insulation ‐ Ceiling Space Heating 12% 3% 9% 30% $0.85 20 0.45
Insulation ‐ Radiant Barrier Cooling 2% 0% 7% 13% $0.26 20 0.64
Insulation ‐ Radiant Barrier Space Heating 5% 2% 7% 13% $0.26 20 0.64
Roofs ‐ High Reflectivity Cooling 5% 0% 2% 75% $0.08 15 1.08
Windows ‐ High Efficiency Cooling 12% 0% 72% 75% $0.88 20 0.74
Windows ‐ High Efficiency Space Heating 11% 8% 72% 75% $0.88 20 0.74
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 86% 90% $0.65 8 0.34
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 1% 45% $0.45 8 0.96
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 2% 13% $0.29 8 0.42
Interior Fluorescent ‐ Delamp and Install Reflectors Interior Lighting 30% 15% 17% 38% $0.50 11 1.40
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.40 8 0.43
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.63 11 1.85
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 13% 45% $0.20 8 1.10
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.21
Interior Screw‐in ‐ Task Lighting Interior Lighting 10% 5% 10% 75% $0.24 5 0.13
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 9% 56% $0.20 8 0.55
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 3% 90% $0.03 9 1.62
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 0% $0.28 15 0.42
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 23% $0.11 10 0.70
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $0.04 10 3.28
Water Heater ‐ Thermostat Setback Water Heating 4% 2% 0% 0% $0.11 10 0.52
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 3% $0.04 5 0.88
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 0% 75% $0.20 16 0.58
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 38% 45% $0.35 16 0.95
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.65
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.37
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 0.65
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.96
Retrocommissioning ‐ Comprehensive Cooling 12% 0% 40% 90% $0.35 4 1.06
Retrocommissioning ‐ Comprehensive Space Heating 12% 9% 40% 90% $0.35 4 1.06
Retrocommissioning ‐ Comprehensive Interior Lighting 12% 9% 40% 90% $0.35 4 1.06
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 68.11
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.11
LED Exit Lighting Interior Lighting 2% 2% 9% 86% $0.00 10 12.29
Retrocommissioning ‐ Lighting Interior Lighting 9% 6% 5% 90% $0.05 5 3.07
Retrocommissioning ‐ Lighting Exterior Lighting 9% 6% 5% 90% $0.05 5 3.07
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.52
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.14
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 6.50
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 33.94
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 1% 2% $0.14 8 0.32
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.78
Industrial Process Improvements Miscellaneous 10% 8% 0% 5% $0.52 10 1.18
Custom Measures Cooling 10% 0% 10% 45% $0.90 15 0.99
Custom Measures Space Heating 10% 8% 10% 45% $0.90 15 0.99
Custom Measures Interior Lighting 10% 8% 10% 45% $0.90 15 0.99
Custom Measures Food Preparation 10% 8% 10% 45% $0.90 15 0.99
Custom Measures Refrigeration 10% 8% 10% 45% $0.90 15 0.99
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 28% $0.80 15 0.77
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 0% $4.00 15 0.59
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $6.00 15 1.04
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 783 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-34 www.gepllc.com

Table D-12 Energy Efficiency Measure Data — Extra Large Comm., Existing Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 47% 90% $0.06 4 1.15
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.19
Chiller ‐ Chilled Water Reset Cooling 15% 0% 30% 75% $0.09 4 0.79
Chiller ‐ Chilled Water Variable‐Flow System Cooling 8% 0% 30% 34% $0.09 10 1.00
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 75% $0.90 20 0.66
Chiller ‐ VSD Cooling 28% 0% 3% 75% $1.17 20 0.47
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 25% 37% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 9% 0% 0% 75% $0.09 14 1.49
Cooling ‐ Economizer Installation Cooling 11% 0% 73% 81% $0.15 15 1.20
Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 5% 95% $0.06 4 2.91
Insulation ‐ Ducting Cooling 8% 0% 2% 50% $0.41 20 0.77
Insulation ‐ Ducting Space Heating 3% 1% 2% 50% $0.41 20 0.77
Repair and Sealing ‐ Ducting Cooling 5% 0% 5% 25% $0.38 15 0.65
Repair and Sealing ‐ Ducting Space Heating 5% 3% 5% 25% $0.38 15 0.65
Energy Management System Cooling 12% 0% 80% 90% $0.35 14 1.21
Energy Management System Space Heating 9% 6% 80% 90% $0.35 14 1.21
Energy Management System Interior Lighting 5% 3% 80% 90% $0.35 14 1.21
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 13% 7% 1% 8% $0.04 10 3.46
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.30
Fans ‐ Variable Speed Control Ventilation 15% 5% 2% 90% $0.20 10 0.83
Retrocommissioning ‐ HVAC Cooling 12% 0% 15% 90% $0.20 4 1.00
Retrocommissioning ‐ HVAC Space Heating 12% 9% 15% 90% $0.20 4 1.00
Retrocommissioning ‐ HVAC Ventilation 9% 6% 15% 90% $0.20 4 1.00
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 1% 34% $0.44 10 1.01
Thermostat ‐ Clock/Programmable Cooling 3% 0% 25% 50% $0.13 11 0.69
Thermostat ‐ Clock/Programmable Space Heating 3% 1% 25% 50% $0.13 11 0.69
Insulation ‐ Ceiling Cooling 1% 0% 2% 9% $0.85 20 0.48
Insulation ‐ Ceiling Space Heating 12% 3% 2% 9% $0.85 20 0.48
Insulation ‐ Radiant Barrier Cooling 1% 0% 2% 13% $0.26 20 0.57
Insulation ‐ Radiant Barrier Space Heating 4% 2% 2% 13% $0.26 20 0.57
Roofs ‐ High Reflectivity Cooling 10% 0% 0% 95% $0.18 15 0.90
Windows ‐ High Efficiency Cooling 6% 0% 95% 100% $2.10 20 0.37
Windows ‐ High Efficiency Space Heating 2% 2% 95% 100% $2.10 20 0.37
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 78% 90% $0.65 8 0.26
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 3% 45% $0.40 8 0.72
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 2% 10% $0.29 8 0.45
Interior Fluorescent ‐ Delamp and Install Reflectors Interior Lighting 30% 15% 3% 25% $0.50 11 0.93
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.20 8 0.57
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.56 11 1.38
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 42% 45% $0.20 8 0.84
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.23
Interior Screw‐in ‐ Task Lighting Interior Lighting 10% 5% 5% 75% $0.24 5 0.18
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 12% 56% $0.20 8 0.42
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 2% 90% $0.03 9 2.66
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 0% $0.28 15 0.70
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 23% $0.11 10 1.19
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $0.04 10 5.48
Water Heater ‐ Thermostat Setback Water Heating 4% 0% 0% 0% $0.11 10 0.72
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 0% $0.04 5 1.45
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 10% 75% $0.20 16 0.02
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 10% 38% $0.35 16 0.34
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.13
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.28
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 0.29
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.18
Retrocommissioning ‐ Comprehensive Cooling 12% 0% 40% 90% $0.25 4 1.21
Retrocommissioning ‐ Comprehensive Space Heating 12% 9% 40% 90% $0.25 4 1.21
Retrocommissioning ‐ Comprehensive Interior Lighting 12% 9% 40% 90% $0.25 4 1.21
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 39.11
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.12
LED Exit Lighting Interior Lighting 2% 2% 9% 86% $0.00 10 18.34
Retrocommissioning ‐ Lighting Interior Lighting 9% 6% 5% 90% $0.05 5 2.54
Retrocommissioning ‐ Lighting Exterior Lighting 9% 6% 5% 90% $0.05 5 2.54
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.04
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.61
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 6.95
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 20.31
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 0% 0% $0.14 8 0.47
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.07
Industrial Process Improvements Miscellaneous 10% 8% 0% 0% $0.52 10 1.11
Custom Measures Cooling 10% 0% 10% 45% $0.67 15 1.09
Custom Measures Space Heating 10% 8% 10% 45% $0.67 15 1.09
Custom Measures Interior Lighting 10% 8% 10% 45% $0.67 15 1.09
Custom Measures Food Preparation 10% 8% 10% 45% $0.67 15 1.09
Custom Measures Refrigeration 10% 8% 10% 45% $0.67 15 1.09
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 41% $0.80 15 1.28
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 0% $4.00 15 1.00
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $4.00 15 1.66
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 784 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-35
An EnerNOC Company
Table D-13 Energy Efficiency Measure Data — Extra Large Industrial, Existing Vintage
  Note: Costs are per sq. ft.

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Refrigeration ‐ System Controls Process 11% 8% 5% 34% $0.40 10 18.09
Refrigeration ‐ System Maintenance Process 3% 2% 5% 34% $0.00 10 2,067.93
Refrigeration ‐ System Optimization Process 15% 11% 5% 34% $0.80 10 12.92
Motors ‐ Variable Frequency Drive Machine Drive 13% 9% 25% 38% $0.10 10 3.38
Motors ‐ Magnetic Adjustable Speed Drives Machine Drive 13% 9% 25% 38% $0.10 10 3.38
Compressed Air ‐ System Controls Machine Drive 9% 7% 5% 34% $0.40 10 0.59
Compressed Air ‐ System Optimization and Improvements Machine Drive 13% 9% 5% 34% $0.80 10 0.42
Compressed Air ‐ System Maintenance Machine Drive 3% 2% 5% 34% $0.20 10 0.34
Compressed Air ‐ Compressor Replacement Machine Drive 5% 4% 5% 34% $0.20 10 0.68
Fan System ‐ Controls Machine Drive 4% 3% 10% 38% $0.35 10 0.11
Fan System ‐ Controls Machine Drive 4% 3%10%38% $0.35 10 0.11
Fan System ‐ Optimization Machine Drive 6% 5% 10% 38% $0.70 10 0.08
Fan System ‐ Optimization Machine Drive 6% 5% 10% 38% $0.70 10 0.08
Fan System ‐ Maintenance Machine Drive 1% 1% 10% 38% $0.15 10 0.07
Fan System ‐ Maintenance Machine Drive 1% 1% 10% 38% $0.15 10 0.07
Pumping System ‐ Controls Machine Drive 5% 4% 5% 34% $0.38 12 0.43
Pumping System ‐ Optimization Machine Drive 13% 9% 5% 34% $0.75 12 0.54
Pumping System ‐ Maintenance Machine Drive 2% 1% 5% 34% $0.19 10 0.27
RTU ‐ Maintenance Cooling 14% 0% 22% 90% $0.06 4 3.18
Chiller ‐ Chilled Water Reset Cooling 14% 0% 30% 75% $0.09 4 2.69
Chiller ‐ Chilled Water Variable‐Flow System Cooling 5% 0% 30% 34% $0.20 10 1.05
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 67% $0.90 20 2.48
Chiller ‐ VSD Cooling 26% 0% 15% 67% $1.17 20 1.68
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 25% 50% $0.04 10 0.03
Chiller ‐ Condenser Water Temprature Reset Cooling 10% 0% 0% 75% $0.20 14 2.72
Cooling ‐ Economizer Installation Cooling 6% 0% 29% 34% $0.15 15 2.02
Heat Pump ‐ Maintenance Combined Heating/Cooling 7% 7% 2% 95% $0.03 4 8.67
Insulation ‐ Ducting Space Heating 6% 6% 12% 50% $0.41 20 1.01
Insulation ‐ Ducting Cooling 3% 0% 12% 50% $0.41 20 1.01
Repair and Sealing ‐ Ducting Cooling 2% 0% 5% 25% $0.38 15 0.63
Repair and Sealing ‐ Ducting Space Heating 2% 1% 5% 25% $0.38 15 0.63
Energy Management System Cooling 6% 0% 11% 90% $0.35 14 1.09
Energy Management System Space Heating 5% 3% 11% 90% $0.35 14 1.09
Energy Management System Interior Lighting 2% 1% 11% 90% $0.35 14 1.09
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 2% 90% $0.14 10 2.94
Fans ‐ Variable Speed Control Ventilation 15% 5% 3% 90% $0.20 10 5.29
Retrocommissioning ‐ HVAC Cooling 12% 0% 1% 70% $0.25 4 1.54
Retrocommissioning ‐ HVAC Space Heating 12% 9% 1% 70% $0.25 4 1.54
Retrocommissioning ‐ HVAC Ventilation 9% 6% 1% 70% $0.25 4 1.54
Pumps ‐ Variable Speed Control Machine Drive 5% 4% 0% 34% $0.44 10 0.31
Thermostat ‐ Clock/Programmable Cooling 5% 0% 59% 70% $0.13 11 2.11
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 59% 70% $0.13 11 2.11
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 84% 90% $0.65 8 0.17
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 2% 27% $0.08 8 0.46
Interior Fluorescent ‐ Delamp and Install Reflectors Interior Lighting 20% 10% 17% 38% $0.50 11 0.31
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 38% $0.20 11 1.95
LED Exit Lighting Interior Lighting 2% 2% 9% 86% $0.00 10 4.00
Retrocommissioning ‐ Lighting Interior Lighting 9% 6% 9% 70% $0.05 5 1.44
Retrocommissioning ‐ Lighting Exterior Lighting 9% 6% 9% 70% $0.05 5 1.44
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 15% 45% $0.20 8 0.55
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.07
Interior Screw‐in ‐ Task Lighting Interior Lighting 7% 4% 10% 75% $0.24 5 0.03
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 2% 56% $0.20 8 0.27
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 0.46
Custom Measures Cooling 10% 0% 10% 45% $1.60 15 1.63
Custom Measures Space Heating 10% 8% 10% 45% $1.60 15 1.63
Custom Measures Interior Lighting 10% 8% 10% 45% $1.60 15 1.63
Custom Measures Machine Drive 10% 8% 10% 45% $1.60 15 1.63
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $4.00 15 2.67
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 785 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-36 www.gepllc.com

Table D-14 Energy Efficiency Measure Data — Small/Medium Comm., New Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 14% 90% $0.08 4 0.82
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.18
Chiller ‐ Chilled Water Reset Cooling 11% 0% 0% 0% $0.86 4 0.06
Chiller ‐ Chilled Water Variable‐Flow System Cooling 4% 0% 0% 0% $0.86 10 0.05
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 0% $0.90 20 0.63
Chiller ‐ VSD Cooling 26% 0% 0% 0% $1.17 20 0.42
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 0% 0% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 8% 0% 0% 0% $0.87 14 0.13
Cooling ‐ Economizer Installation Cooling 6% 0% 45% 49% $0.15 15 0.65
Heat Pump ‐ Maintenance Combined Heating/Cooling 7% 7% 10% 95% $0.03 4 4.32
Insulation ‐ Ducting Cooling 5% 0% 9% 50% $0.41 20 0.64
Insulation ‐ Ducting Space Heating 3% 1% 9% 50% $0.41 20 0.64
Energy Management System Cooling 5% 0% 24% 75% $0.35 14 0.55
Energy Management System Space Heating 2% 1% 24% 75% $0.35 14 0.55
Energy Management System Interior Lighting 2% 1% 24% 75% $0.35 14 0.55
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 25% 13% 1% 15% $0.04 10 7.04
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.32
Fans ‐ Variable Speed Control Ventilation 15% 5% 8% 90% $0.20 10 0.85
Commissioning ‐ HVAC Cooling 5% 0% 40% 75% $0.90 25 0.33
Commissioning ‐ HVAC Space Heating 5% 4% 40% 75% $0.90 25 0.33
Commissioning ‐ HVAC Ventilation 5% 4% 40% 75% $0.90 25 0.33
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 5% 34% $0.44 10 1.01
Thermostat ‐ Clock/Programmable Cooling 5% 0% 34% 50% $0.13 11 1.06
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 34% 50% $0.13 11 1.06
Insulation ‐ Ceiling Cooling 1% 0% 10% 81% $0.16 20 1.60
Insulation ‐ Ceiling Space Heating 15% 4% 10% 81% $0.16 20 1.60
Insulation ‐ Radiant Barrier Cooling 2% 0% 7% 13% $0.26 20 0.76
Insulation ‐ Radiant Barrier Space Heating 6% 2% 7% 13% $0.26 20 0.76
Roofs ‐ High Reflectivity Cooling 7% 0% 5% 95% $0.09 15 1.25
Windows ‐ High Efficiency Cooling 5% 0% 61% 75% $0.35 20 0.69
Windows ‐ High Efficiency Space Heating 3% 2% 61% 75% $0.35 20 0.69
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 81% 90% $0.65 8 0.31
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 1% 45% $0.38 8 1.07
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 10% 75% $0.09 8 1.50
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.50 8 0.32
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.70 11 1.56
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 7% 45% $0.20 8 1.00
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.24
Interior Screw‐in ‐ Task Lighting Interior Lighting 7% 4% 25% 75% $0.24 5 0.08
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 9% 56% $0.20 8 0.50
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 8% 90% $0.01 9 4.22
Water Heater ‐ Pipe Insulation Water Heating 4% 2% 46% 50% $0.28 15 0.24
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 0% $0.11 10 0.63
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 40% 50% $0.02 10 5.80
Water Heater ‐ Thermostat Setback Water Heating 4% 0% 10% 75% $0.11 10 0.38
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 0% $0.02 5 1.53
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 0% 75% $0.20 16 1.09
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 18% 38% $0.35 16 1.24
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.09
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.20
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 1.02
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.00
Commissioning ‐ Comprehensive Cooling 10% 0% 40% 75% $1.25 25 0.83
Commissioning ‐ Comprehensive Space Heating 10% 7% 40% 75% $1.25 25 0.83
Commissioning ‐ Comprehensive Interior Lighting 10% 7% 40% 75% $1.25 25 0.83
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 61.07
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.08
LED Exit Lighting Interior Lighting 2% 2% 85% 86% $0.00 10 11.83
Commissioning ‐ Lighting Interior Lighting 5% 4% 30% 75% $0.20 25 1.54
Commissioning ‐ Lighting Exterior Lighting 5% 4% 30% 75% $0.20 25 1.54
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.00
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.23
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 7.30
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 36.95
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 0% 0% $0.14 8 0.30
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.95
Advanced New Construction Designs Cooling 40% 0% 5% 75% $2.00 35 2.01
Advanced New Construction Designs Space Heating 40% 30% 5% 75% $2.00 35 2.01
Advanced New Construction Designs Interior Lighting 25% 19% 5% 75% $2.00 35 2.01
Insulation ‐ Wall Cavity Cooling 1% 0% 10% 68% $0.34 20 0.72
Insulation ‐ Wall Cavity Space Heating 10% 2% 10% 68% $0.34 20 0.72
Roofs ‐ Green Cooling 7% 0% 2% 11% $1.00 30 0.26
Roofs ‐ Green Space Heating 4% 3% 2% 11% $1.00 30 0.26
Industrial Process Improvements Miscellaneous 10% 8% 0% 23% $0.52 10 1.16
Custom Measures Cooling 8% 0% 10% 45% $1.50 15 0.45
Custom Measures Space Heating 8% 6% 10% 45% $1.50 15 0.45
Custom Measures Interior Lighting 8% 6% 10% 45% $1.50 15 0.45
Custom Measures Food Preparation 8% 6% 10% 45% $1.50 15 0.45
Custom Measures Refrigeration 8% 6% 10% 45% $1.50 15 0.45
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 19% $0.80 15 0.68
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $4.00 15 0.53
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 47% $8.04 15 1.01
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 786 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-37
An EnerNOC Company
Table D-15 Energy Efficiency Measure Data — Large Commercial, New Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 27% 90% $0.06 4 1.13
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.19
Chiller ‐ Chilled Water Reset Cooling 18% 0% 30% 75% $0.18 4 0.42
Chiller ‐ Chilled Water Variable‐Flow System Cooling 5% 0% 30% 34% $0.18 10 0.28
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 66% $0.90 20 0.61
Chiller ‐ VSD Cooling 32% 0% 15% 66% $1.17 20 0.50
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 15% 41% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 8% 0% 25% 75% $0.18 14 0.63
Cooling ‐ Economizer Installation Cooling 11% 0% 44% 49% $0.15 15 1.19
Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 10% 95% $0.06 4 2.72
Insulation ‐ Ducting Cooling 4% 0% 8% 50% $0.41 20 0.56
Insulation ‐ Ducting Space Heating 3% 1% 8% 50% $0.41 20 0.56
Energy Management System Cooling 21% 0% 48% 90% $0.35 14 2.10
Energy Management System Space Heating 8% 5% 48% 90% $0.35 14 2.10
Energy Management System Interior Lighting 9% 6% 48% 90% $0.35 14 2.10
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 13% 7% 1% 11% $0.04 10 2.84
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.07
Fans ‐ Variable Speed Control Ventilation 15% 5% 2% 90% $0.20 10 0.68
Commissioning ‐ HVAC Cooling 5% 0% 50% 75% $0.85 25 0.30
Commissioning ‐ HVAC Space Heating 5% 4% 50% 75% $0.85 25 0.30
Commissioning ‐ HVAC Ventilation 5% 4% 50% 75% $0.85 25 0.30
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 5% 34% $0.13 10 1.05
Thermostat ‐ Clock/Programmable Cooling 5% 0% 33% 50% $0.13 11 0.97
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 33% 50% $0.13 11 0.97
Insulation ‐ Ceiling Cooling 1% 0% 75% 81% $0.35 20 0.60
Insulation ‐ Ceiling Space Heating 10% 3% 75% 81% $0.35 20 0.60
Insulation ‐ Radiant Barrier Cooling 1% 0% 7% 13% $0.26 20 0.56
Insulation ‐ Radiant Barrier Space Heating 5% 2% 7% 13% $0.26 20 0.56
Roofs ‐ High Reflectivity Cooling 4% 0% 5% 95% $0.05 15 1.28
Windows ‐ High Efficiency Cooling 12% 0% 72% 75% $0.88 20 0.72
Windows ‐ High Efficiency Space Heating 11% 8% 72% 75% $0.88 20 0.72
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 86% 90% $0.65 8 0.30
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 1% 45% $0.34 8 1.14
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 10% 19% $0.19 8 0.57
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.40 8 0.39
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.63 11 1.66
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 13% 45% $0.20 8 0.99
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.19
Interior Screw‐in ‐ Task Lighting Interior Lighting 10% 5% 10% 75% $0.24 5 0.11
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 9% 56% $0.20 8 0.49
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 3% 90% $0.03 9 1.60
Water Heater ‐ Pipe Insulation Water Heating 4% 2% 0% 0% $0.28 15 0.27
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 23% $0.11 10 0.69
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $0.04 10 3.23
Water Heater ‐ Thermostat Setback Water Heating 4% 0% 0% 0% $0.11 10 0.44
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 3% $0.04 5 0.87
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 0% 75% $0.20 16 0.58
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 38% 45% $0.35 16 0.94
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.63
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.35
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 0.65
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.94
Commissioning ‐ Comprehensive Cooling 10% 0% 40% 75% $1.00 25 0.96
Commissioning ‐ Comprehensive Space Heating 10% 7% 40% 75% $1.00 25 0.96
Commissioning ‐ Comprehensive Interior Lighting 10% 7% 40% 75% $1.00 25 0.96
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 67.83
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.09
LED Exit Lighting Interior Lighting 2% 2% 85% 86% $0.00 10 11.13
Commissioning ‐ Lighting Interior Lighting 5% 4% 60% 75% $0.15 25 1.99
Commissioning ‐ Lighting Exterior Lighting 5% 4% 60% 75% $0.15 25 1.99
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.52
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.03
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 5.86
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 33.94
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 1% 2% $0.14 8 0.29
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.78
Advanced New Construction Designs Cooling 40% 0% 5% 75% $2.00 35 1.84
Advanced New Construction Designs Space Heating 40% 30% 5% 75% $2.00 35 1.84
Advanced New Construction Designs Interior Lighting 25% 19% 5% 75% $2.00 35 1.84
Insulation ‐ Wall Cavity Cooling 1% 0% 9% 68% $0.78 20 0.43
Insulation ‐ Wall Cavity Space Heating 10% 2% 9% 68% $0.78 20 0.43
Roofs ‐ Green Cooling 4% 0% 2% 13% $1.00 15 0.08
Roofs ‐ Green Space Heating 2% 2% 2% 13% $1.00 15 0.08
Industrial Process Improvements Miscellaneous 10% 8% 0% 5% $0.52 10 1.18
Custom Measures Cooling 8% 0% 10% 45% $0.90 15 0.73
Custom Measures Space Heating 8% 6% 10% 45% $0.90 15 0.73
Custom Measures Interior Lighting 8% 6% 10% 45% $0.90 15 0.73
Custom Measures Food Preparation 8% 6% 10% 45% $0.90 15 0.73
Custom Measures Refrigeration 8% 6% 10% 45% $0.90 15 0.73
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 28% $0.80 15 0.76
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 0% $4.00 15 0.58
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $6.00 15 0.98
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 787 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-38 www.gepllc.com

Table D-16 Energy Efficiency Measure Data — Extra Large Commercial, New Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 47% 90% $0.06 4 1.02
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.17
Chiller ‐ Chilled Water Reset Cooling 12% 0% 60% 75% $0.09 4 0.61
Chiller ‐ Chilled Water Variable‐Flow System Cooling 8% 0% 30% 34% $0.09 10 0.95
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 75% $0.90 20 0.64
Chiller ‐ VSD Cooling 28% 0% 3% 75% $1.17 20 0.45
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 25% 37% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 8% 0% 25% 75% $0.09 14 1.28
Cooling ‐ Economizer Installation Cooling 11% 0% 73% 81% $0.15 15 1.14
Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 5% 95% $0.06 4 2.61
Insulation ‐ Ducting Cooling 7% 0% 2% 50% $0.41 20 0.71
Insulation ‐ Ducting Space Heating 3% 1% 2% 50% $0.41 20 0.71
Energy Management System Cooling 11% 0% 80% 90% $0.35 14 0.94
Energy Management System Space Heating 4% 2% 80% 90% $0.35 14 0.94
Energy Management System Interior Lighting 5% 3% 80% 90% $0.35 14 0.94
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 13% 7% 1% 8% $0.04 10 3.31
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.24
Fans ‐ Variable Speed Control Ventilation 15% 5% 2% 90% $0.20 10 0.80
Commissioning ‐ HVAC Cooling 5% 0% 50% 75% $0.70 25 0.42
Commissioning ‐ HVAC Space Heating 5% 4% 50% 75% $0.70 25 0.42
Commissioning ‐ HVAC Ventilation 5% 4% 50% 75% $0.70 25 0.42
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 1% 34% $0.44 10 1.01
Thermostat ‐ Clock/Programmable Cooling 3% 0% 25% 50% $0.13 11 0.67
Thermostat ‐ Clock/Programmable Space Heating 3% 1% 25% 50% $0.13 11 0.67
Insulation ‐ Ceiling Cooling 1% 0% 2% 81% $0.35 20 0.68
Insulation ‐ Ceiling Space Heating 10% 3% 2% 81% $0.35 20 0.68
Insulation ‐ Radiant Barrier Cooling 1% 0% 2% 13% $0.26 20 0.47
Insulation ‐ Radiant Barrier Space Heating 2% 1% 2% 13% $0.26 20 0.47
Roofs ‐ High Reflectivity Cooling 10% 0% 5% 95% $0.18 15 0.85
Windows ‐ High Efficiency Cooling 6% 0% 95% 100% $1.69 20 0.38
Windows ‐ High Efficiency Space Heating 2% 2% 95% 100% $1.69 20 0.38
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 78% 90% $0.65 8 0.23
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 3% 45% $0.30 8 0.86
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 10% 15% $0.19 8 0.61
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.20 8 0.52
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.56 11 1.24
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 42% 45% $0.20 8 0.76
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.20
Interior Screw‐in ‐ Task Lighting Interior Lighting 10% 5% 25% 75% $0.24 5 0.16
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 12% 56% $0.20 8 0.38
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 2% 90% $0.03 9 2.63
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 0% $0.28 15 0.69
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 23% $0.11 10 1.18
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $0.04 10 5.43
Water Heater ‐ Thermostat Setback Water Heating 4% 0% 0% 0% $0.11 10 0.71
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 0% $0.04 5 1.43
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 10% 75% $0.20 16 0.02
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 10% 38% $0.35 16 0.32
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.12
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.26
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 0.27
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.17
Commissioning ‐ Comprehensive Cooling 10% 0% 40% 75% $0.80 25 1.05
Commissioning ‐ Comprehensive Space Heating 10% 7% 40% 75% $0.80 25 1.05
Commissioning ‐ Comprehensive Interior Lighting 10% 7% 40% 75% $0.80 25 1.05
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 38.86
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.10
LED Exit Lighting Interior Lighting 2% 2% 85% 86% $0.00 10 16.52
Commissioning ‐ Lighting Interior Lighting 5% 4% 60% 75% $0.10 25 2.47
Commissioning ‐ Lighting Exterior Lighting 5% 4% 60% 75% $0.10 25 2.47
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.04
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.45
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 6.26
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 20.31
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 0% 0% $0.14 8 0.42
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.07
Advanced New Construction Designs Cooling 40% 0% 5% 75% $2.00 35 1.67
Advanced New Construction Designs Space Heating 40% 30% 5% 75% $2.00 35 1.67
Advanced New Construction Designs Interior Lighting 25% 19% 5% 75% $2.00 35 1.67
Insulation ‐ Wall Cavity Cooling 1% 0% 2% 68% $0.09 20 1.73
Insulation ‐ Wall Cavity Space Heating 10% 2% 2% 68% $0.09 20 1.73
Roofs ‐ Green Cooling 10% 0% 2% 13% $1.00 15 0.20
Roofs ‐ Green Space Heating 5% 3% 2% 13% $1.00 15 0.20
Industrial Process Improvements Miscellaneous 10% 8% 0% 0% $0.52 10 1.11
Custom Measures Cooling 8% 0% 10% 45% $0.67 15 0.81
Custom Measures Space Heating 8% 6% 10% 45% $0.67 15 0.81
Custom Measures Interior Lighting 8% 6% 10% 45% $0.67 15 0.81
Custom Measures Food Preparation 8% 6% 10% 45% $0.67 15 0.81
Custom Measures Refrigeration 8% 6% 10% 45% $0.67 15 0.81
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 41% $0.80 15 1.27
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 0% $4.00 15 1.00
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $4.00 15 1.57
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 788 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-39
An EnerNOC Company
Table D-17 Energy Efficiency Measure Data — Extra Large Industrial, New Vintage
  Note: Costs are per sq. ft.

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Refrigeration ‐ System Controls Process 11% 8% 5% 34% $0.40 10 18.09
Refrigeration ‐ System Maintenance Process 3% 2% 5% 34% $0.00 10 2,067.93
Refrigeration ‐ System Optimization Process 15% 11% 5% 34% $0.80 10 12.92
Motors ‐ Variable Frequency Drive Machine Drive 13% 9% 25% 38% $0.10 10 3.38
Motors ‐ Magnetic Adjustable Speed Drives Machine Drive 13% 9% 25% 38% $0.10 10 3.38
Compressed Air ‐ System Controls Machine Drive 9% 7% 5% 34% $0.40 10 0.59
Compressed Air ‐ System Optimization and Improvements Machine Drive 13% 9% 5% 34% $0.80 10 0.42
Compressed Air ‐ System Maintenance Machine Drive 3% 2% 5% 34% $0.20 10 0.34
Compressed Air ‐ Compressor Replacement Machine Drive 5% 4% 5% 34% $0.20 10 0.68
Fan System ‐ Controls Machine Drive 4% 3% 10% 38% $0.35 10 0.11
Fan System ‐ Controls Machine Drive 4% 3%10%38% $0.35 10 0.11
Fan System ‐ Optimization Machine Drive 6% 5% 10% 38% $0.70 10 0.08
Fan System ‐ Optimization Machine Drive 6% 5% 10% 38% $0.70 10 0.08
Fan System ‐ Maintenance Machine Drive 1% 1% 10% 38% $0.15 10 0.07
Fan System ‐ Maintenance Machine Drive 1% 1% 10% 38% $0.15 10 0.07
Pumping System ‐ Controls Machine Drive 5% 4% 5% 34% $0.38 12 0.42
Pumping System ‐ Optimization Machine Drive 13% 9% 5% 34% $0.75 12 0.54
Pumping System ‐ Maintenance Machine Drive 2% 1% 5% 34% $0.19 10 0.27
RTU ‐ Maintenance Cooling 14% 0% 22% 90% $0.06 4 2.82
Chiller ‐ Chilled Water Reset Cooling 14% 0% 60% 75% $0.09 4 2.53
Chiller ‐ Chilled Water Variable‐Flow System Cooling 4% 0% 30% 34% $0.20 10 0.80
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 67% $0.90 20 2.40
Chiller ‐ VSD Cooling 27% 0% 25% 67% $1.17 20 1.63
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 25% 50% $0.04 10 0.04
Chiller ‐ Condenser Water Temprature Reset Cooling 10% 0% 5% 75% $0.20 14 2.60
Cooling ‐ Economizer Installation Cooling 6% 0% 29% 34% $0.15 15 1.92
Heat Pump ‐ Maintenance Combined Heating/Cooling 7% 7% 2% 95% $0.03 4 7.76
Insulation ‐ Ducting Space Heating 5% 5% 12% 50% $0.41 20 0.95
Insulation ‐ Ducting Cooling 3% 0% 12% 50% $0.41 20 0.95
Energy Management System Cooling 5% 0% 11% 90% $0.35 14 0.88
Energy Management System Space Heating 2% 1% 11% 90% $0.35 14 0.88
Energy Management System Interior Lighting 2% 1% 11% 90% $0.35 14 0.88
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 2% 90% $0.14 10 2.81
Fans ‐ Variable Speed Control Ventilation 15% 5% 3% 90% $0.34 10 2.97
Commissioning ‐ HVAC Cooling 5% 0% 60% 75% $0.70 25 0.92
Commissioning ‐ HVAC Space Heating 5% 4% 60% 75% $0.70 25 0.92
Commissioning ‐ HVAC Ventilation 5% 4% 60% 75% $0.70 25 0.92
Pumps ‐ Variable Speed Control Machine Drive 5% 4% 0% 34% $0.44 10 0.31
Thermostat ‐ Clock/Programmable Cooling 5% 0% 59% 70% $0.13 11 2.02
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 59% 70% $0.13 11 2.02
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 84% 90% $0.65 8 0.15
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 10% 40% $0.08 8 0.42
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 38% $0.20 11 1.76
LED Exit Lighting Interior Lighting 2% 2% 85% 86% $0.00 10 3.72
Commissioning ‐ Lighting Interior Lighting 5% 4% 60% 75% $0.10 25 1.41
Commissioning ‐ Lighting Exterior Lighting 5% 4% 60% 75% $0.10 25 1.41
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 15% 45% $0.20 8 0.50
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.06
Interior Screw‐in ‐ Task Lighting Interior Lighting 7% 4% 10% 75% $0.24 5 0.03
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 2% 56% $0.20 8 0.25
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 0.41
Advanced New Construction Designs Cooling 40% 0% 5% 75% $2.00 35 2.67
Advanced New Construction Designs Space Heating 40% 30% 5% 75% $2.00 35 2.67
Advanced New Construction Designs Interior Lighting 25% 19% 5% 75% $2.00 35 2.67
Custom Measures Cooling 8% 0% 10% 45% $1.60 15 1.28
Custom Measures Space Heating 8% 6% 10% 45% $1.60 15 1.28
Custom Measures Interior Lighting 8% 6% 10% 45% $1.60 15 1.28
Custom Measures Machine Drive 8% 6% 10% 45% $1.60 15 1.28
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $4.00 15 2.51
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 789 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 790 of 1069

2011 Electric Integrated
Resource Plan

Appendix D – Avista Electric
Conservation Potential
Assessment Study

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 791 of 1069

Global Energy Partners
An EnerNOC Company 500 Ygnacio Valley Road, Suite 450
Walnut Creek, CA 94596
P: 925.482.2000
F: 925.284.3147 E: [e-mail]

AVISTA ELECTRIC
CONSERVATION POTENTIAL
ASSESSMENT STUDY
Final Report — Electricity Potentials
August 19, 2011
J. Borstein, Project Manager
I. Rohmund, Director

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 792 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 793 of 1069

Global Energy Partners iii
An EnerNOC Company
This report was prepared by
Global Energy Partners
An EnerNOC Company
500 Ygnacio Valley Blvd., Suite 450
Walnut Creek, CA 94596
Principal Investigator(s):
I. Rohmund
J. Borstein
A. Duer
B. Kester
J. Prijyanonda
S. Yoshida

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 794 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 795 of 1069

Global Energy Partners v
An EnerNOC Company
EXECUTIVE SUMMARY
Avista Corporation (Avista) engaged Global Energy Partners (Global) to conduct a Conservation
Potential Assessment (CPA) Study. The CPA is a 20-year potentials study for energy efficiency
(EE) and demand response (DR) to provide data on demand-side resources for developing
Avista’s 2011 Integrated Resource Plan (IRP), and in accordance with Washington I-937. The
study used 2009, the first year for which complete billing data was available, as the baseline year
and then developed potential estimates for the period 2012–2032. This report provides results of
the electricity energy efficiency potential study only, and subsequent documents will address
natural gas and DR potential.
Study Objectives
The study objectives included:
Conduct a conservation potential study for electricity for Washington and Idaho, and natural
gas for Washington, Idaho, and Oregon. The study will account for:
o Impacts of existing Avista conservation programs
o Avista’s load forecasts and load shapes
o Impacts of codes and standards
o Technology developments and innovation
o The economy and energy prices
o Naturally occurring energy savings
Assess and analyze cost-effective EE and DR potentials in accordance with the Northwest
Power and Conservation Council’s (NWPPC) 6th Power Plan and Washington I-937
requirements.
Obtain supply curves showing the incremental costs associated with achieving higher levels
of EE and stacking EE resources by cost of conserved energy.
Analyze various market penetration rates associated with technical, economic, achievable,
and naturally occurring potential estimates.
Study Approach
To execute this project, Global took the following steps, which are also shown in Figure ES-1.
1. Performed a market assessment to describe base year energy consumption for the residential
and C&I sectors. This included using utility data and secondary data to understand customers
in Avista’s service territory and how these customers currently use electricity. Based on the
market assessment, we developed energy market profiles for the study’s base year, 2009.
2. Developed a baseline energy forecast by sector and end use for the twenty-year study
period.
3. Identified and analyzed energy-efficiency measures appropriate for the Avista service area.
4. Estimated four levels of energy-efficiency potential, technical, economic, maximum
achievable, and realistic achievable.
The steps are described in further detail in Chapter 2.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 796 of 1069
Avista Conservation Potential Assessment Study Executive Summary
vi www.gepllc.com

Figure ES-1 Analysis Approach Overview

The study segmented Avista customers by state and rate class (Residential, Commercial &
Industrial (C&I) General Service, C&I Large General Service, Extra Large Commercial, and Extra
Large Industrial). In addition, the residential class was segmented by housing type and income
(single family, multi-family, mobile home, and low income). The low-income threshold for
purposes of this study was defined as 200% of the Federal poverty level. For the pumping rate
classes, representing 2% of load, the Northwest Power and Conservation Council (NWPCC) Sixth
Plan calculator was used to determine future EE potential. Within each segment, energy use was
characterized by end-use (e.g., space heating, cooling, lighting, water heat, motors, etc.) and by
technology (e.g., heat pump, resistance heating, furnace for space heating). This market
characterization is detailed in Chapter 3.
The baseline forecast is the ―business as usual‖ metric, without new utility conservation
programs, against which energy savings from energy efficiency measures are compared. The
baseline forecast includes the projected impacts of known codes and standards, as of 2010 when
the study was conducted. These include the Energy Independence and Security Act (EISA),
which mandates higher efficacies for lighting technologies starting in 2012, and a series of recent
appliance standards agreed upon in 2010. These recent codes and standards have direct bearing
on the amount of utility program potential over and above the effects of codes and standards
and naturally occurring conservation. This process incorporates the changes in market conditions
such as customer and market growth, income growth, Avista’s retail rates forecast, trends in
end-use and technology saturations, equipment purchase decisions, consumer price elasticity,
and income and persons per household. The baseline forecast enables understanding customer
potential estimates in the context of total energy use in the future.
For each customer sector, a robust list of electrical energy efficiency measures was compiled,
drawing upon the Sixth Power Plan database, the Regional Technical Forum (RTF), and other
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 797 of 1069
Executive Summary Avista Conservation Potential Assessment Study
Global Energy Partners vii
An EnerNOC Company
measures considered applicable to Avista. This list of energy efficiency equipment and measures
included 2,808 equipment options and 1,524 measure options and represented a wide variety of
major types of end-use equipment, as well as devices and actions to reduce energy consumption.
Considered against current avoided costs, many of these measures do not pass the economic
screens, but may ultimately be part of Avista’s energy efficiency program portfolio during this 20 -
year planning horizon. Measure cost, savings, estimated useful life, and other performance
factors were characterized for the list of measures. Cost-effectiveness screening was performed,
using the total resource cost (TRC) test, for each measure and each year of the study to develop
economic potential. The measure analysis is discussed in Chapter 5.
Market Characterization and Baseline Forecast
During 2009, Avista served 354,615 residential, commercial, industrial, and pumping customers
with a combined electricity use of approximately 8,862 GWh.
Residential Sector
The total number of 2009 residential customers was 200,134 in Washington and 99,579 in Idaho.
Table ES-1 shows their distribution by housing type and income level. The limited income
category, which is composed of single-family, multi-family, and mobile homes, represents
households with income below $35,000 annually.
Table ES-1 Residential Electricity Usage and Intensity by Segment and State, 2009
Washington
Segment
Intensity
(kWh/Household)
Number of
Customers
% of
Customers
2009 Electricity
Sales (MWh) % of Sales
Single Family 14,547 109,134 54% 1,587,572 65%
Multi-Family 8,728 18,219 9% 159,019 6%
Mobile Home 13,092 5,248 3% 68,708 3%
Limited Income 9,424 67,533 34% 636,407 26%
Total 12,250 200,134 100% 2,451,707 100%

Idaho
Segment
Intensity
(kWh/Household)
Number of
Customers
% of
Customers
2009 Electricity
Sales (MWh) % of Sales
Single Family 13,703 59,205 59% 811,302 69%
Multi-Family 8,213 5,237 5% 43,013 4%
Mobile Home 12,320 4,774 5% 58,815 5%
Limited Income 8,868 30,363 31% 269,249 23%
Total 11,874 99,580 100% 1,182,379 100%

For each residential segment, a snapshot of electricity use by end use and technology was
developed. Figure ES-2 presents the end-use breakout by household for the residential sector as
a whole. The appliance end use accounts for the largest share of the usage, closely followed by
space heating, with water heating the third largest end use. The miscellaneous end use includes
such devices as furnace fans, pool pumps, and other ―plug‖ loads (hair dryers, power tools,
coffee makers, etc.). Interior and exterior lighting combined account for 12% of electricity use in
2009. The electronics end use, which includes personal computers, televisions, home audio,
video game consoles, etc., also contributes significantly to household electricity usage. Cooling
and combined heating and cooling through heat pumps make up the remainder.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 798 of 1069
Avista Conservation Potential Assessment Study Executive Summary
viii www.gepllc.com

Figure ES-2 Residential Electricity Use by End Use per Household, 2009 (kWh and %)

The residential baseline forecast incorporates the effects of future customer growth, trends in
appliance ownership, building codes, federal appliance standards and customer usage response
to changes in electricity prices and household income. As such, it includes naturally-occurring
energy efficiency. Overall, residential use in both states and for all segments increases from
3,634,054 MWh in 2009 to 5,600,870 MWh in 2032, an average annual growth rate of 1.9%. This
reflects projected growth in the number of households, home size, and income levels, as well as
relatively low electricity prices. Figure ES-3 shows the residential baseline forecast by end use.
Figure ES-3 Residential Baseline Forecast by End Use

Cooling,
601 , 5%
Space Heating,
2,619 , 21%
Heat & Cool,
714 , 6%
Water Heating,
1,834 , 15%
Appliances,
2,637 , 22%
Interior
Lighting,
1,279 , 10%
Exterior
Lighting,
213 , 2%
Electronics,
1,053 , 9%
Miscellaneous,
1,176 , 10%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 799 of 1069
Executive Summary Avista Conservation Potential Assessment Study
Global Energy Partners ix
An EnerNOC Company
Commercial & Industrial Sector
Table ES-2 and Table ES-3 present the segmentation of C&I customers in Washington and Idaho
respectively. Although the General Service 011 and Large General Service 021 rate classes
include a small percentage of industrial customers, we treated them as primarily commercial
building types. For the General Service segment, we assumed facilities were small to medium
buildings, dominated by retail facilities. For the Large General Service segment, we assumed the
typical facility was an office building.
Table ES-2 Commercial Sector Market Characterization Results, Washington 2009
Avista Rate Schedule LoadMAP Segment
and Typical Building
Electricity
sales (MWh)
Intensity
(kWh/sq.ft.)
General Service 011, 012 Small and Medium Commercial — Retail 415,935 17.5
Large General Service 021, 022 Large Commercial — Office 1,556,929 16.7
Extra Large General
Service Commercial 025C Extra Large Commercial — University 265,686 13.9
Extra Large General
Service Industrial 025I Extra Large Industrial 613,615 40.0
Total 2,852,165

Table ES-3 Commercial Sector Market Characterization Results, Idaho 2009
Avista Rate Schedule LoadMAP Segment and Typical
Building
Electricity
sales (MWh)
Intensity
(kWh/sq.ft.)
General Service 011, 012 Small and Medium Commercial — Retail 322,570 17.5
Large General Service 021, 022 Large Commercial — Office 699,953 16.7
Extra Large General
Service Commercial 025C Extra Large Commercial — University 70,361 13.9
Extra Large General
Service Industrial 025I, 025P Extra Large Industrial 1,087,974 40.0
Total 2,180,858

Figure ES-4 shows the breakdown of annual electricity usage by end use for the C&I sector as a
whole. Lighting is the largest single end use in the sector, accounting for one fifth of total usage.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 800 of 1069
Avista Conservation Potential Assessment Study Executive Summary
x www.gepllc.com

Figure ES-4 Commercial and Industrial Electricity Consumption by End Use, 2009

Figure ES-5 presents the baseline forecast at the end-use level for the C&I sector as a whole.
Overall, C&I annual energy use increases from 5,033,023 MWh in 2009 to 7,239,694 MWh in
2032, a 43.8% increase. This reflects growth in floor space across all sectors. Interior screw-in
lighting increases over the forecast period, but at a slower rate than other technologies as a
result of the EISA lighting standard.
Figure ES-5 C&I Baseline Electricity Forecast by End Use

System-wide Baseline Forecast Summary
Table ES-4 and Figure ES-6 provide an overall summary of the baseline forecast by sector and
for the Avista system as a whole. Overall, the forecast for the next 20 years shows substantial
growth, reflecting projected increases in customers and income. This forecast is the metric
against which the energy-efficiency savings potential is compared.
Cooling
9%
Space Heating
5%
Heat & Cool
2%
Ventilation
8%
Water Heating
5%
Food Preparation
2%
Refrigeration
4%Interior Lighting
21%
Exterior Lighting
3%
Office Equipment
7%
Miscellaneous
12%
Machine Drive
15%
Process
7%
-
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
2009 2012 2017 2022 2027 2032
An
n
u
a
l

U
s
e

(
M
W
h
)
Cooling
Space Heating
Heat & Cool
Ventilation
Water Heating
Food Preparation
Refrigeration
Interior Lighting
Exterior Lighting
Office Equipment
Miscellaneous
Machine Drive
Process
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 801 of 1069
Executive Summary Avista Conservation Potential Assessment Study
Global Energy Partners xi
An EnerNOC Company
Table ES-4 Baseline Forecast Summary by Sector and State
End Use 2009 2012 2022 2032 % Change
('09–'32)
Avg. Growth Rate
('09–'32)
Res. WA 2,451,707 2,448,104 2,947,427 3,792,486 54.7% 1.9%
Res. ID 1,182,379 1,178,591 1,408,812 1,808,300 52.9% 1.8%
C&I WA 2,852,165 2,955,156 3,509,816 4,280,649 50.1% 1.8%
C&I ID 2,180,858 2,217,188 2,551,291 2,970,324 36.2% 1.3%
Total 8,667,109 8,799,039 10,417,347 12,851,760 48.3% 1.7%

Figure ES-6 Baseline Forecast Summary by Sector and State

The baseline forecast, prior to the consideration of potentials, projects overall growth of 48% in
electric consumption. This compounded average annual growth rate of 1.7% during this 20 year
period is consistent with Avista’s current and previous Integrated Resource Plans. Chapter 4
provides details of the baseline forecast.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 802 of 1069
Avista Conservation Potential Assessment Study Executive Summary
xii www.gepllc.com

Definitions of Potential
In this study, we estimated four types of potential: technical; economic; and achievable
potential, which is further divided into maximum achievable, and realistic achievable. Technical
and economic potential are both theoretical limits to efficiency savings. Achievable potential
embodies a set of assumptions about the decisions consumers make regarding the efficiency of
the equipment they purchase, the maintenance activities they undertake, the controls they use
for energy-consuming equipment, and the elements of building construction.
Technical potential is defined as the theoretical upper limit of energy efficiency potential. It
assumes that customers adopt all feasible measures regardless of their cost. At the time of
equipment failure, customers replace their equipment with the most efficient option available. In
new construction, customers and developers also choose the most efficient equipment option.
Examples of measures that make up technical potential in the residential sector include:
Ductless mini-split air conditioners with variable refrigerant flow
Ground source (or geothermal) heat pumps
LED lighting for general service and linear applications
Technical potential also assumes the adoption of every available other measure, where
applicable. For example, it includes installation of high-efficiency windows in all new construction
opportunities and air conditioner maintenance in all existing buildings with central and room air
conditioning.
Economic potential represents the adoption of all cost-effective energy efficiency measures.
As described earlier, LoadMAP performs an economic screen to determine which measures are
economically viable. LoadMAP incorporates the result of the screen into the purchase shares to
reflect the most efficient measure that passes the screen. For our analysis, we apply the total
resource cost (TRC) test, which compares lifetime energy and capacity benefits to the
incremental cost, including the administrative costs associated with any energy-efficiency
program. The benefits include non-energy benefits.
Achievable potential refines the economic potential by taking into account penetration rates of
efficient technologies, expected program participation, and customer preferences and likely
behavior. Two types of achievable potential were evaluated for this study:
Maximum achievable potential (MAP) establishes an upper boundary of potential
savings a utility could achieve through its energy efficiency programs. MAP presumes
incentives that are sufficient to ensure customer adoption. It also considers a maximum
participation rate by customers for the various energy efficiency programs that are designed
to deliver the various measures. For this study, we developed market acceptance rate (MAR)
factors, based on the ramp rate curves used in the Sixth Power Plan.1 These MAR factors
were then applied to this study’s estimates of economic potential to estimate MAP.
Realistic achievable potential (RAP) represents a lower boundary forecast of potentials
resulting from likely customer behavior and penetration rates of efficient technologies. It
uses a set of program implementation factors (PIFs) to take into account existing barriers
that are likely to limit the amount of savings that might be achieved through energy
efficiency programs. The RAP also takes into account recent utility experience and reported
savings from past and present programs.

1 The Sixth Power Plan Conservation Supply Curve workbooks are available at
http://www.nwcouncil.org/energy/powerplan/6/supplycurves/default.htm, with separate workbooks for specific sectors and end uses.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 803 of 1069
Executive Summary Avista Conservation Potential Assessment Study
Global Energy Partners xiii
An EnerNOC Company
Potential Savings from Electric Energy Efficiency
Maximum achievable potential across all sectors is 88,760 MWh (10.1 aMW) in 2012 and
increases to a cumulative value of 2,905,702 MWh (331.7 aMW) by 2032. These savings
represents 1.0% of the baseline forecast in 2012 and 22.6% in 2032. Realistic achievable
potential in 2012 is 50,261 MWh (5.7 aMW) and reaches a cumulative value of 2,155,133 MWh
(246.0 aMW) by 2032, for savings that are 0.6% and 16.8% of the baseline in 2012 and 2032
respectively. Between 2012 and 2032, the baseline forecast shows overall electricity consumption
growth of 46%, but the realistic achievable potential forecast reduces growth by half to 23%.
Technical potential by 2032 is 37.8% of the baseline and economic potential savings are 26.4%
of the baseline, or roughly 70% of technical potential savings. MAP and RAP savings in 2012 are
86% and 64% respectively of the economic potential savings.
Figure ES-7 displays the energy use forecast for the four potential levels versus the baseline
forecast. Figure ES-8 summarizes the energy-efficiency savings for the four potential levels
relative to the baseline forecast for selected years. Table ES-5 presents the energy consumption
and peak demand for the potential levels across sectors.
Figure ES-7 Energy Efficiency Potential Forecasts, All Sectors

-
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6,000,000
8,000,000
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 804 of 1069
Avista Conservation Potential Assessment Study Executive Summary
xiv www.gepllc.com

Figure ES-8 Summary of Energy Efficiency Potential Savings, All Sectors

Table ES-5 Summary of Energy Efficiency Potential, All Sectors
2012 2017 2022 2027 2032
Baseline Forecast (MWh) 8,799,039 9,463,880 10,417,347 11,536,869 12,851,760
Baseline Peak Demand
(MW) 1,780 1,880 2,080 2,306 2,566
Cumulative Energy Savings (MWh)
Realistic Achievable 50,261 405,985 945,183 1,536,357 2,155,133
Maximum Achievable 88,760 1,035,470 1,952,473 2,476,694 2,905,702
Economic 244,292 1,493,608 2,411,399 2,937,775 3,387,203
Technical 329,513 2,087,061 3,435,475 4,250,217 4,852,362
Cumulative Energy Savings (% of Baseline)
Realistic Achievable 0.6% 4.3% 9.1% 13.3% 16.8%
Maximum Achievable 1.0% 10.9% 18.7% 21.5% 22.6%
Economic 2.8% 15.8% 23.1% 25.5% 26.4%
Technical 3.7% 22.1% 33.0% 36.8% 37.8%
Peak Savings (MW)
Realistic Achievable 14 84 183 306 431
Maximum Achievable 22 207 386 492 566
Economic 60 302 479 580 659
Technical 78 422 669 826 943
Peak Savings (% of Baseline)
Realistic Achievable 0.8% 4.5% 8.8% 13.3% 16.8%
Maximum Achievable 1.2% 11.0% 18.6% 21.3% 22.1%
Economic 3.4% 16.0% 23.0% 25.2% 25.7%
Technical 4.4% 22.4% 32.2% 35.8% 36.8%

Realistic Achievable
Maximum Achievable
Economic
Technical
0%
5%
10%
15%
20%
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2012 2017 2022 2027 2032
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 805 of 1069
Executive Summary Avista Conservation Potential Assessment Study
Global Energy Partners xv
An EnerNOC Company
Table ES-6 and Figure ES-9 summarize cumulative realistic achievable potential by sector.
Initially, the residential sector accounts for about 52% of the savings, but by the end of the
study, the C&I sector becomes the source of 58% of the savings.
Table ES-6 Realistic Achievable Cumulative Energy-efficiency Potential by Sector, MWh
Segment 2012 2017 2022 2027 2032
Residential, WA 17,413 94,529 238,739 431,973 637,029
Residential, ID 8,692 43,922 97,705 172,179 260,003
C&I, WA 15,733 173,433 378,252 575,328 774,619
C&I, ID 8,423 94,102 230,487 356,878 483,482
Total 50,261 405,985 945,183 1,536,357 2,155,133

Figure ES-9 Realistic Achievable Cumulative Potential by Sector

Table ES-7 shows the incremental annual realistic achievable potential by sector for 2012
through 2015. During this period, lighting and appliance standards slow the rate of growth in the
residential baseline energy consumption, thus reducing the amount of incremental annual
potential savings from residential conservation programs. On the other hand, C&I potential
continues to grow. Complete annual incremental savings for Washington and Idaho appear in
Appendices A and B respectively.
Table ES-7 Incremental Annual Realistic Achievable Energy-efficiency Potential by
Sector, MWh
Segment 2012 2013 2014 2015
Residential, WA 17,413 17,161 16,488 18,514
Residential, ID 8,692 8,451 7,943 8,569
C&I, WA 15,733 21,165 26,869 30,393
C&I, ID 8,423 10,734 14,543 16,956
Total 50,261 57,511 65,843 74,432
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
2012 2017 2022 2027 2032
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C&I, WA
Residential, ID
Residential, WA
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 806 of 1069
Avista Conservation Potential Assessment Study Executive Summary
xvi www.gepllc.com

Figure ES-10 illustrates how the annual incremental realistic achievable potential throughout the
study tracks the avoided energy costs, with annual potential generally increasing or decreasing
along with avoided costs. Note however that other factors also influence potential, particularly
the rates at which programs can ramp up over time, which is particularly relevant to how
potential changes from year to year in the early years of the study.
Figure ES-10 Incremental Annual Realistic Achievable Energy-efficiency (MWh)
vs. Avoided Energy Cost

Note: Avoided costs are 2009 real dollars and include energy costs, risk, and the 10% Power Act premium.

$-
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 807 of 1069
Executive Summary Avista Conservation Potential Assessment Study
Global Energy Partners xvii
An EnerNOC Company
Residential Sector Potential
Realistic achievable potential savings for the residential sector in both states is 26,105 MWh in
2012, or 0.7% of the sector’s baseline forecast. It reaches 897,032 MWh, or 16.0% of the
baseline forecast by 2032. Technical and economic potential savings are 37.7% and 24.5%
respectively. Table ES-8 presents estimates for energy and peak demand under the four types of
potential.
Table ES-8 Energy Efficiency Potential, Residential Sector
2012 2017 2022 2027 2032
Baseline Forecast (MWh) 3,626,696 3,871,294 4,356,240 4,918,847 5,600,787
Baseline Peak Demand
(MW) 991 1,026 1,150 1,288 1,449
Cumulative Energy Savings (MWh)
Realistic Achievable 26,105 138,450 336,444 604,152 897,032
Maximum Achievable 36,300 429,065 798,829 1,024,671 1,192,794
Economic 104,111 583,427 967,788 1,188,497 1,373,869
Technical 153,100 918,965 1,468,041 1,825,587 2,112,855
Cumulative Energy Savings (% of Baseline)
Realistic Achievable 0.7% 3.6% 7.7% 12.3% 16.0%
Maximum Achievable 1.0% 11.1% 18.3% 20.8% 21.3%
Economic 2.9% 15.1% 22.2% 24.2% 24.5%
Technical 4.2% 23.7% 33.7% 37.1% 37.7%
Peak Savings (MW)
Realistic Achievable 10 44 100 179 262
Maximum Achievable 14 120 232 301 343
Economic 38 171 286 349 396
Technical 51 256 407 503 579
Peak Savings (% of Baseline)
Realistic Achievable 1.1% 4.3% 8.7% 13.9% 18.1%
Maximum Achievable 1.4% 11.7% 20.2% 23.3% 23.7%
Economic 3.8% 16.7% 24.9% 27.1% 27.3%
Technical 5.1% 24.9% 35.4% 39.0% 40.0%

In terms of how residential potential is divided among the various end uses, we note the
following:
Water Heating offers the highest cumulative technical potential over the 20-year period,
which reflects the high potential for conversion to natural gas in homes where gas is
available (see discussion below) and use of heat pump water heaters where gas is not
available, as well as a wide range of other water heating measures. Conversion to natural
gas passes the TRC test throughout the study period for most Washington housing types and
for single family homes in Idaho. In contrast, based on the study’s assumptions of equ ipment
cost and avoided cost, heat pump water heaters are cost-effective in new single family
homes by 2014, but do not become cost-effective for existing homes until 2024 in Idaho and
2028 in Washington. Water heating also has the highest cumulative realistic achievable
potential.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 808 of 1069
Avista Conservation Potential Assessment Study Executive Summary
xviii www.gepllc.com

Space Heating offers the second-highest cumulative technical potential over the study and
its economic potential is slightly higher than water heating, again due to the potential for
conversion to natural gas (see discussion below), but also due to shell measures, controls,
and advanced new construction designs. Based on realistic achievable savings, space heating
also ranks second.
Interior lighting offers the fourth-largest technical potential savings, but the third-largest
economic and realistic achievable potential. The lighting standard begins its phase-in starting
in 2012, which coincides with the availability in the market place of advanced incandescent
lamps that meet the minimum efficacy standard. The baseline forecast assumes that people
will install both advanced incandescent and CFLs in screw-in lighting applications. For
technical potential, LED lamps are the most efficient option, starting in 2012. However, LED
lamps do not pass the economic screen until 2022, when they begin to become cost-effective
for pin-based fixtures. Nonetheless, there is significant economic and realistic achievable
lighting potential due to conversion from advanced incandescents to CFLs.
Appliances rank sixth based on technical potential, but fourth in terms of realistic
achievable potential. This reflects the cost-effectiveness of the highest-efficiency white-goods
appliances for both new construction and for replacing failed units, as well as the market
acceptance of high-efficiency appliances. Removal of second refrigerators and freezers also
contributes to economic and realistic achievable potential within this end use.
Cooling offers the third-highest technical potential, but is sixth based on realistic achievable
potential. Initially technical potential is low but ramps up due to the assumption of increased
saturation of air conditioning over time. Economic potential for cooling in 2031 is about 40%
of technical potential because the higher SEER units do not pass the economic screen based
on based on the study’s assumptions of equipment cost and avoided cost.
Home electronics also offer substantial savings opportunities. Technical potential reflects
the purchase of ENERGY STAR units for all technologies, except PCs and laptops for which a
super-efficient ―climate saver‖ option is available in the marketplace. However, the climate
saver options are not cost-effective during the forecast horizon, so economic potential
reflects the purchase of ENERGY STAR units across all technologies in this end use.
Commercial and Industrial Sector Potential
Realistic achievable potential savings for the C&I sector in both states is 24,155 MWh in 2012, or
0.5% of the sector’s baseline forecast. It reaches 1,258,101 MWh, or 17.4% of the baseline
forecast by 2032. Technical and economic potential savings are 37.8% and 27.8% of the
baseline forecast respectively. Table ES-9 presents estimates for the sector’s energy and peak
demand under the four types of potential.
In terms of how potential is divided among the various end uses, we note the following:
Interior lighting offers the largest technical, economic, and achievable potential. The high
technical potential of 892,840 MWh in 2032 is a result of LED lighting that is now commercially
available in screw-in and linear lighting applications, as well as numerous fixture improvement
and control options. However, LED lighting is not cost effective given the study’s avoided cost
assumptions, so economic potential reflects installation of CFL, T5, and Super T8 lamps
throughout most of the commercial sector. Still, this results in realistic achievable potential of
598,564 MWh by 2032.
Cooling has the third highest savings for technical potential at 302,301 MWh in 2032, and
many of the cooling measures are cost effective, including installation of high-efficiency
equipment, thermal shell measures, HVAC control strategies, and retrocommissioning.
Because the market for cooling technologies is mature, these savings are relatively easy to
capture, as reflected in the ramp rates for these measures. Thus realistic achievable potential
for cooling, at 119,700 MWh, is the second highest among C&I end uses.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 809 of 1069
Executive Summary Avista Conservation Potential Assessment Study
Global Energy Partners xix
An EnerNOC Company
Ventilation is second in terms of technical and economic potential due to conversion to variable
air volume systems, high-efficiency and variable speed control fans, and retrocommissioning.
Realistic achievable potential in 2032 of 117,020 MWh ranks this end use third, just behind
cooling.
Machine drive ranks fourth in realistic achievable potential at 101,018 MWh in 2032. Even
though the National Electrical Manufacturer’s Association (NEMA) standards make premium
efficiency motors the baseline efficiency level, savings remain available from upgrading to still
more efficient levels.
Office equipment, exterior lighting, and industrial process improvements offer smaller
but still significant realistic achievable potential by 2032 at 73,152 MWh, 68,467 MWh, and
60,759 MWh respectively.
Savings from commercial refrigeration, food preparation, and water heating are
relatively small across the C&I sector as a whole, though these end uses can offer significant
savings in supermarkets, restaurants, hospitals, and other buildings where these end use
constitute a larger portion of overall energy use.
Table ES-9 Energy Efficiency Potential, Commercial and Industrial Sector
2012 2017 2022 2027 2032
Baseline Forecast (MWh) 5,172,344 5,592,586 6,061,107 6,618,022 7,250,973
Cumulative Energy Savings (MWh)
Realistic Achievable 24,155 267,535 608,739 932,205 1,258,101
Maximum Achievable 52,460 606,406 1,153,644 1,452,022 1,712,907
Economic 140,180 910,181 1,443,612 1,749,278 2,013,333
Technical 176,414 1,168,096 1,967,434 2,424,630 2,739,507
Cumulative Energy Savings (% of Baseline)
Realistic Achievable 0.5% 4.8% 10.0% 14.1% 17.4%
Maximum Achievable 1.0% 10.8% 19.0% 21.9% 23.6%
Economic 2.7% 16.3% 23.8% 26.4% 27.8%
Technical 3.4% 20.9% 32.5% 36.6% 37.8%
Peak Savings (MW)
Realistic Achievable 4 40 84 127 169
Maximum Achievable 8 88 154 191 223
Economic 22 130 193 231 263
Technical 27 166 262 324 364
Peak Savings (% of Baseline)
Realistic Achievable 0.5% 4.7% 9.0% 12.4% 15.1%
Maximum Achievable 1.0% 10.3% 16.6% 18.8% 20.0%
Economic 2.7% 15.3% 20.8% 22.7% 23.6%
Technical 3.4% 19.4% 28.2% 31.8% 32.6%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 810 of 1069
Avista Conservation Potential Assessment Study Executive Summary
xx www.gepllc.com

Sensitivity of Potential to Avoided Costs
Global modeled several scenarios with varying levels of avoided costs in addition to the base
case. The other scenarios included 150%, 125%, and 75% of the avoided costs used in the base
case. Figure ES -11 shows how realistic achievable potential varies under the four scenarios. The
base case realistic achievable potential is approximately 16.4% of the baseline forecast by 2032.
With the 150% avoided cost case, realistic achievable potential increased to 19.2% of the
baseline forecast, while the 125% avoided cost case and the 75% avoided cost case yielded
realistic achievable potential equal to 18.1% and 13.2% of the baseline forecast respectively.
While the changes are significant, the relationship between avoided cost and realistic achievable
potential is not linear and increases in avoided costs do not provide equivalent percentage
increases in realistic achievable potential. Technical potential imposes a limit on the amount of
additional conservation and each incremental unit of conservation becomes increasingly
expensive.
Figure ES -11 Energy Savings, Economic Potential Case by Avoided Costs Scenario
(MWh)

The project developed a series of supply curves based on the four avoided cost scenarios, shown
in Figure ES -12. Each supply curve is created by stacking measures and equipment over the 20-
year planning horizon in ascending order of cost. As expected, this stacking of conservation
resources produces a traditional upward-sloping supply curve. The 75% of avoided cost scenario
provides roughly a 13% reduction in energy use compared with the baseline forecast in 2032, at
a cost of $0.05/kWh or less. The other three scenarios track one another closely, providing just
over 15% savings in 2032 at costs below $0.05/kWh.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 811 of 1069
Executive Summary Avista Conservation Potential Assessment Study
Global Energy Partners xxi
An EnerNOC Company
Figure ES -12 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios

Sensitivity of Potential to Customer and Economic Growth
This conservation potential assessment shows that conservation offsets roughly 50% of growth
in electrical energy use for the Avista system, whereas the Sixth Plan projects that conservation
can offset 80% of growth. Of course, Avista’s service territory differs from the region overall in
many ways, including its climate. Another significant factor may be the CPA study’s assumptions
regarding customer and economic growth. To better understand how growth affects the study’s
results, the project team evaluated scenarios with lower customer and economic growth, as
indicated in Table ES-10.
Table ES-10 Varying Growth Scenario Descriptions
Reference
Scenario
Low Growth
Scenario 1
Low Growth
Scenario 2
Home size ~ 1% per year growth Capped at 110% of
existing home size
Capped at 110% of existing
home size
Per capita income growth
1.6% 2011–2015;
2.2% 2016–2020;
2.1% thereafter
1.6% after 2016 1.6% after 2016
Residential sector market
growth
1.30% after 2015 (WA)
1.25% after 2015 (ID) no change 1.0% after 2015 (WA & ID)
Commercial sector
market growth, WA & ID
~ 2.0% (varies by
segment) no change 1.0% all segments

Table ES -11 shows that as economic and customer growth decreases, the ability of conservation
to offset growth increases. In the reference scenario, energy efficiency offsets 52% of growth in
consumption, while in the lower growth scenarios, EE offsets 54% and 76% of growth
respectively. This is the case because with reduced new construction, load growth and
achievable potential drop, but savings due to the retrofit of existing buildings constitute a greater
proportion of load growth.
$0.00
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$0.10
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∆ Portfolio average cost for each scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 812 of 1069
Avista Conservation Potential Assessment Study Executive Summary
xxii www.gepllc.com

Table ES -11 Varying Growth Scenario Results
Reference
Scenario
Low Growth
Scenario 1
Low Growth
Scenario 2
Baseline forecast 2012 (MWh) 8,799,039 8,799,039 8,799,033
Baseline forecast 2032 (MWh) 12,851,760 12,523,843 11,178,008
Load growth 2012-2032 (MWh) 4,052,720 3,724,803 2,378,975
Realistic achievable potential forecast
2032 (MWh) 10,745,176 10,500,088 9,366,471
Realistic achievable potential savings 2032
(MWh) 2,106,584 2,023,754 1,811,538
Percentage of growth offset 52% 54% 76%
Note: Value of 2,106,548 MWh for 2032 realistic achievable potential was based on interim results and thus
is different from the value shown elsewhere in this report.
Pumping Potential
As displayed in Table ES -12, pumping accounts represent 2.2% of Avista’s total electricity sales
and 0.8% of peak demand. Because pumping represents a relatively small percentage of Avista’s
total sales, the project team decided to use the NWPCC Sixth Plan calculator to estimate
pumping energy efficiency potential.
Table ES -12 Pumping Rate Classes, Electricity Sales and Peak Demand 2009
Sector
Rate
Schedule(s)
Number of meters
(customers)
2009 Electricity
sales (MWh)
Peak demand
(MW)
Pumping, Washington 031, 032 2,361 135,999 10
Pumping, Idaho 031, 032 1,312 58,885 4
Pumping, Total 3,673 194,884 14
Percentage of System Total 2.2% 0.8%

The Sixth Plan Calculator estimates agricultural conservation targets through 2019, based on
2007 sales. We trended the data through 2022 to provide annual savings estimates for the ten-
year period 2012–2022, with the results provided in Table ES -13 and Table ES -14.
Table ES -13 Sixth Plan Calculator Agriculture Incremental Annual Potential, Selected
Years (MWh)
Segment 2012 2013 2014 2015
Pumping, Washington 1,567 1,484 1,402 1,835
Pumping, Idaho 690 654 618 809
Pumping, Total 2,257 2,138 2,020 2,643
Table ES -14 Sixth Plan Calculator Agriculture Cumulative Potential, Selected Years
(MWh)
Measure 2012 2017 2022
Pumping, Washington 1,567 9,979 18,892
Pumping, Idaho 690 4,397 8,324
Pumping, Total 2,257 14,375 27,217

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 813 of 1069
Executive Summary Avista Conservation Potential Assessment Study
Global Energy Partners xxiii
An EnerNOC Company
Report Organization
The body of the report is organized as follows:
Chapter 1, Introduction
Chapter 2, Study Approach for Energy Efficiency Analysis
Chapter 3, Market Assessment and Market Profiles
Chapter 4, Baseline Forecast
Chapter 5, Energy Efficiency Measure Analysis
Chapter 6, Energy Efficiency Potential Results
Appendix A, Washington Results
Appendix B, Idaho Results
Appendix C, Residential Energy Efficiency Equipment and Measure Data
Appendix D, Commercial Energy Efficiency Equipment and Measure Data
Appendix E, Study References
Results of the demand response analysis and the natural gas potential assessment will be
presented in separate forthcoming documents.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 814 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 815 of 1069

Global Energy Partners xxv
An EnerNOC Company
CONTENTS
EXECUTIVE SUMMARY
1 INTRODUCTION .................................................................................................... 1-1
1.1 Background ......................................................................................... 1-1
1.2 Objectives ........................................................................................... 1-1
1.3 Report Organization ............................................................................. 1-2
2 STUDY APPROACH FOR ENERGY EFFICIENCY ANALYSIS .................................... 2-1
2.1 Market Assessment and Market Profiles .................................................. 2-2
2.2 Baseline Forecast ................................................................................. 2-4
2.2.1 Modeling Approach .................................................................... 2-5
2.3 Energy Efficiency Measures Analysis ...................................................... 2-6
2.4 Assessment of Energy-Efficiency Potential .............................................. 2-7
2.4.1 Modeling Approach .................................................................... 2-8
3 MARKET ASSESSMENT AND MARKET PROFILES .................................................. 3-1
3.1 Residential Sector ................................................................................. 3-2
3.1.1 Market Characterization ............................................................. 3-3
3.1.2 Residential Market Profiles .......................................................... 3-5
3.2 Commercial and Industrial Sectors ......................................................... 3-8
3.2.1 C&I Market Characterization ....................................................... 3-8
3.2.2 C&I Market Profiles .................................................................... 3-9
4 BASELINE FORECAST ............................................................................................ 4-1
4.1 Residential Sector ................................................................................. 4-1
4.1.1 Residential Baseline Forecast Drivers ........................................... 4-1
4.1.2 Residential Baseline Forecast Results........................................... 4-2
4.2 Commercial and Industrial Sector .......................................................... 4-7
4.2.1 C&I Baseline Forecast Drivers ..................................................... 4-7
4.2.2 C&I Baseline Forecast Results ..................................................... 4-8
4.3 Baseline Forecast Summary.................................................................. 4-12
4.3.1 Comparison of Baseline Forecast with Avista 2009 IRP ................. 4-13
5 ENERGY-EFFICIENCY MEASURE ANALYSIS .......................................................... 5-1
5.1 Selection of Energy Efficiency Measures ................................................. 5-1
5.1.1 Residential Measures ................................................................. 5-2
5.1.2 Commercial and Industrial Measures ........................................... 5-2
5.2 Measure Characteristics ....................................................................... 5-12
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 816 of 1069

xxvi www.gepllc.com

5.2.1 Measure Cost Data Development ............................................... 5-13
5.2.2 Representative Measure Data Inputs ......................................... 5-13
5.2.3 Conversion to Natural Gas ........................................................ 5-14
5.3 Application of measures for technical potential ...................................... 5-15
5.4 Application of measures for Economic Potential ..................................... 5-15
5.4.1 Equipment Measures Economic Screening .................................. 5-17
5.4.2 Non-equipment Measures Economic Screening ........................... 5-18
5.5 Total Measures Evaluated .................................................................... 5-18
6 ENERGY EFFICIENCY POTENTIAL RESULTS ......................................................... 6-1
6.1 DefInitions of Potential .......................................................................... 6-1
6.2 Overall Energy Efficiency Potential ......................................................... 6-1
6.3 Residential Sector ................................................................................. 6-6
6.3.1 Residential Potential by Market Segment ...................................... 6-7
6.3.2 Residential Potential by End Use, Technology, and Measure Type .. 6-9
6.4 Commercial and Industrial Sector Potential ........................................... 6-14
6.4.1 Commercial Potential by Market Segment and State.................... 6-16
6.4.2 C&I Potential by End Use, Technology, and Measure Type .......... 6-17
6.5 Sensitivity Analysis .............................................................................. 6-23
6.5.1 Sensitivity of Potential to Avoided Cost ...................................... 6-23
6.5.2 Sensitivity of Potential to Customer and Economic Growth ........... 6-24
6.6 Pumping Potential............................................................................... 6-25

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 817 of 1069

Global Energy Partners xxvii
An EnerNOC Company
LIST OF FIGURES
Figure ES-1 Analysis Approach Overview vi
Figure ES-2 Residential Electricity Use by End Use per Household, 2009 (kWh and %) viii
Figure ES-3 Residential Baseline Forecast by End Use viii
Figure ES-4 Commercial and Industrial Electricity Consumption by End Use, 2009 x
Figure ES-5 C&I Baseline Electricity Forecast by End Use x
Figure ES-6 Baseline Forecast Summary by Sector and State xi
Figure ES-7 Energy Efficiency Potential Forecasts, All Sectors xiii
Figure ES-8 Summary of Energy Efficiency Potential Savings, All Sectors xiv
Figure ES-9 Realistic Achievable Cumulative Potential by Sector xv
Figure ES-10 Incremental Annual Realistic Achievable Energy-efficiency (MWh) vs. Avoided
Energy Cost xvi
Figure ES -11 Energy Savings, Economic Potential Case by Avoided Costs Scenario (MWh) xx
Figure ES -12 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios xxi
Figure 2-1 Analysis Approach Overview 2-1
Figure 2-2 LoadMAP Baseline and Potential Modeling 2-9
Figure 3-1 Electricity Sales by Rate Class, Washington 2009 3-2
Figure 3-2 Electricity Sales by Rate Class, Idaho 2009 3-2
Figure 3-3 Residential Sector Allocation by Segments, Percentage of Customers 3-3
Figure 3-4 Residential Electricity Use by Customer Segment, Percentage of Sales 2009 3-4
Figure 3-5 Residential Electricity Use by End Use per Household, 2009 (kWh and %) 3-6
Figure 3-6 End-Use Shares of Total Electricity Use by Housing Type, 2009 3-8
Figure 3-7 Commercial and Industrial Electricity Consumption by End Use, 2009 3-10
Figure 3-8 Commercial End Use Consumption, 2009 3-11
Figure 3-9 Extra Large Industrial End Use Consumption, 2009 3-11
Figure 4-1 Residential Baseline Forecast by End Use 4-3
Figure 4-2 Residential Baseline Electricity Use per Household by End Use 4-4
Figure 4-3 C&I Baseline Electricity Forecast by End Use 4-8
Figure 4-4 Baseline Forecast Summary by Sector and State 4-12
Figure 5-1 Approach for Measure Assessment 5-1
Figure 5-2 Avoided Costs for Energy and Capacity 5-17
Figure 6-1 Summary of Energy Efficiency Potential Savings, All Sectors 6-2
Figure 6-2 Energy Efficiency Potential Forecasts, All Sectors 6-2
Figure 6-3 Realistic Achievable Cumulative Potential by Sector 6-4
Figure 6-4 Incremental Annual Realistic Achievable Energy-efficiency (MWh) vs. Avoided
Energy Cost 6-5
Figure 6-5 Energy Efficiency Potential Savings, Residential Sector 6-6
Figure 6-6 Energy Efficiency Potential Forecast, Residential Sector 6-6
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 818 of 1069

xxviii www.gepllc.com

Figure 6-7 Residential Realistic Achievable Potential by End Use, Selected Years 6-11
Figure 6-8 Energy Efficiency Potential Savings, Commercial and Industrial Sector 6-14
Figure 6-9 Energy Efficiency Potential Forecast, Commercial and Industrial Sector 6-15
Figure 6-10 C&I Realistic Achievable Potential by End Use, Selected Years 6-19
Figure 6-11 Energy Savings, Economic Potential Case by Avoided Costs Scenario (MWh) 6-23
Figure 6-12 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios 6-24
Figure 6-13 Sixth Plan Calculator Agriculture Incremental Annual Potential 6-26

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 819 of 1069

Global Energy Partners xxix
An EnerNOC Company
LIST OF TABLES
Table ES-1 Residential Electricity Usage and Intensity by Segment and State, 2009 vii
Table ES-2 Commercial Sector Market Characterization Results, Washington 2009 ix
Table ES-3 Commercial Sector Market Characterization Results, Idaho 2009 ix
Table ES-4 Baseline Forecast Summary by Sector and State xi
Table ES-5 Summary of Energy Efficiency Potential, All Sectors xiv
Table ES-6 Realistic Achievable Cumulative Energy-efficiency Potential by Sector, MWh xv
Table ES-7 Incremental Annual Realistic Achievable Energy-efficiency Potential by Sector,
MWh xv
Table ES-8 Energy Efficiency Potential, Residential Sector xvii
Table ES-9 Energy Efficiency Potential, Commercial and Industrial Sector xix
Table ES-10 Varying Growth Scenario Descriptions xxi
Table ES -11 Varying Growth Scenario Results xxii
Table ES -12 Pumping Rate Classes, Electricity Sales and Peak Demand 2009 xxii
Table ES -13 Sixth Plan Calculator Agriculture Incremental Annual Potential, Selected Years
(MWh) xxii
Table ES -14 Sixth Plan Calculator Agriculture Cumulative Potential, Selected Years (MWh) xxii
Table 2-1 Segmentation Framework for Electricity 2-2
Table 2-2 Data Needs for the Market Profiles 2-3
Table 2-3 Data Needs for the Baseline Forecast and Potentials Estimation in LoadMAP 2-6
Table 3-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009 3-1
Table 3-2 Electricity Use and Peak Demand by Rate Class, Idaho 2009 3-1
Table 3-3 Residential Sector Allocation by Segments 3-3
Table 3-4 Residential Electricity Usage and Intensity by Segment and State, 2009 3-4
Table 3-5 Average Residential Sector Market Profile 3-7
Table 3-6 Commercial Sector Market Characterization Results, Washington 2009 3-9
Table 3-7 Commercial Sector Market Characterization Results, Idaho 2009 3-9
Table 3-8 Small/Medium Commercial Segment Market Profile, Washington, 2009 3-12
Table 4-1 Residential Market Size Forecast (number of households) 4-1
Table 4-2 Residential Baseline Forecast Electricity Consumption by End Use (MWh) 4-5
Table 4-3 Residential Baseline Electricity Forecast by End Use and Technology (MWh) 4-6
Table 4-4 Commercial Market Size Growth and Electricity Price Forecast 4-7
Table 4-5 C&I Electricity Consumption by End Use (MWh) 4-9
Table 4-6 C&I Baseline Electricity Forecast by End Use and Technology (MWh) 4-10
Table 4-7 Baseline Forecast Summary by Sector and State 4-12
Table 4-8 Comparison of LoadMAP Baseline, Avista IRP, and Sixth Plan Energy Forecasts
(MWh) 4-13
Table 4-9 Comparison of Retail Electricity Prices 4-13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 820 of 1069

xxx www.gepllc.com

Table 5-1 Summary of Residential Equipment Measures 5-3
Table 5-2 Summary of Residential Non-equipment Measures 5-5
Table 5-3 Summary of Commercial and Industrial Equipment Measures 5-6
Table 5-4 Summary of Commercial and Industrial Non-equipment Measures 5-10
Table 5-5 Sample Equipment Measures for Central Air Conditioning — Single Family
Home Segment 5-13
Table 5-6 Sample Non-Equipment Measures – Single Family Homes, Existing 5-14
Table 5-7 Sample Non-Equipment Water Heating Measures – Single Family Homes,
Existing, Washington 5-15
Table 5-8 Economic Screen Results for Selected Residential Equipment Measures 5-18
Table 5-9 Number of Measures Evaluated 5-18
Table 6-1 Summary of Energy Efficiency Potential, All Sectors 6-3
Table 6-2 Realistic Achievable Cumulative Energy-efficiency Potential by Sector, MWh 6-3
Table 6-3 Incremental Annual Realistic Achievable Energy-efficiency Potential by Sector,
MWh 6-4
Table 6-4 Energy Efficiency Potential, Residential Sector 6-7
Table 6-5 Residential Sector, Baseline and Realistic Achievable Potential by Segment 6-8
Table 6-6 Residential Realistic Achievable Potential by Housing Type, 2022 6-8
Table 6-7 Residential Cumulative Savings by End Use and Potential Type (MWh) 6-10
Table 6-8 Residential Potential by End Use and Market Segment, 2022 (MWh) 6-11
Table 6-9 Residential Cumulative Realistic Achievable Potential by End Use and
Equipment Measures, Selected Years (MWh) 6-12
Table 6-10 Residential Realistic Achievable Savings from Conversion to Natural Gas (MWh)6-12
Table 6-11 Residential Realistic Achievable Savings for Non-equipment Measures (MWh),
Selected Years 6-13
Table 6-12 Energy Efficiency Potential, Commercial and Industrial Sector 6-15
Table 6-13 C&I Sector, Baseline and Realistic Achievable Potential by Segment 6-16
Table 6-14 C&I Realistic Achievable Potential by Segment, 2022 6-16
Table 6-15 C&I Cumulative Savings by End Use and Potential Type, Selected Years, (MWh)6-18
Table 6-16 C&I Realistic Achievable Potential by End Use and Market Segment, 2022
(MWh) 6-19
Table 6-17 C&I Cumulative Realistic Achievable Potential by End Use and Equipment
Measures, Selected Years (MWh) 6-20
Table 6-18 C&I Cumulative Realistic Achievable Savings for Non-equipment Measures,
Selected Years (MWh) 6-21
Table 6-19 Realistic Achievable Potential with Varying Avoided Costs 6-24
Table 6-20 Varying Growth Scenario Descriptions 6-25
Table 6-21 Varying Growth Scenario Results 6-25
Table 6-22 Pumping Rate Classes, Electricity Sales and Peak Demand 2009 6-26
Table 6-23 Sixth Plan Calculator Agriculture Incremental Annual Potential, Selected Years
(MWh) 6-26
Table 6-24 Sixth Plan Calculator Agriculture Cumulative Potential, Selected Years (MWh) 6-27

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 821 of 1069

Global Energy Partners, LLC 1-1
An EnerNOC Company
CHAPTER 1

INTRODUCTION
1.1 BACKGROUND
Avista Corporation (Avista) engaged Global Energy Partners (Global) to conduct a Conservation
Potential Assessment (CPA) Study. The CPA is a 20-year potentials study for energy efficiency
(EE) and demand response (DR) to provide data on demand-side resources for developing
Avista’s 2011 Integrated Resource Plan (IRP), and in accordance with Washington I -937. The
study used 2009, the first year for which complete billing data was available, as the baseline year
and then developed potential estimates for the period 2012-2032. Although the final report will
address electricity and natural gas, this interim report provides results of the electricity potential
study only.
1.2 OBJECTIVES
Key objectives for the study include:
Conduct a conservation potential study for electricity for Washington and Idaho, and natural
gas for Washington, Idaho, and Oregon. The study will account for:
o Impacts of existing Avista conservation programs
o Avista’s load forecasts and load shapes
o Impacts of codes and standards
o Technology developments and innovation
o The economy and energy prices
o Naturally occurring energy savings
Assess and analyze cost-effective EE and DR potentials in accordance with the Northwest
Power and Conservation Council’s (NWPPC) 6th Power Plan and Washington I-937
requirements.
Obtain supply curves showing the incremental costs associated with achieving higher levels
of EE and DR and stacking EE and DR resources by cost of conserved energy.
Analyze various market penetration rates associated with technical, economic, achievable,
and naturally occurring potential estimates.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 822 of 1069
Introduction Avista Conservation Potential Assessment Study
1-2 www.gepllc.com

1.3 REPORT ORGANIZATION
The remainder of this report presents the results of the electricity conservation potential
assessment for Avista’s Washington and Oregon service territory. In most cases, results for
Avista’s overall electric system are presented in the body of the report, and Washington- and
Oregon-specific results are presented in Appendices A and B respectively. The report is organized
as follows:
Chapter 2, Study Approach for Energy Efficiency Analysis
Chapter 3, Market Assessment and Market Profiles
Chapter 4, Baseline Forecast
Chapter 5, Energy Efficiency Measure Analysis
Chapter 6, Energy Efficiency Potential Results
Appendix A, Washington Results
Appendix B, Idaho Results
Appendix C, Residential Energy Efficiency Equipment and Measure Data
Appendix D, Commercial Energy Efficiency Equipment and Measure Data
Appendix E, Study References

Results of the demand response analysis and the natural gas potential assessment will be
presented in separate forthcoming documents.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 823 of 1069

Global Energy Partners, LLC 2-1
An EnerNOC Company
CHAPTER 2
STUDY APPROACH FOR ENERGY EFFICIENCY ANALYSIS
To execute this project, Global took the following steps, which are also shown in Figure 2-1.
1. Performed a market assessment to describe base year energy consumption for the residential
and C&I sectors. This included using utility data and secondary data to understand customers
in Avista’s service territory and how these customers currently use electricity. Based on the
market assessment, we developed energy market profiles for the study’s base year, 2009.
2. Developed a baseline energy forecast by sector and end use for the twenty-year study
period.
3. Identified and analyzed energy-efficiency measures appropriate for the Avista service area.
4. Estimated four levels of energy-efficiency potential, Technical, Economic, Maximum
Achievable, and Realistic Achievable.
The steps are described in further detail throughout the remainder of this section.
Figure 2-1 Analysis Approach Overview

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 824 of 1069
Study Approach For Energy Efficiency Analysis Avista Conservation Potential Assessment Study
2-2 www.gepllc.com

2.1 MARKET ASSESSMENT AND MARKET PROFILES
It is absolutely critical to develop a good understanding of where Avista is today in terms of
energy use and customer behavior before developing projections of potential EE savings. The
purpose of the market assessment is to develop market profiles that describe current electricity
use in terms of sector, customer segment, and end use. The base year for this study is 2009, the
most recent year for which complete billing data was available at the start of the study.
We began the market assessment by defining the market segments (building types, end uses
and other dimensions) that are relevant in the Avista service territory. The segmentation scheme
employed for this project, as presented in Table 2-1, is based on Avista rate schedules. For the
pumping rate classes, we determined to use the Northwest Power and Conservation Council
(NWPCC) Sixth Plan calculator to determine future EE potential.
Table 2-1 Segmentation Framework for Electricity
Market
Dimension
Segmentation
Design Dimension Examples
Dimension 1 Geographic Region Washington, Idaho
Dimension 2 Sector / Rate Class Residential — Rate Class 001
C&I General Service — Rate Class 011, 012
C&I Large General Service — Rate Classes 021, 022
Comm. Extra Large General Service — Rate Class 025
Ind. Extra Large General Service — Rate Classes 025, 025P
Pumping — Rate Classes 030, 031, 032
Dimension 3 Building Type Residential: single-family, multi-family, mobile home, limited income
No further segmentation of C&I and pumping, except for XLarge
General Service, which was divided into commercial and industrial
segments
Dimension 4 Vintage Existing and new construction (as appropriate for residential and
commercial sectors)
Dimension 5 End Uses Cooling, lighting, water heat, motors, etc. (as appropriate by sector)
Dimension 6 Appliances/End
Uses and
Technologies
Cooling, lighting, water heat, motors, etc. (as appropriate by sector);
Technologies such as types of lamps, chillers, color TVs, etc.
Dimension 7 Equipment
Efficiency Levels
Old, Standard (minimum standard), Maximum Efficiency

With the segmentation scheme defined, we set out to populate the market profiles. The first step
was to identify the electricity sales in the base year for each segment using Avista’s 2009
historical customer billing data by rate class. In order to further divide the residential sector, we
relied upon regional demographic and economic data from secondary sources (see below).
Then, we developed the data for the remaining market profile elements, which include market
size, annual electricity use, electric appliance and equipment saturations, technology shares, and
end-use consumption estimates (unit energy consumption or UEC for residential customers and
energy use index or EUI for C&I customers). We calibrated the elements of the market profile for
each segment to match the segment and sector-level sales we developed in the previous step.
We developed market profiles for the entire existing market, as well as new construction in each
segment.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 825 of 1069
Avista Conservation Potential Assessment Study Study Approach For Energy Efficiency Analysis
Global Energy Partners, LLC 2-3
An EnerNOC Company
While this study did not involve any primary market research, a wealth of primary data is
available for the Pacific Northwest region from NEEA and a recent customer saturation survey
from Inland Power and Light, a neighboring utility. In addition, data were available from a
residential survey conducted as part of Inland Power’s December 2009 CPA. We used these
sources together with other secondary data, including the Energy Information Agency’s
Residential Energy Consumption Survey (RECS), the Annual Energy Outlook (AEO), th e
California’s Residential Appliance Saturation Survey (RASS), and the California Commercial End
Use Survey (CEUS), to develop the market profiles.
In addition to information about annual electricity use, we also needed estimates of peak
demand by segment and end use in order to calculate peak-demand savings from EE measures.
We developed a set of peak factors, factors that represent the fraction of annual energy use that
occurs during the peak hour, and apply them to annual electricity use to calculate peak demand
by end use. Peak factors for this study were developed for each sector, customer segment and
end use using Global’s EnergyShapeTM database and information from Avista regarding its load
shapes and peak demand.2
Table 2-2 summarizes the data required for the market profiles. This information is required for
each segment within each sector, as well as for new construction and existing
dwellings/buildings. Additional details regarding sources appear in Appendix E.
Table 2-2 Data Needs for the Market Profiles
Model Inputs Description Key Sources
Base-year data
Market size Base-year residential dwellings and
C&I floor space Avista billing data, NEEA Reports
Appliance/equipment
saturations
Fraction of dwellings with an
appliance/technology;

Percentage of C&I floor space with
equipment/technology
NEAA reports, Inland Power & Light
residential saturation survey, RECS,
and other secondary data
UEC/EUI for each end-
use technology
UEC: Annual electricity use for a
technology in dwelling that have the
technology;

EUI: Annual electricity use per square
foot for a technology in floor space
that has the technology
NEAA reports, RASS, CEUS,
engineering analysis, prototype
simulations, engineering analysis
Appliance/equipment
vintage distribution Age distribution for each technology NEEA reports, RASS, CEUS, secondary
data (DEEM, EIA, EPRI, DEER, etc.)
Efficiency options for
each technology
List of available efficiency options and
annual energy use for each technology
Prototype simulations, engineering
analysis, appliance/equipment
standards, secondary data (DEEM,
EIA, EPRI, DEER, etc.)
Peak factors Share of technology energy use that
occurs during the peak hour
Avista data; Global’s EnergyShape
database

The quality of data inputs is critical. To ensure the best results, we pursued the following course
during the data-development process.

2 The peak factors were used to compute peak demand savings only and they were not used to develop a stand-alone peak-demand
forecast.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 826 of 1069
Study Approach For Energy Efficiency Analysis Avista Conservation Potential Assessment Study
2-4 www.gepllc.com

1. Used NEEA reports, the Inland Power & Light survey of its residential customers, and RECS
to provide information about market size for customer segments, appliance and equipment
saturations, appliance and equipment characteristics, UECs, building characteristics,
customer behavior, operating characteristics, and energy-efficiency actions already taken.
2. Incorporated secondary data sources to supplement and corroborate the research in items 1
and 2 above.
3. Compared and cross-checked with data obtained as part of other northwest utility studies,
the EPRI National Potential Study, and other regional sources.
4. Ensured calibration to control totals such as total usage values by segment, available through
the billing data.
5. Worked with the Avista staff and the extended project team to vet the data against their
knowledge and experience.
The market assessment, market segmentation, and resulting market profiles are presented in
Chapter 3.
2.2 BASELINE FORECAST
The next step of the energy efficiency potential study was to develop the baseline forecast which
is the metric against which savings from energy-efficiency measures are compared. The baseline
case forecasts annual electricity use and peak demand by customer segment and end use under
a ―business as usual‖ (without new utility programs) scenario for the 20-year planning horizon
starting in 2012. This process is crucial as it allows for projections to be determined in the
absence of future conservation programs. This puts the changes in market conditions and
customer potentials estimates in context of total energy use in the future and also allows us to
project where the energy-efficiency savings will come from. The end-use forecast also includes
the expected impacts of codes and standards, which affect what is possible through utility
programs. Given the recent extensive attention to energy efficiency at the national level through
Smart Grid and American Reinvestment and Recovery Act (ARRA) stimulus efforts and
promulgated through the implementation of more stringent codes and standards both nationally
and in local jurisdictions, we have taken steps in our modeling framework to capture the effects
of market influences in our baseline forecast assessments. This is an important issue for this
study, as the adoption of future codes and standards will have a direct bearing on how much
utility program EE potential there can be over and above the effects of those efforts. This study
includes standards in effect as of late 2010, which were not taken into account during the
development of the Sixth Plan.
Inputs to the baseline forecast include:
Current economic growth forecasts
New construction forecasts
Appliance and equipment standards
Existing and approved changes to building codes and standards
Forecasted changes in fuel share and equipment saturation
The (future) effects of utility programs offered prior to 2010
Avista’s electricity price and sales forecasts

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 827 of 1069
Avista Conservation Potential Assessment Study Study Approach For Energy Efficiency Analysis
Global Energy Partners, LLC 2-5
An EnerNOC Company
2.2.1 Modeling Approach
We used the Load Management Analysis and Planning tool (LoadMAPTM) to develop the baseline
forecast, as well as forecasts of energy-efficiency potential. Global developed LoadMAP in 2007
and has used it for the EPRI National Potential Study and numerous utility-specific forecasting
and potential studies. Built in Excel, the LoadMAP framework is both accessible and transparent
and has the following key features.
Embodies the basic principles of rigorous end-use models (such as EPRI’s REEPS and
COMMEND) but in a more simplified, accessible form.
Includes stock-accounting algorithms that treat older, less efficient appliance/equipment
stock separately from newer, more efficient equipment. Equipment is replaced according to
the measure life defined by the user.
Balances the competing needs of simplicity and robustness by incorporating important
modeling details related to equipment saturations, efficiencies, vintage, and the like, where
market data are available, and treats end uses separately to account for varying importance
and availability of data resources.
Isolates new construction from existing equipment and buildings and treats purchase
decisions for new construction, replacement upon failure, early replacement, and non-owner
acquisition separately.
Uses a simple logic for appliance and equipment decisions. Other models available for this
purpose embody complex decision choice algorithms or diffusion assumptions, and the model
parameters tend to be difficult to estimate or observe and sometimes produce anomalous
results that require calibration or even overriding. The LoadMAP approach allows the user to
drive the appliance and equipment choices year by year directly in the model. This flexible
approach allows users to import the results from diffusion models or to input individual
assumptions. The framework also facilitates sensitivity analysis.
Includes appliance and equipment models customized by end use. For example, the logic for
lighting equipment is distinct from refrigerators and freezers.
Can accommodate various levels of segmentation. Analysis can be performed at the sector
level (e.g., total residential) or for customized segments within sectors (e.g., housing type or
income level).
Consistent with the segmentation scheme and the market profiles we describe above, the
LoadMAP model provides forecasts of baseline energy use by sector, segment, end use and
technology for existing and new buildings. It provides forecasts of total energy use and energy-
efficiency savings associated with the four types of potential. It also provides forecasts of peak-
demand savings for each type of potential.3
Table 2-3 summarizes the LoadMAP model inputs required for the baseline forecast. These inputs
are required for each segment within each sector, as well as for new construction and existing
dwellings/buildings.

3 The model computes a peak-demand forecast for each type of potential for each end use as an intermediate calculation. Peak-
demand savings are calculated as the difference between the peak-demand value in the potential forecast (e.g., technical potential)
and the peak-demand value in the baseline forecast.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 828 of 1069
Study Approach For Energy Efficiency Analysis Avista Conservation Potential Assessment Study
2-6 www.gepllc.com

Table 2-3 Data Needs for the Baseline Forecast and Potentials Estimation in LoadMAP
Model Inputs Description Key Sources
Customer growth
forecasts
Forecasts of new construction in
residential and C&I sectors
Avista 2009 IRP, Sixth Power Plan,
Regional census data
Equipment purchase
shares for baseline
forecast
For each equipment/technology,
purchase shares for each efficiency
level; specified separately for
equipment replacement (replace-on-
burnout), non-owner acquisition, and
new construction
Shipments data, AEO forecast
assumptions, appliance/efficiency
standards analysis
Electricity prices Forecast of average electricity prices Avista price forecast data
Utilization model
parameters
Price elasticities, elasticities for other
variables (income, weather)
EPRI’s REEPS and COMMEND models;
Avista forecasting data

We present the results of the baseline forecast development in Chapter 4. As with the
development of the market profiles, we reviewed the baseline forecast results with the Avista
staff.
2.3 ENERGY EFFICIENCY MEASURES ANALYSIS
The framework for assessing savings, costs, and other attributes of energy-efficiency measures
involves identifying the list of measures to include in the analysis, determining their applicability
to each market sector and segment, fully characterizing each measure, and performing cost-
effectiveness screening. Potential measures include the replacement of a unit that has failed or is
at the end of its useful life with an efficient unit, retrofit/early replacement of equipment,
improvements to the building envelope and other actions resulting in improved energy efficiency,
and the application of controls to optimize energy use.
We compiled a robust listing of energy efficiency measures for each customer sector, drawing
upon a variety of secondary sources:
The Sixth Power Plan database of EE measure costs and savings
NEEA’s Regional Technical Forum
Database for Energy Efficient Resources (DEER). The California Energy Commission and
California Public Utilities Commission (CPUC) sponsor this database, which is designed to
provide well-documented estimates of energy and peak demand savings values, measure
costs, and effective useful life (EUL) all with one data source for the state of California.
Global’s Database of Energy Efficiency Measures (DEEM). In 2004, Global prepared a
database of energy efficiency measures for residential and commercial segments across the
U.S. This is analogous to the DEER database developed for California. Global updates the
database on a regular basis as it conducts new energy efficiency potential studies.
EPRI National Potential Study (2009). In 2009, Global conducted an assessment of the
national potential for energy efficiency, with estimates derived for the four DOE regions
(including the Pacific region that includes California).
Based on this compilation of information, Global assembled a broad and inclusive universal list of
EE measures, covering all major types of end-use equipment, as well as devices and actions to
reduce energy consumption. If considered today, many of these measures would not pass the
economic screens, but may ultimately be part of Avista’s EE program portfolios.
Once we assembled the list of EE measures, the project team assessed their energy-saving
characteristics. For energy-saving measures not already specified in the databases above, we
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 829 of 1069
Avista Conservation Potential Assessment Study Study Approach For Energy Efficiency Analysis
Global Energy Partners, LLC 2-7
An EnerNOC Company
used Global’s Building Energy Simulation Tool (BEST), a derivative of the DOE 2.2 building
simulation model, to estimate measure savings. We used building prototypes for the Northwest
region to estimate energy savings.
For each measure we also characterized incremental cost, service life, and other performance
factors. Following the measure characterization, we performed an economic screening of each
measure, which serves as the basis for developing the economic potential.
We provide further descriptions of EE measures analysis and the economic screening process in
Chapter 5.
2.4 ASSESSMENT OF ENERGY-EFFICIENCY POTENTIAL
A key objective of this study is to estimate the potential for energy savings through energy
efficiency activities in the Avista electric service territory. The potential impact of EE activities is
the cumulative total of all energy-related projects.
The approach we used for this study adheres to the approaches and conventions outlined in the
National Action Plan for Energy-Efficiency (NAPEE) Guide for Conducting Potential Studies
(November 2007).4 The NAPEE Guide represents the most credible and comprehensive industry
practice for specifying energy-efficiency potential. Specifically, four types of potentials were
developed as part of this study.
Technical potential is calculated by applying the most efficient option commercially available
to each purchase decision, regardless of cost. It is a theoretical case that provides the broadest
and highest definition of savings potential since it quantifies the savings that would result if all
current equipment, processes, and practices in all sectors of the market were replaced by the
most efficient feasible type. Technical potential does not take into account the cost-effectiveness
of the measures. Further, technical potential is specifically defined as ―phase-in technical
potential,‖ which assumes that only the portion of the current stock of equipment that has
reached the end of its useful life and is due for turnover is changed out by the most efficient
measures available (i.e., replacement). Non-equipment measures, such as controls and other
devices (e.g., programmable thermostats) are not adopted all at once but are phased-in over
time, just like the equipment measures. Lighting retrofits, which are in effect early replacements
of existing lighting systems, are considered a non-equipment measure.
Economic potential results from the purchase of the most efficient cost-effective option
available for a given equipment or non-equipment measure. Cost effectiveness is determined by
applying an economic test. In this report, the total resource cost (TRC) test5 was used to assess
the cost-effectiveness of individual measures. Measures that passed the economic screen were
then represented in the aggregate for economic potential. As with technical potential, economic
potential is a phased-in approach. Economic potential is still a hypothetical upper-boundary of
savings potential as it represents only measures that are economic but does not yet consider
customer acceptance and other factors.
Achievable potential refines the economic potential by taking into account penetration rates of
efficient technologies, expected program participation, and customer preferences and likely
behavior. Two types of achievable potential were evaluated for this study:
Maximum achievable potential (MAP) establishes an upper boundary of potential
savings a utility could achieve through its energy efficiency programs. MAP presumes
incentives that are sufficient to ensure customer adoption. It also considers a maximum
4 National Action Plan for Energy Efficiency (2007). National Action Plan for Energy Efficiency Vision for 2025: Developing a Framework for Change. www.epa.gov/eeactionplan. 5 While there are other tests that can be used to represent the economic potential (e.g., Participant or Utility Cost), the TRC is
generally seen as the most appropriate representation of economic potential since it tends to be most representative of the net benefits
of energy efficiency to society as a whole. The TRC is used in the economic screen as a proxy for moving forward and representing
achievable energy efficiency savings potential for those measures that are most widely cost-effective.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 830 of 1069
Study Approach For Energy Efficiency Analysis Avista Conservation Potential Assessment Study
2-8 www.gepllc.com

participation rate by customers for the various energy efficiency programs that are designed
to deliver the various measures. For this study, we developed market acceptance rate (MAR)
factors, based on the ramp rate curves used in the Sixth Power Plan. These MAR factors
were then applied to this study’s estimates of economic potential to estimate MAP.
Realistic achievable potential (RAP) represents a lower boundary forecast of potentials
resulting from likely customer behavior and penetration rates of efficient technologies. It
uses a set of program implementation factors (PIFs) to take into account existing barriers
that are likely to limit the amount of savings that might be achieved through energy
efficiency programs. The RAP also takes into account recent utility experience and reported
savings from past and present programs.
2.4.1 Modeling Approach
We used LoadMAP to develop the estimates of technical, economic, and achievable potential.
LoadMAP calculates results in terms of annual energy saved (kWh) and peak demand reduction
(MW) for each level of potential by market segment, end use, and measure type. Figure 2-2
illustrates the LoadMAP process for developing both the baseline forecast the potentials
forecasts.
For the technical potential, LoadMAP ―chooses‖ the most efficient option for each purchase
decision involving major end-use equipment (refrigerators, air conditioners) during the forecast
period. It also phases in all non-equipment measures during the forecast period.
For the economic potential, LoadMAP applies the TRC, which tests each measure in terms of
its lifetime benefits (i.e., energy savings multiplied by the avoided cost) relative to the initial
capital cost required to install the measure. If the benefit/cost ratio is greater than or equal to
1.0, then the measure passes the screen and it is included in the calculation of economic
potential. If the B/C ratio is less than 1.0, the measure is screened out of economic potential. To
allow for the changing characteristics of individual, new measures, we perform the economic
screen during each year of the forecast period. Therefore, a measure than may not pass the
screen in 2010 may pass in some future year. If more than one efficiency option passes the
economic screen, for example if SEER 15 and SEER 16 both pass, then the most efficient option,
SEER 16, is included in the calculation of economic potential.
Economic potential still does not take into account the acceptance of those measures by
customers, so it is still a hypothetical upper-boundary of EE potential. But again, this exercise is
important as it provides useful insights as to how much potential is economic and oftentimes can
be compared with other studies of economic potential.
To develop estimates for maximum and realistic achievable potential, we specify market
adoption rates and program implementation factors for each measure as described above. For
this study, we based these factors on the Sixth Power Plan’s conservation curve ramp rates, and
the past experience at Avista and at other utility EE programs. We also tapped into our recently
completed market research for two EE potential studies in which we assessed customer
acceptance rates taking into account some degree of financial intervention on the part of the
utility to bring down customer paybacks to a level that motivates their participation in various EE
programs. While there is a significant degree of uncertainty associated with these adoption rates,
we believe that the approach is reasonable and is bounded by the experience gained from other
utility EE efforts. Because the adoption rates are model inputs, they can be modified as new
information becomes available.
The LoadMAP model provides a forecast of annual electricity use and peak demand under the
four types of potential. The energy and peak-demand savings from energy efficiency measures
are calculated as the difference between the values for the baseline forecast and the potential
forecast.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 831 of 1069
Avista Conservation Potential Assessment Study Study Approach For Energy Efficiency Analysis
Global Energy Partners, LLC 2-9
An EnerNOC Company
Figure 2-2 LoadMAP Baseline and Potential Modeling

Results of the potentials assessment are presented in Chapter 6.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 832 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 833 of 1069

Global Energy Partners, LLC 3-1
An EnerNOC Company
CHAPTER 3

MARKET ASSESSMENT AND MARKET PROFILES
Avista Utilities, headquartered in Spokane, Washington is an investor-owned utility with annual
revenues of more than $1.3 billion. Avista provides electric and natural gas service to about
481,000 customers in a service territory of more than 30,000 square miles. Avista uses a mix of
hydro, natural gas, coal and biomass generation delivered over 2,100 miles of transmission line,
17,000 miles of distribution line, and 6,100 miles of natural gas distribution mains. Avista
currently operates a portfolio of electric and natural gas conservation programs in Washington,
Idaho, and Oregon for residential, low-income, and non-residential customers that is funded by a
non-bypassable systems benefits charge.
The base year for this study is 2009, the most recent year for which complete billing data were
available at the beginning of the study. Table 3-1 and Table 3-2 show the breakdown, for
Washington and Idaho respectively, of 2009 electricity sales among the major sectors and rate
classes, drawn from billing data provided by Avista. Peak demand data was taken from the 2009
System Load Research Project report.6 Figure 3-1and Figure 3-2 show similar data, but with the
Extra Large General Service customers (rate class 025) further divided into commercial and
industrial. In Figure 3-2 for Idaho, Extra Large General Service also includes Potlatch, rate class
25P.
Table 3-1 Electricity Sales and Peak Demand by Rate Class, Washington 2009
Sector
Rate
Schedule(s)
Number of meters
(customers)
2009 Electricity
sales (MWh)
Peak demand
(MW)
Residential 001 200,134 2,451,687 710
General Service 011, 012 27,142 415,935 64
Large General Service 021, 022 3,352 1,556,929 232
Extra Large General Service 025 22 879,233 134
Pumping 031, 032 2,361 135,999 10
Total 233,011 5,439,850 1,150
Table 3-2 Electricity Use and Peak Demand by Rate Class, Idaho 2009
Sector
Rate
Schedule(s)
Number of meters
(customers)
2009 Electricity
sales (MWh)
Peak demand
(MW)
Residential 001 99,580 1,182,368 283
General Service 011, 012 19,245 322,570 61
Large General Service 021, 022 1,456 699,953 115
Extra Large General Service 025, 025P 10 266,044 40
Extra Large GS Potlatch 025P 1 892 101
Pumping 031, 032 1,312 58,885 4
Total 121,604 3,422,111 603

6 Avista Corp. System Load Research Project report, March 2010, prepared by KEMA.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 834 of 1069
Market Assessment and Market Profiles Avista Conservation Potential Assessment Study
3-2 www.gepllc.com

Figure 3-1 Electricity Sales by Rate Class, Washington 2009

Figure 3-2 Electricity Sales by Rate Class, Idaho 2009

For this study, the project team decided not to explicitly model the EE potential for pumping
customers but instead to use the Northwest Power and Conservation Council (NPCC) standard
calculator to estimate EE potential. Results of that calculation appear in Chapter 6.
Below we discuss the market characterization and development of market profiles for the
Residential and C&I sectors.
3.1 RESIDENTIAL SECTOR
This section characterizes the residential market at a high level, and then provides a profile of
how customers in each residential segment use electricity by end use.
Residential
45%
General Service
8%
Large General
Service
29%
Extra Large
Commercial
5%
Extra Large
Industrial
11%
Pumping
2%
Residential
35%
General Service
9%Large General
Service
20%
Extra Large
Commercial
2%
Extra Large
Industrial
32%
Pumping
2%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 835 of 1069
Avista Conservation Potential Assessment Study Market Assessment and Market Profiles
Global Energy Partners, LLC 3-3
An EnerNOC Company
3.1.1 Market Characterization
The total number of residential customers was 200,134 in Washington and 99,579 in Idaho,
based on the average number of rate class 001 monthly customers for 2009 provided by Avista.7
We segmented these customers into four groups based on housing type and level of income:
single family, multi family, mobile home, and limited income. The single family segment includes
single-family detached homes, townhouses, and duplexes or row houses. The multi family
segment includes apartments or condos in buildings with more than two units. The limited
income segment is composed of all three housing types: single-family homes, multi-family
homes, and mobile homes.
Because Avista does not maintain information on housing type or income level, we relied on a
variety of survey and demographic sources for segmenting the residential market, including the
U.S. Census American Community Survey 2006-2008, a 2009 Inland Power customer survey, and
other sources (see Appendix E). Avista defines the limited-income category as those customers
with annual income less than or equal to two times the poverty level. For an average household
size of 2.5 persons, two times the poverty level is $32,880. For the purpose of our analysis, we
used a slightly higher income level cutoff of $35,000 to define this segment, which allowed us to
take advantage of the data sources listed above.
The resulting residential customer allocation by segment appears in Table 3-3 and in Figure 3-3.
Table 3-3 Residential Sector Allocation by Segments
Washington Idaho
Segment Allocation of
Customers % of Total Allocation of
Customers % of Total
Single Family 109,134 54% 59,205 59%
Multi Family 18,219 9% 5,237 5%
Mobile Home 5,248 3% 4,774 5%
Limited Income 67,533 34% 30,363 31%
Total 200,134 100% 99,579 100%
Note: Minor difference with Idaho residential customer total 99,580 Table 3-2 due to calibration.
Figure 3-3 Residential Sector Allocation by Segments, Percentage of Customers

7 Rate classes 12 and 22, although they include homes, are included with rates classes 11 and 21 respectively, which corresponds with
how customer classes were combined for Avista’s System Load Research Project report.
Single
Family
54%
Multi
Family
9%
Mobile
Home
3%
Limited
Income
34%
Washington, % of Customers
Single
Family
59%Multi
Family
5%
Mobile
Home
5%
Limited
Income
31%
Idaho, % of Customers
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 836 of 1069
Market Assessment and Market Profiles Avista Conservation Potential Assessment Study
3-4 www.gepllc.com

Next, to determine the residential whole building energy intensity (kWh/household) by segment,
we drew upon data from the Energy Information Agency, a NEEA residential billing analysis
report, and the Inland Power & Light 2009 Conservation Potential Assessment. Based on these
sources, we developed the segment level energy intensities shown in Table 3-4. The selected
energy intensity values multiplied by the number of households equal the annual sales for each
segment. These values sum to the total annual energy use for the residential sector in each
state. Figure 3-4 presents the resulting energy sales by segment. The single-family segment
used just over half the total residential sector electricity in 2009.
Table 3-4 Residential Electricity Usage and Intensity by Segment and State, 2009
Washington
Segment
Intensity
(kWh/Household)
Number of
Customers
% of
Customers
2009 Electricity
Sales (MWh) % of Sales
Single Family 14,547 109,134 54% 1,587,572 65%
Multi-Family 8,728 18,219 9% 159,019 6%
Mobile Home 13,092 5,248 3% 68,708 3%
Limited Income 9,424 67,533 34% 636,407 26%
Total 12,250 200,134 100% 2,451,707 100%

Idaho
Segment
Intensity
(kWh/Household)
Number of
Customers
% of
Customers
2009 Electricity
Sales (MWh) % of Sales
Single Family 13,703 59,205 59% 811,302 69%
Multi-Family 8,213 5,237 5% 43,013 4%
Mobile Home 12,320 4,774 5% 58,815 5%
Limited Income 8,868 30,363 31% 269,249 23%
Total 11,874 99,580 100% 1,182,379 100%
Note: Minor differences with totals in Table 3-1 and Table 3-2 due to calibration.
Figure 3-4 Residential Electricity Use by Customer Segment, Percentage of Sales 2009

Single
Family
65%
Multi
Family
6%
Mobile
Home
3%
Limited
Income
26%
Washington, % of Sales
Single
Family
68%
Multi
Family
4%
Mobile
Home
5%
Limited
Income
23%
Idaho, % of Sales
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 837 of 1069
Avista Conservation Potential Assessment Study Market Assessment and Market Profiles
Global Energy Partners, LLC 3-5
An EnerNOC Company
3.1.2 Residential Market Profiles
As we describe in the previous chapter, the market profiles provide the foundation upon which
we develop the baseline forecast. For each segment, we created a market profile, which includes
the following elements:
Market size represents the number of customers in the segment
Saturations embody the fraction of homes with the electric technologies. (e.g., homes with
electric space heating). We developed these using a combination of survey data from sources
including Inland Power & Light, NEEA, and Puget Sound Energy (PSE). The results were
cross-checked and validated against various other secondary sources.
UEC (unit energy consumption) describes the amount of electricity consumed in 2009 by
a specific technology in homes that have the technology (in kWh/household). As above, we
used data from Inland Power & Light, NEEA, and PSE. We also used data from various utility
potential studies that Global has recently completed. As needed, some minor adjustments
were made to calibrate to whole-building intensities.
Intensity represents the average use for the technology across all homes in 2009. It is
computed as the product of the saturation and the UEC and is defined as kWh/household.
Usage is the annual electricity use by a technology/end use in the segment. It is the product
of the number of households and intensity and is quantified in GWh.
Table 3-5 presents the average existing home market profile for the entire Avista residential
sector. The table shows data captured directly from LoadMAP. Values in red are inputs to
LoadMAP. The existing-home profile represents all the housing stock in the Avista service area in
2009. Market profiles for each of the residential segments in Washington and Idaho respectively
appear in Appendix A and B.
Figure 3-5 presents the end-use breakout for the residential sector as a whole. The appliance
end use accounts for the largest share of the usage, closely followed by space heating, with
water heating the third largest end use. The miscellaneous end use includes such devices as
furnace fans, pool pumps, and other ―plug‖ loads (hair dryers, power tools, coffee makers, etc.).
Interior and exterior lighting combined account for 12% of electricity use in 2009. The
electronics end use, which includes personal computers, televisions, home audio, video game
consoles, etc., also contributes significantly to household electricity usage. Cooling and combined
heating and cooling through heat pumps make up the remainder.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 838 of 1069
Market Assessment and Market Profiles Avista Conservation Potential Assessment Study
3-6 www.gepllc.com

Figure 3-5 Residential Electricity Use by End Use per Household, 2009 (kWh and %)

Cooling,
601 , 5%
Space Heating,
2,619 , 21%
Heat & Cool,
714 , 6%
Water Heating,
1,834 , 15%
Appliances,
2,637 , 22%
Interior
Lighting,
1,279 , 10%
Exterior
Lighting,
213 , 2%
Electronics,
1,053 , 9%
Miscellaneous,
1,176 , 10%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 839 of 1069
Avista Conservation Potential Assessment Study Market Assessment and Market Profiles
Global Energy Partners, LLC 3-7
An EnerNOC Company
Table 3-5 Average Residential Sector Market Profile

UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 29%1,613 470 141
Cooling Room AC 20%643 131 39
Combined Heating/Cooling Air Source Heat Pump 14%5,051 699 209
Combined Heating/Cooling Geothermal Heat Pump 0%3,715 15 4
Space Heating Electric Resistance 18%6,114 1,119 335
Space Heating Electric Furnace 22%6,779 1,492 447
Space Heating Supplemental 9%83 8 2
Water Heating Water Heater 66%2,796 1,834 550
Interior Lighting Screw-in 100%1,144 1,144 343
Interior Lighting Linear Fluorescent 66%121 80 24
Interior Lighting Pin-based 92%59 55 16
Exterior Lighting Screw-in 70%301 211 63
Exterior Lighting High Intensity/Flood 2%116 2 1
Appliances Clothes Washer 84%105 88 26
Appliances Clothes Dryer 80%621 498 149
Appliances Dishwasher 86%185 160 48
Appliances Refrigerator 100%746 746 224
Appliances Freezer 62%760 474 142
Appliances Second Refrigerator 35%787 277 83
Appliances Stove 86%299 257 77
Appliances Microwave 95%144 137 41
Electronics Personal Computers 121%263 317 95
Electronics TVs 222%311 688 206
Electronics Devices and Gadgets 100%48 48 14
Miscellaneous Pool Pump 10%1,328 130 39
Miscellaneous Furnace Fan 26%404 107 32
Miscellaneous Miscellaneous 100%940 940 282
12,125 3,634
-
Average Market Profile - Residential Sector
End Use Technology Saturation
Total
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 840 of 1069
Market Assessment and Market Profiles Avista Conservation Potential Assessment Study
3-8 www.gepllc.com

Figure 3-6 presents the end-use shares of total electricity use for each housing type. Space
heating is the largest single use in all housing types except single family homes where it is lower
relative to other uses. Appliances are the largest energy consumer in the single family segment
and are a significant energy use in the other segments as well.
Figure 3-6 End-Use Shares of Total Electricity Use by Housing Type, 2009

3.2 COMMERCIAL AND INDUSTRIAL SECTORS
The approach we used for the C&I sectors is analogous to the residential sector. It begins with
segmentation, then defines market size and annual electricity use, and concludes with market
profiles.
3.2.1 C&I Market Characterization
We developed the non-residential energy use by segment using Avista 2009 billing data by rate
class. Table 3-6 and Table 3-7 present the results for the market characterization for Washington
and Idaho respectively. Although the General Service 011 and Large General Service 021 rate
classes include a small percentage of industrial customers, we chose to model these as primarily
commercial building types. For the General Service segment, we assumed facilities were small to
medium buildings, dominated by retail facilities. For the Large General Service segment, we
assumed the typical facility was an office building. When developing the market profiles, as
further described below, we began with these assumed prototypical building types, but adjusted
them to account for the diversity in each segment. For the Extra Large General Service rate class
025, we divided customers into separate commercial and industrial segments and included the
Potlatch facility, Idaho rate class 025P, with the other Idaho Extra Large industrial customers.
This grouping enabled better modeling of the industrial customers.
We then used data from NEEA, the California Commercial End Use Study (CEUS), and other
recently completed studies to develop estimates of floor space and annual intensities (in
kWh/square foot) for each segment. Because of the heterogeneous nature of the C&I sectors
and the wide variation in customer size (compared to residential homes), floor space is used as
the unit of measure to quantify energy use and equipment inventories on a per-square-foot
basis. Note that we are not concerned with absolute square footage, as the purpose of this study
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Single Family Multi Family Mobile Home Limited
Income
Cooling
Space Heating
Heat & Cool
Water Heating
Appliances
Interior Lighting
Exterior Lighting
Electronics
Miscellaneous
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 841 of 1069
Avista Conservation Potential Assessment Study Market Assessment and Market Profiles
Global Energy Partners, LLC 3-9
An EnerNOC Company
is not to estimate C&I floor space, but with the relative size of each segment and its growth over
time.
Table 3-6 Commercial Sector Market Characterization Results, Washington 2009
Avista Rate Schedule LoadMAP Segment
and Typical Building
Electricity
sales (MWh)
Intensity
(kWh/sq.ft.)
General Service 011, 012 Small and Medium Commercial — Retail 415,935 17.5
Large General Service 021, 022 Large Commercial — Office 1,556,929 16.7
Extra Large General
Service Commercial 025C Extra Large Commercial — University 265,686 13.9
Extra Large General
Service Industrial 025I Extra Large Industrial 613,615 40.0
Total 2,852,165

Table 3-7 Commercial Sector Market Characterization Results, Idaho 2009
Avista Rate Schedule LoadMAP Segment and Typical
Building
Electricity
sales (MWh)
Intensity
(kWh/sq.ft.)
General Service 011, 012 Small and Medium Commercial — Retail 322,570 17.5
Large General Service 021, 022 Large Commercial — Office 699,953 16.7
Extra Large General
Service Commercial 025C Extra Large Commercial — University 70,361 13.9
Extra Large General
Service Industrial 025I, 025P Extra Large Industrial 1,087,974 40.0
Total 2,180,858

3.2.2 C&I Market Profiles
For the C&I sector, the approach we used to develop market profiles is similar to what we
described above for residential.
Saturations are the percentage of floor space with each electric end use. For space heating,
cooling and water heating, this embodies the electric fuel share. For space heating and
cooling, it also embodies the fraction of conditioned space. The saturation values for each
end use are from NEEA reports, supplemented with other secondary sources to develop the
technology-level saturations. For the industrial segments, we drew upon U.S. Industrial
Electric Motor Systems Market Opportunities Assessment from the US Department of Energy
(US DOE) and the EIA Annual Energy Outlook.
EUIs (end-use indices) represent the amount of electricity used per square foot of floor
space in buildings where the equipment is present. Data from NEEA. US DOE, EIA, and other
secondary sources provided EUIs by end use. We developed the technology-level EUIs using
our engineering model BEST and other secondary sources. Finally, we adjusted the EUIs to
calibrate to Avista’s overall building type intensity.
Intensity is the average use across all floor space (computed as the product of saturation
and EUI). For the industrial sector, we calibrate
Annual use is the total consumption in 2009 for each end use (computed as the product of
the intensity and the floor space for the segment.
Figure 3-7 shows the breakdown of annual electricity usage by end use for the C&I sector as a
whole. Lighting is the largest single end use in the sector, accounting for one fifth of total usage.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 842 of 1069
Market Assessment and Market Profiles Avista Conservation Potential Assessment Study
3-10 www.gepllc.com

Figure 3-7 Commercial and Industrial Electricity Consumption by End Use, 2009

This information is further detailed in Figure 3-8, which shows the end-use breakdown for the
composite of the three commercial segments — Small/Medium, Large, and Extra Large — and
Figure 3-9, which shows similar information for the Extra Large Industrial segment.
Observations include the following:
Commercial buildings
o Lighting is the largest single energy use across all of the commercial buildings,
accounting for 29% of energy use.
o Space conditioning, including heating, cooling, and ventilation, is close behind with 27%
of energy use.
o Miscellaneous and office equipment are the next largest energy uses.
o Water heating, refrigeration, and food preparation are only a small portion of energy use
in the commercial sector overall, though they are more significant in specific building
types (supermarkets, restaurants, hospitals, lodging).
Extra Large Industrial facilities
o Machine drive and process loads dominate in this segment, together accounting for 65%
of energy use.
o HVAC and interior lighting consume 17% and 6% of energy respectively.
Cooling
9%
Space Heating
5%
Heat & Cool
2%
Ventilation
8%
Water Heating
5%
Food Preparation
2%
Refrigeration
4%Interior Lighting
21%
Exterior Lighting
3%
Office Equipment
7%
Miscellaneous
12%
Machine Drive
15%
Process
7%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 843 of 1069
Avista Conservation Potential Assessment Study Market Assessment and Market Profiles
Global Energy Partners, LLC 3-11
An EnerNOC Company
Figure 3-8 Commercial End Use Consumption, 2009

Figure 3-9 Extra Large Industrial End Use Consumption, 2009

Table 3-8 shows an example commercial average base year market profile, in this case for the
Washington Small/Medium Commercial Segment. The table show data captured from LoadMAP,
where values shown in red are inputs to the model. The market profiles for each of the
Washington and Idaho C&I segments are shown in Appendices A and B respectively.
Cooling
10%
Space Heating
6%
Heat & Cool
2%
Ventilation
9%
Water Heating
8%
Food Preparation
3%
Refrigeration
6%
Interior Lighting
29%
Exterior Lighting
5%
Office Equipment
10%
Miscellaneous
12%
Cooling
6%
Space Heating
3%Heat & Cool
0%
Ventilation
8%
Interior
Lighting
6%
Exterior
Lighting
1%
Miscellaneous
12%
Machine Drive
45%
Process
20%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 844 of 1069
Market Assessment and Market Profiles Avista Conservation Potential Assessment Study
3-12 www.gepllc.com

Table 3-8 Small/Medium Commercial Segment Market Profile, Washington, 2009

EUI Intensity Usage EUI Intensity
(kWh)(kWh/Sqft.)(GWh)(kWh)(kWh/Sqft.)
Cooling Central Chiller 13.8%2.39 0.33 8 13.8%2.15 0.30 -10%
Cooling RTU 63.1%2.46 1.55 37 63.1%2.22 1.40 -10%
Cooling PTAC 3.3%2.44 0.08 2 3.3%2.20 0.07 -10%
Combined Heating/Cooling Heat Pump 3.6%6.19 0.22 5 3.6%5.57 0.20 -10%
Space Heating Electric Resistance 5.9%6.72 0.39 9 5.9%6.72 0.39 0%
Space Heating Furnace 17.7%7.05 1.25 30 17.7%6.34 1.13 -10%
Ventilation Ventilation 76.9%2.09 1.61 38 76.9%1.88 1.45 -10%
Interior Lighting Interior Screw-in 100.0%1.00 1.00 24 100.0%0.90 0.90 -10%
Interior Lighting HID 100.0%0.68 0.68 16 100.0%0.61 0.61 -10%
Interior Lighting Linear Fluorescent 100.0%3.37 3.37 80 100.0%3.03 3.03 -10%
Exterior Lighting Exterior Screw-in 82.6%0.20 0.16 4 82.6%0.18 0.15 -10%
Exterior Lighting HID 82.6%0.76 0.63 15 82.6%0.68 0.56 -10%
Exterior Lighting Linear Fluorescent 82.6%0.16 0.13 3 82.6%0.14 0.12 -10%
Water Heating Water Heater 63.0%2.00 1.26 30 63.0%1.90 1.19 -5%
Food Preparation Fryer 25.8%0.16 0.04 1 25.8%0.16 0.04 0%
Food Preparation Oven 25.8%0.98 0.25 6 25.8%0.98 0.25 0%
Food Preparation Dishwasher 25.8%0.06 0.01 0 25.8%0.06 0.01 0%
Food Preparation Hot Food Container 25.8%0.31 0.08 2 25.8%0.31 0.08 0%
Food Preparation Food Prep 25.8%0.01 0.00 0 25.8%0.01 0.00 0%
Refrigeration Walk in Refrigeration 0.0%- - - 0.0%- -
Refrigeration Glass Door Display 52.4%0.45 0.23 6 52.4%0.40 0.21 -10%
Refrigeration Solid Door Refrigerator 52.4%0.50 0.26 6 52.4%0.45 0.24 -10%
Refrigeration Open Display Case 52.4%0.04 0.02 1 52.4%0.04 0.02 -10%
Refrigeration Vending Machine 52.4%0.30 0.16 4 52.4%0.30 0.16 0%
Refrigeration Icemaker 52.4%0.34 0.18 4 52.4%0.34 0.18 0%
Office Equipment Desktop Computer 99.9%0.48 0.48 11 99.9%0.48 0.48 0%
Office Equipment Laptop Computer 99.9%0.06 0.06 1 99.9%0.06 0.06 0%
Office Equipment Server 99.9%0.36 0.36 9 99.9%0.36 0.36 0%
Office Equipment Monitor 99.9%0.25 0.25 6 99.9%0.25 0.25 0%
Office Equipment Printer/copier/fax 99.9%0.24 0.24 6 99.9%0.24 0.24 0%
Office Equipment POS Terminal 99.9%0.27 0.27 7 99.9%0.27 0.27 0%
Miscellaneous Non-HVAC Motor 40.2%1.22 0.49 12 40.2%1.22 0.49 0%
Miscellaneous Other Miscellaneous 100.0%1.43 1.43 34 100.0%1.43 1.43 0%
17.50 416 16.3
New Units
Compared to
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 845 of 1069

Global Energy Partners, LLC 4-1
An EnerNOC Company

CHAPTER 4

BASELINE FORECAST
Prior to developing estimates of energy-efficiency potential, a baseline end-use forecast was
prepared to quantify how electricity is used by end use in the base year and what electricity is
likely to be in the future in absence of new utility programs. The baseline forecast serves as the
metric against which energy-efficiency potentials — technical, economic, and achievable — are
compared.
4.1 RESIDENTIAL SECTOR
4.1.1 Residential Baseline Forecast Drivers
In general, the baseline forecast incorporates assumptions about economic growth, electricity
prices, appliance/equipment standards and building codes already mandated, and naturally
occurring conservation. The key inputs we used to develop the forecast for Avista include:
Customer growth: provided by Avista through 2015, and rate of growth assumed constant
thereafter
Forecasts of electricity prices: provided by Avista through 2015, with rate of increases
thereafter based on the Annual Energy Outlook (AEO)
Forecasts of household size: from Census data and the 6th Plan
Forecast of income: from Washington state data
Trends in end-use/technology saturations: developed from the AEO
Equipment purchase decisions: developed from AEO
Table 4-1 presents the assumptions used in the forecast regarding market size growth,
household size, median household income, and electricity prices. The market size growth rate
was applied equally to each of the four segments.
Table 4-1 Residential Market Size Forecast (number of households)
Driver 2009 2012 2017 2022 2027 2032
Average
Growth
(%/yr)
Market Size WA
(number of households) 200,134 204,530 217,921 232,414 247,871 264,356 1.21%
Market Size ID
(number of households) 99,579 102,077 108,592 115,553 122,960 130,842 1.19%
Persons per household 2.50 2.50 2.50 2.50 2.50 2.50 –
Electricity price WA
(cents per kWh) $0.0721 $0.0796 $0.0804 $0.0825 $0.0845 $0.0867 0.80%
Electricity price ID
(cents per kWh) $0.0742 $0.0855 $0.0876 $0.0898 $0.0921 $0.0944 1.05%
Per capita income
($ real, 2000) $34,506 $35,787 $39,202 $43,623 $48,400 $53,700 1.92%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 846 of 1069
Baseline Forecast Avista Conservation Potential Assessment Study
4-2 www.gepllc.com

In addition to forecasts for household size, electricity price, and median household income, the
model also requires elasticities for these variables. The elasticities for prices and persons per
household are based on the REEPS model developed by the Electric Power Research Institute
(EPRI). The income elasticity was provided by Avista. The values are as follows:
–0.151 for electricity prices
0.75 for income for all end uses except for appliances, where we use 0.375
0.20 for persons per household
In addition, we implemented the following assumptions for the residential sector 8:
In 2006, a Federal standard for central air conditioners and heat pumps went into effect,
requiring all newly manufactured air conditioners and heat pumps to meet SEER 13 or better.
This standard applies to replace-upon-burnout in existing construction and new construction.
In 2016, the standard becomes SEER 149.
In April 2010, DOE released updated water heater standards that go into effect April 16,
2015. The new standard for water heaters with volume at or below 55 gallons requires an
energy factor (EF) equal to 0.96 minus 0.0003 times the rated storage volume in gallons.
DOE is scheduled to make a final ruling on refrigerator and freezer standards on December
31, 2010. We incorporated this anticipated ruling into the forecast and assumed that
refrigeration and freezer consumption will decrease by 20% in 201410. This forecast does not
include anticipated standards for room air conditioners, clothes washers, clothes dryers and
dishwashers because DOE rulings on the standards have not yet been set.
Residential lighting is affected by the passage of the Energy Independence and Security Act
(EISA) in 2007, which mandates higher efficacies for lighting technologies starting in 2012.
Several lighting technologies are anticipated to meet this standard when it goes into effect,
including compact fluorescent lamps (CFL) and white light-emitting diodes (LED). As a result,
the share of incandescent lamps decreases while CFL and LED purchases increase. CFLs
dominate over the forecast period, but LEDs account for about 20% of purchases by 2020.
In November 2008, ENERGY STAR 3.0 for color televisions went into effect. This standard
sets the rules for becoming ENERGY STAR qualified. One such criterion is that TVs must not
exceed 1 watt of power in standby mode.
4.1.2 Residential Baseline Forecast Results
Overall, residential use in both states and for all segments increases from 3,634,054 MWh in
2009 to 5,600,870 MWh in 2032, an average annual growth rate of 1.9%. This is slightly higher
than the 1.5% annual growth rate in Avista’s 2009 IRP for the period 2009 through 2030.
Because the IRP forecast includes future conservation activities and LoadMAP’s baseline forecast
does not, we would generally expect LoadMAP’s baseline forecast to be somewhat higher. This
increase is also more than double the AEO forecast of 0.8% average growth.

8 These assumptions reflect standards in effect as of late 2010 or scheduled to take effect over the course of the 20-year study period. Because some of these standards were not yet announced when the NWPCC Sixth Plan was developed, this study’s baseline incorporates reduced baseline energy usage compared with the Sixth Plan. 9 This assumption was included in the 2010 Annual Energy Outlook (AEO) forecast. The SEER 14 standard level used in the AEO forecast was established in a 2009 consensus agreement made between equipment manufacturers and energy efficiency advocacy organizations. DOE is required to publish the final rule on central air conditioners and heat pump standards in 2011. 10 This level is consistent with the standard recently agreed upon in a joint proposal by home appliance manufacturers and energy
efficiency advocates which states that refrigeration and freezer consumption must decrease by 20-30% effective in 2014.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 847 of 1069
Avista Conservation Potential Assessment Study Baseline Forecast
Global Energy Partners, LLC 4-3
An EnerNOC Company
General observations about this forecast include the following:
Overall, household growth is robust, with a nearly 32% increase between 2009 and 2032.
The AEO forecast is somewhat lower, with a 26% increase in the number of households.
The factors that impact usage — relatively low electricity prices and strong income growth —
result in strong residential consumption growth over the forecast period.
New homes are larger than existing homes, based on data from the AEO and other studies.
However, equipment and appliances are more efficient, so the combined effect is slightly
positive.
Figure 4-1 presents the baseline forecast at the end-use level for the residential sector as a
whole, in both Washington and Idaho.
Figure 4-1 Residential Baseline Forecast by End Use

End-use specific observations include:
The drop in all space conditioning loads from 2009 to 2012 is due to the transition from
actual weather in 2009 (589 cooling degree days and 6,976 heating degree days) to the
normal weather forecast (434 cooling degree days and 6,657 heating degree days)
thereafter.
Cooling grows due to increasing saturation of central air conditioning in new homes and
larger home sizes, as well as the addition of central air conditioning to existing homes.
Space heating, combined heating and cooling, and water heating grow, but at a slightly
moderate rate compared to cooling, again due to the growth in households and to larger
home sizes.
Beginning in 2012, the federal lighting standards cause a decline in electricity for interior
lighting use of 29% and exterior lighting use by 41% over the forecast period. The AEO 2010
forecast projects a 26% decline in lighting energy use over the same period. The AEO
reduction is less than that shown here, again due to increasing home size.
Appliances decrease, reflecting efficiency gains, particularly in the refrigeration appliances
due to standards that offset the small increases in saturations of dishwashers, clothes
washers, and clothes dryers.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 848 of 1069
Baseline Forecast Avista Conservation Potential Assessment Study
4-4 www.gepllc.com

Growth in electricity use in electronics is strong and reflects an increase in the saturation of
electronics and the trend toward higher-powered computers and larger televisions.
Growth in miscellaneous use is also substantial. This has been a long-term trend and we
incorporate growth assumptions that are consistent with the AEO.
Figure 4-2 presents the forecast of use per household. Most noticeable is that lighting use
decreases significantly after 2010, as the lighting standard from EISA comes into effect and as
LED lamps begin to gain traction in the later years of the forecast. Appliance use also decreases
over the forecast period due to appliance standards. Use in electronics and miscellaneous
increase over the forecast period, reflecting the trend that households continue to add various
electronics to the home.
Figure 4-2 Residential Baseline Electricity Use per Household by End Use

Table 4-2 shows the forecast by end use, while Table 4-3 provides additional detail by technology
within each end use. Central AC increases during the forecast as more households add air
conditioning. Screw-in lighting decreases as a result of the EISA lighting standard. Over the forecast
period there is strong growth in usage from electronics due to the increase in saturation.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 849 of 1069
Avista Conservation Potential Assessment Study Baseline Forecast
Global Energy Partners, LLC 4-5
An EnerNOC Company
Table 4-2 Residential Baseline Forecast Electricity Consumption by End Use (MWh)
End Use 2009 2012 2017 2022 2027 2032 % Change
('09–'32)
Avg. growth
rate
Cooling 180,022 164,865 197,394 239,439 292,044 355,171 97% 3.0%
Space Heating 784,854 783,258 906,261 1,051,822 1,210,093 1,383,665 76% 2.5%
Heat & Cool 213,860 201,410 229,160 258,676 295,177 341,644 60% 2.0%
Water Heating 549,606 557,022 611,950 675,037 748,494 830,988 51% 1.8%
Interior Lighting 790,377 776,482 795,594 835,023 894,245 989,025 25% 1.0%
Exterior Lighting 383,305 371,610 246,575 256,864 262,823 271,374 -29% -1.5%
Appliances 63,864 61,321 41,763 39,795 38,430 37,735 -41% -2.3%
Electronics 315,599 336,152 394,727 459,538 529,485 616,688 95% 2.9%
Miscellaneous 352,599 374,575 447,870 540,047 648,055 774,496 120% 3.4%
Total 180,022 164,865 197,394 239,439 292,044 355,171 54% 1.9%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 850 of 1069
Baseline Forecast Avista Conservation Potential Assessment Study
4-6 www.gepllc.com

Table 4-3 Residential Baseline Electricity Forecast by End Use and Technology (MWh)
End Use Technology 2009 2012 2017 2022 2027 2032 % Change
('09–'32)
Avg. Growth
Rate
Cooling Central AC 140,731 130,669 161,085 199,996 249,120 308,429 119% 3.4%
Room AC 39,291 34,196 36,310 39,443 42,924 46,742 19% 0.8%
Space Heating
Electric Furnace 447,317 447,255 520,409 606,695 700,178 801,899 79% 2.5%
Electric Resistance 335,280 333,732 383,172 441,947 506,164 577,358 72% 2.4%
Supplemental 2,257 2,272 2,680 3,180 3,750 4,409 95% 2.9%
Heat & Cool Air Source Heat Pump 209,371 197,111 224,050 252,476 287,663 332,619 59% 2.0%
Geothermal Heat Pump 4,489 4,299 5,109 6,200 7,514 9,025 101% 3.0%
Water Heating Water Heater 549,606 557,022 611,950 675,037 748,494 830,988 51% 1.8%
Appliances
Refrigerator 223,654 213,517 204,566 204,184 209,933 231,329 3% 0.1%
Freezer 141,950 137,910 137,084 136,274 143,528 158,560 12% 0.5%
Second Refrigerator 83,117 77,296 72,374 70,707 69,137 73,789 -11% -0.5%
Clothes Washer 26,332 26,102 27,746 30,875 34,868 39,019 48% 1.7%
Clothes Dryer 149,267 150,677 163,829 180,582 199,465 221,428 48% 1.7%
Dishwasher 47,886 48,894 54,242 60,691 68,105 76,321 59% 2.0%
Stove 77,079 79,792 89,107 99,966 111,884 125,081 62% 2.1%
Microwave 41,092 42,294 46,647 51,744 57,325 63,498 55% 1.9%
Interior
Lighting
Screw-in 342,923 329,329 198,253 200,264 196,856 194,811 -43% -2.5%
Linear Fluorescent 24,025 25,171 29,266 34,273 39,944 46,451 93% 2.9%
Pin-based 16,358 17,110 19,056 22,326 26,023 30,112 84% 2.7%
Exterior
Lighting
Screw-in 63,165 60,629 41,255 39,254 37,834 37,069 -41% -2.3%
High Intensity/Flood 698 692 508 540 596 666 -5% -0.2%
Electronics
Personal Computers 94,922 101,516 120,451 143,627 170,677 202,632 113% 3.3%
TVs 206,326 219,527 256,515 294,816 333,825 384,485 86% 2.7%
Devices and Gadgets 14,351 15,110 17,761 21,095 24,983 29,572 106% 3.1%
Miscellaneous
Furnace Fan 32,029 33,795 39,817 47,004 54,841 63,046 97% 2.9%
Pool Pump 38,852 39,438 44,334 51,331 59,964 69,728 79% 2.5%
Miscellaneous 281,718 301,342 363,719 441,712 533,250 641,722 128% 3.6%
Grand Total 3,634,086 3,626,696 3,871,294 4,356,240 4,918,847 5,600,787 54% 1.9%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 851 of 1069
Avista Conservation Potential Assessment Study Baseline Forecast
Global Energy Partners, LLC 4-7
An EnerNOC Company
4.2 COMMERCIAL AND INDUSTRIAL SECTOR
4.2.1 C&I Baseline Forecast Drivers
As is the case with the residential sector, the C&I baseline forecast incorporates assumptions
about economic growth, electricity prices, equipment standards and building codes already
mandated, and naturally occurring conservation. The key inputs we used to develop the forecast
for Avista include:
Floor space growth for Commercial segments derived from Avista customer and load growth
projections through 2015 and from Avista IRP projections regarding expansion of existing
Extra Large Customer facilities; after 2015 assumed constant growth rate of 2% based on
Avista IRP11
Floor space growth for Extra Large Industrial segment derived from Avista customer and load
growth projections through 2015; thereafter based on based on employment growth of 2.8%
in Washington and 1.4% in Idaho12
Forecasts of electricity prices provided by Avista through 2015, with rate of increases
thereafter based on the Annual Energy Outlook (AEO)
Trends in end-use/technology saturations developed from the AEO
Equipment purchase decisions developed from AEO13
Table 4-4 presents the growth and electricity price assumptions used in the C&I forecast. Market
size growth is shown as an indexed value where 2009 equals 1.0
Table 4-4 Commercial Market Size Growth and Electricity Price Forecast
Indexed Market Size
2009 = 1.0 2009 2012 2017 2022 2027 2032
Avg.
Growth
(%/yr)
Small/Med. Comm., WA 1.00 1.04 1.14 1.26 1.39 1.53 1.85%
Large Comm., WA 1.00 1.01 1.10 1.22 1.34 1.48 1.72%
Extra Large Comm., WA 1.00 1.05 1.34 1.48 1.63 1.80 2.57%
Extra Large Industrial, WA 1.00 1.16 1.31 1.51 1.73 1.99 2.99%
Small/Med. Comm., ID 1.00 1.03 1.13 1.25 1.38 1.53 1.84%
Large Comm., ID 1.00 1.03 1.15 1.27 1.40 1.54 1.88%
Extra Large Comm., ID 1.00 1.04 1.25 1.38 1.52 1.68 2.26%
Extra Large Industrial, ID 1.00 1.04 1.13 1.21 1.30 1.39 1.44%

Electricity Price 2009 2012 2017 2022 2027 2032
Avg.
Growth
(%/yr)
Electricity price, WA
(cents per kWh) $0.0700 $0.0698 $0.0703 $0.0727 $0.0752 $0.0778 0.46%
Electricity price, ID
(cents per kWh) $0.0566 $0.0586 $0.0600 $0.0621 $0.0642 $0.0664 0.69%
11 Avista 2009 IRP, p. 2-10: Commercial usage per customer is forecast to increase for several years due to additional buildings either built or anticipated to be built by existing very large customers, such as Washington State University and Sacred Heart Hospital. Expected additions for very large customers are included in the forecast through 2015, and no additions are included in the forecast
after 2015. 12 Avista 2009 IRP p. 2-6. 13 We developed baseline purchase decisions using the Energy Information Agency’s Annual Energy Outlook report (2010), which
utilizes the National Energy Modeling System (NEMS) to produce a self-consistent supply and demand economic model. We calibrated
equipment purchase options to match manufacturer shipment data for recent years and trended forward.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 852 of 1069
Baseline Forecast Avista Conservation Potential Assessment Study
4-8 www.gepllc.com

4.2.2 C&I Baseline Forecast Results
Figure 4-3 and Table 4-5 present the baseline forecast at the end-use level for the C&I sector as a
whole. Overall, C&I annual energy use increases from 5,033,023 MWh in 2009 to 7,239,694 MWh in
2032, a 43.8% increase. This reflects growth in floor space across all sectors. Table 4-6 presents the
C&I forecast by technology. Interior screw-in lighting increases over the forecast period, but at a
slower rate than other technologies as a result of the lighting standard.
Figure 4-3 C&I Baseline Electricity Forecast by End Use

-
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
2009 2012 2017 2022 2027 2032
An
n
u
a
l

U
s
e

(
M
W
h
)
Cooling
Space Heating
Heat & Cool
Ventilation
Water Heating
Food Preparation
Refrigeration
Interior Lighting
Exterior Lighting
Office Equipment
Miscellaneous
Machine Drive
Process
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 853 of 1069
Avista Conservation Potential Assessment Study Baseline Forecast
Global Energy Partners, LLC 4-9
An EnerNOC Company
Table 4-5 C&I Electricity Consumption by End Use (MWh)
End Use 2009 2012 2017 2022 2027 2032 % Change
('09–'32)
Avg. growth
rate
Cooling 433,257 429,715 453,330 473,311 504,446 550,621 27.1% 1.04%
Space Heating 250,919 224,970 249,918 273,638 300,093 330,065 31.5% 1.19%
Heat & Cool 81,984 80,104 82,263 86,559 94,007 103,167 25.8% 1.00%
Ventilation 421,805 426,987 457,118 487,582 534,845 588,427 39.5% 1.45%
Water Heating 246,022 244,232 266,435 289,253 315,002 344,844 40.2% 1.47%
Food Preparation 92,263 94,294 104,419 114,396 125,186 136,992 48.5% 1.72%
Refrigeration 203,660 204,139 213,050 224,372 242,222 264,431 29.8% 1.14%
Interior Lighting 1,079,050 1,106,035 1,175,567 1,274,090 1,388,871 1,513,165 40.2% 1.47%
Exterior Lighting 179,595 183,933 202,023 219,529 239,546 261,703 45.7% 1.64%
Office Equipment 344,351 363,758 387,164 421,052 458,189 498,560 44.8% 1.61%
Miscellaneous 619,607 645,918 714,601 785,490 863,772 950,463 53.4% 1.86%
Machine Drive 740,191 800,303 881,202 966,387 1,061,952 1,169,146 58.0% 1.99%
Process 340,318 367,955 405,497 445,447 489,890 539,389 58.5% 2.00%
Total 433,257 429,715 453,330 473,311 504,446 550,621 27.1% 1.04%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 854 of 1069
Baseline Forecast Avista Conservation Potential Assessment Study
4-10 www.gepllc.com

Table 4-6 C&I Baseline Electricity Forecast by End Use and Technology (MWh)
End Use Technology 2009 2012 2017 2022 2027 2032 % Change
('09–'32)
Avg.
Growth
Rate
Cooling
Central Chiller 161,468 161,651 175,544 184,829 194,228 210,874 30.6% 1.16%
PTAC 18,631 18,428 18,862 19,691 21,069 23,036 23.6% 0.92%
RTU 253,158 249,637 258,925 268,791 289,149 316,711 25.1% 0.97%
Space Heating
Electric Resistance 102,223 191,387 212,950 234,235 257,713 283,617 177.5% 4.44%
Furnace 148,697 33,583 36,969 39,403 42,380 46,447 -68.8% -5.06%
Heat & Cool Heat Pump 81,984 80,104 82,263 86,559 94,007 103,167 25.8% 1.00%
Ventilation Ventilation 421,805 426,987 457,118 487,582 534,845 588,427 39.5% 1.45%
Water Heating Water Heater 246,022 244,232 266,435 289,253 315,002 344,844 40.2% 1.47%
Food Preparation
Dishwasher 5,561 5,675 6,260 6,889 7,580 8,341 50.0% 1.76%
Fryer 10,938 11,160 12,267 13,442 14,715 16,107 47.3% 1.68%
Oven 64,439 65,882 73,158 80,123 87,640 95,864 48.8% 1.73%
Hot Food Container 10,600 10,838 11,915 13,043 14,260 15,590 47.1% 1.68%
Food Prep 724 739 818 900 991 1,090 50.5% 1.78%
Refrigeration
Walk in Refrigeration 26,545 26,356 27,877 29,977 32,721 35,993 35.6% 1.32%
Glass Door Display 29,998 29,887 31,549 33,927 37,032 40,736 35.8% 1.33%
Solid Door Refrigerator 56,389 55,997 58,578 61,819 66,199 71,682 27.1% 1.04%
Open Display Case 18,136 18,080 19,502 20,983 22,909 25,201 39.0% 1.43%
Vending Machine 28,068 28,373 25,594 23,005 23,392 24,849 -11.5% -0.53%
Icemaker 44,524 45,447 49,951 54,661 59,969 65,969 48.2% 1.71%
Interior Lighting
HID 175,721 181,398 198,158 215,929 235,578 257,305 46.4% 1.66%
Linear Fluorescent 686,924 702,882 771,014 840,371 916,893 1,001,311 45.8% 1.64%
Interior Screw-in 216,406 221,755 206,395 217,790 236,400 254,549 17.6% 0.71%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 855 of 1069
Avista Conservation Potential Assessment Study Baseline Forecast
Global Energy Partners, LLC 4-11
An EnerNOC Company
Table 4-6 C&I Baseline Electricity Forecast by End Use and Technology (MWh) (continued)
End Use Technology 2009 2012 2017 2022 2027 2032 % Change
('09–'32)
Avg.
Growth
Rate
Exterior Lighting
HID 132,407 135,795 150,576 164,140 179,105 195,616 47.7% 1.70%
Linear Fluorescent 25,393 25,871 28,196 30,732 33,529 36,611 44.2% 1.59%
Exterior Screw-in 21,795 22,266 23,250 24,657 26,912 29,475 35.2% 1.31%
Office Equipment
Monitor 41,029 53,265 46,532 50,891 55,743 61,060 48.8% 1.73%
Server 74,853 76,495 84,537 93,022 102,358 112,632 50.5% 1.78%
Desktop Computer 154,994 158,861 173,772 187,271 201,951 217,747 40.5% 1.48%
Laptop Computer 13,081 13,425 14,794 15,996 17,306 18,722 43.1% 1.56%
Printer/copier/fax 39,520 40,314 44,034 48,018 52,383 57,096 44.5% 1.60%
POS Terminal 20,873 21,398 23,495 25,853 28,448 31,304 50.0% 1.76%
Miscellaneous
Other Miscellaneous 263,934 269,935 298,454 328,409 361,370 397,639 50.7% 1.78%
Miscellaneous 208,493 225,425 248,425 272,900 300,128 330,453 58.5% 2.00%
Non-HVAC Motor 147,180 150,558 167,722 184,182 202,275 222,371 51.1% 1.79%
Machine Drive
Less than 5 HP 35,529 38,415 41,579 44,045 47,585 52,286 47.2% 1.68%
5-24 HP 76,980 83,231 91,723 100,760 110,813 122,010 58.5% 2.00%
25-99 HP 188,009 203,277 224,017 246,087 270,640 297,986 58.5% 2.00%
100-249 HP 106,588 115,244 127,002 139,514 153,434 168,937 58.5% 2.00%
250-499 HP 116,950 126,448 139,349 153,078 168,351 185,361 58.5% 2.00%
500 and more HP 216,136 233,688 257,531 282,903 311,129 342,566 58.5% 2.00%
Process
Process
Cooling/Refrigeration 102,095 110,387 121,649 133,634 146,967 161,817 58.5% 2.00%
Process Heating 153,143 165,580 182,474 200,451 220,451 242,725 58.5% 2.00%
Electrochemical
Process 85,079 91,989 101,374 111,362 122,473 134,847 58.5% 2.00%
Grand Total 5,033,023 5,172,344 5,592,586 6,061,107 6,618,022 7,250,973 44.1% 1.59%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 856 of 1069
Baseline Forecast Avista Conservation Potential Assessment Study
4-12 www.gepllc.com

4.3 BASELINE FORECAST SUMMARY
Table 4-7 and Figure 4-4 provide an overall summary of the baseline forecast by sector and for the Avista system as a whole. Overall, the forecast
for the next 20 years shows substantial growth, reflecting projected increases in customers and income. This forecast is the metric against which
the energy-efficiency savings potential is compared.
Table 4-7 Baseline Forecast Summary by Sector and State
End Use 2009 2012 2017 2022 2027 2032
% Change
('09–'32)
Avg. Growth
Rate
('09–'32)
Res. WA 2,451,707 2,448,104 2,617,630 2,947,427 3,329,882 3,792,486 54.7% 1.9%
Res. ID 1,182,379 1,178,591 1,253,664 1,408,812 1,588,965 1,808,300 52.9% 1.8%
C&I WA 2,852,165 2,955,156 3,209,083 3,509,816 3,869,176 4,280,649 50.1% 1.8%
C&I ID 2,180,858 2,217,188 2,383,504 2,551,291 2,748,846 2,970,324 36.2% 1.3%
Total 8,667,109 8,799,039 9,463,880 10,417,347 11,536,869 12,851,760 48.3% 1.7%

Figure 4-4 Baseline Forecast Summary by Sector and State

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 857 of 1069
Avista Conservation Potential Assessment Study Baseline Forecast
Global Energy Partners, LLC 4-13
An EnerNOC Company
4.3.1 Comparison of Baseline Forecast with Avista 2009 IRP
Table 4-8 compares the Avista 2009 IRP forecast, the LoadMAP baseline forecast for Washington
and Idaho combined, and the regional forecast from the Sixth Plan. For the LoadMAP baseline
and Avista forecast, the table shows data for the period 2009 through 2030, the last year of the
IRP forecast. The Sixth Plan forecast is the medium case scenario for 2010 through 2030.
Table 4-8 Comparison of LoadMAP Baseline, Avista IRP, and Sixth Plan Energy
Forecasts (MWh)
LoadMAP Baseline Avista IRP14 Sixth
Plan15
Sector 2009 2030
Avg.
Growth
('09-'30)
2009 2030
Avg.
Growth
('09-'30)
Avg.
Growth
('10-'30)
Residential 3,634,086 5,314,970 1.8% 3,700,000 5,048,000 1.5% 1.4%
Commercial 3,331,433 4,457,968 1.4% 3,400,000 4,773,000 1.6% 1.6%
Industrial 1,701,589 2,530,353 1.9% 1,900,000 3,029,000 2.2% 0.8%
Total 8,667,109 12,303,291 1.7% 9,002,009 12,852,030 1.7% 1.4%

The LoadMAP and IRP forecasts do not match exactly for the base year, likely due to the slightly
different ways in which the study team selected rate classes to include and how we grouped
them. Also, the IRP was prepared in September 2009, before final results for 2009 were
available.
Overall growth in energy usage agrees well between LoadMAP and the IRP, at approximately
1.7% annual average growth. However, Global’s forecast for the Residential sector produces
greater growth than the IRP’s projections, while the opposite is true for Commercial and
Industrial sectors. Because the LoadMAP baseline excludes future additional conservation
activities, we would generally expect it to be somewhat higher than the IRP forecast, as is the
case with the Residential sector. In general, the Sixth Plan forecast, which also excludes
additional conservation, is lower than both the LoadMAP and Avista IRP forecasts, with the
exception of the Commercial sector, where the Sixth Plan and the Avista IRP agree.
Retail Electricity Prices
Table 4-9 compares retail electricity prices used in the LoadMAP model and those projected in
the IRP.
Table 4-9 Comparison of Retail Electricity Prices
LoadMAP Avista IRP16
Sector 2009
($/kWh)
2018
($/kWh)
Avg.
Growth
('09-'18)
2019
($/kWh)
2032
($/kWh)
Avg.
Growth
('19-'32)
Avg.
Growth
('19-'32)
Avg.
Growth
('19-'30)
Res. WA $0.072 $0.080 1.2% $0.0818 $0.087 0.5% 10.0% Inflation
Res. ID $0.074 $0.088 1.8% $0.089 $0.094 0.5% 10.0% Inflation
C&I WA $0.0700 $0.0703 0.1% $0.0713 $0.0778 0.7% 10.0% Inflation
C&I ID $0.0566 $0.0600 0.6% $0.0608 $0.0664 0.7% 10.0% inflation

14 Avista forecast from 2009 IRP, Figure 2.10 and p. 2-12. 15 NPCC Sixth Northwest Conservation and Electric Power Plan, p. C-6, table C-3. 16 Avista 2009 IRP, p. 2-9.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 858 of 1069
Baseline Forecast Avista Conservation Potential Assessment Study
4-14 www.gepllc.com
Avista’s IRP forecast ―is based on retail prices increasing an average of 10 percent annually from
2010 to 2018, followed by increases at the rate of inflation thereafter.‖ However, Avista’s most
recent load forecast for 2011–2015 shows lower annual rate increases. For this study, Global
used the rates from the 2011–2015 load forecast and thereafter, based on data from the AEO,
increased rates by 0.50% and 0.68% respectively for residential and C/I customers.
Residential Energy Use per Household
As mentioned above, the LoadMAP residential baseline energy use forecast is higher than the IRP
residential forecast. Furthermore, the baseline forecast of energy use per household is notably
different, with average growth of 0.6% compared with Avista IRP showing that energy use per
household decreases over time.17
Long-Term Weather
This study used the 30-year normal weather data. In contrast, the IRP mentions warming trends
in recent weather. Although the model does not directly account for climate changes, the
residential market profiles show an increase in air conditioning saturation over time, which
indirectly reflects weather trends.

17 Avista 2009 IRP Figure 2.9, p. 2-11.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 859 of 1069

Global Energy Partners, LLC 5-1
An EnerNOC Company
CHAPTER 5
ENERGY-EFFICIENCY MEASURE ANALYSIS
This section describes the framework used to assess the savings, costs, and other attributes of
energy-efficiency measures. These characteristics form the basis for measure-level cost-
effectiveness analyses as well as for determining measure-level savings. For all measures, Global
assembled information to reflect equipment performance, incremental costs, and equipment
lifetimes. We used this information, along with the avoided costs, in the economic screen to
determine economically feasible measures. Figure 5-1 outlines the framework for measure
analysis.
Figure 5-1 Approach for Measure Assessment

5.1 SELECTION OF ENERGY EFFICIENCY MEASURES
The first step of the energy efficiency measure analysis was to identify the list of all relevant
energy efficiency measures that should be considered for the Avista CPA. Sources consulted to
develop the list for this study included:
Avista’s existing conservation programs
The Sixth Power Plan database of EE measure costs and savings
NEEA’s Regional Technical Forum
Database for Energy Efficient Resources (DEER): The California Energy Commission and
California Public Utilities Commission (CPUC) sponsor this database, which is designed to
provide well-documented estimates of energy and peak demand savings values, measure
costs, and effective useful life (EUL) all with one data source for the state of California.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 860 of 1069
Energy-Efficiency Measure Analysis Avista Conservation Potential Assessment Study
5-2 www.gepllc.com

Global’s Database of Energy Efficiency Measures (DEEM). In 2004, Global prepared a
database of energy efficiency measures for residential and commercial segments across the
U.S., analogous to the DEER database developed for California. Global updates the database
on a regular basis as it conducts new energy efficiency potential studies.
EPRI National Potential Study (2009). Global’s assessment of the national potential for
energy efficiency derived for the four DOE regions (including the Pacific region.
Other recent Global potential studies
Measures can be categorized into one of two types, equipment measures and non-equipment
measures, according to the LoadMAP taxonomy:
Equipment measures, or efficient energy-consuming equipment, save energy by providing the
same service with a lower energy requirement. An example is the replacement of a standard
efficiency refrigerator with an ENERGY STAR model. For equipment measures, many efficiency
levels are available for a specific technology that range from the baseline unit (often determined
by code or standard) up to the most efficient product commercially available. For instance, in the
case of central air conditioners, this list begins with the federal standard SEER 13 unit and spans
a broad spectrum of efficiency, with the highest efficiency level represented by a ductless mini-
split system with variable refrigerant flow (at SEER levels of 18 or greater).
Non-equipment measures save energy by reducing the need for delivered energy but do not
involve replacement or purchase of major end-use equipment (such as a refrigerator or air
conditioner). An example would be a programmable thermostat that is pre-set, for example, to
run the air conditioner only when people are home. Non-equipment measures fall into one of the
following categories:
Building shell (windows, insulation, roofing material)
Equipment controls (thermostat, occupancy sensors)
Equipment maintenance (cleaning filters, changing setpoints)
Whole-building design (natural ventilation, passive solar lighting)
Lighting retrofits (included as a non-equipment measure because retrofits are performed
prior to the equipment’s normal end of life)
Displacement measures (ceiling fan instead of central air conditioner)
Non-equipment measures can apply to more than one end use. For example, insulation levels will
affect both cooling and space heating energy consumption.
Global prepared a preliminary list of measures for Avista’s review and revised the list based on
Avista’s input.
5.1.1 Residential Measures
Table 5-1 and Table 5-2 show the residential equipment and non-equipment measure options
respectively and the segments for which they were modeled. Residential measures are described
in Appendix C.
5.1.2 Commercial and Industrial Measures
Table 5-3and Table 5-4 list the C&I equipment and non-equipment measures, respectively.
Measures were modeled for nearly all C&I building types, both new and existing, with only a few
exceptions as shown. For all C&I segments, a custom measure category was included to serve as
a ―catch all‖ for measures for which costs and savings are not easily quantified and that could be
part of a program such as Avista’s existing Site-Specific incentive program. In addition, because
the Small/Medium Commercial and Large Commercial segments also include some industrial
customers, we included a non-equipment measure called Industrial Process Improvements to
capture potential savings from these customers. C&I Measures are described in Appendix D.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 861 of 1069
Avista Conservation Potential Assessment Study Energy-Efficiency Measure Analysis
Global Energy Partners, LLC 5-3
An EnerNOC Company
Table 5-1 Summary of Residential Equipment Measures

End Use Technology Efficiency Option Eff
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End Use Technology Efficiency Option
Cooling
Central AC SEER 13 100%15 2009 2014
Central AC SEER 14 (ENERGY STAR)92%15 2009 2032
Central AC SEER 15 (CEE Tier 2)89%15 2009 2032
Central AC SEER 16 (CEE Tier 3)86%15 2009 2032
Central AC Ductless Mini-Split System 75%20 2009 2032
Room AC EER 9.8 100%10 2009 2032
Room AC EER 10.8 (ENERGY STAR)91%10 2009 2032
Room AC EER 11 89%10 2009 2032
Room AC EER 11.5 85%10 2009 2032
Air Source Heat Pump SEER 13 100%15 2009 2014
Air Source Heat Pump SEER 14 (ENERGY STAR)92%15 2009 2032
Air Source Heat Pump SEER 15 (CEE Tier 2)89%15 2009 2032
Air Source Heat Pump SEER 16 (CEE Tier 3)86%15 2009 2032
Air Source Heat Pump Ductless Mini-Split System 75%20 2009 2032
Geothermal Heat Pump Standard 100%14 2009 2032
Geothermal Heat Pump High Efficiency 86%14 2009 2032
Electric Resistance Electric Resistance 100%20 2009 2032
Electric Furnace 3400 BTU/KW 100%15 2009 2032
Supplemental Supplemental 100%5 2009 2032
Water Heater Baseline (EF=0.90)100%15 2009 2015
Water Heater High Efficiency (EF=0.95)95%15 2009 2032
Water Heater Geothermal Heat Pump 32%15 2009 2032
Water Heater Solar 25%15 2009 2032
Screw-in Incandescent 100%4 2009 2014
Screw-in Infrared Halogen 81%5 2015 2020
Screw-in CFL 22%6 2009 2032
Screw-in LED 14%12 2009 2032
Linear Fluorescent T12 100%6 2009 2032
Linear Fluorescent T8 91%6 2009 2032
Linear Fluorescent Super T8 74%6 2009 2032
Linear Fluorescent T5 73%6 2009 2032
Linear Fluorescent LED 72%10 2009 2032
Pin-based Halogen 100%4 2009 2032
Pin-based CFL 23%6 2009 2032
Pin-based LED 16%10 2009 2032
Screw-in Incandescent 100%4 2009 2014
Screw-in Infrared Halogen 79%5 2015 2020
Screw-in CFL 20%6 2009 2032
Screw-in LED 14%12 2009 2032
High Intensity/Flood Incandescent 100%4 2009 2014
High Intensity/Flood Infrared Halogen 88%4 2015 2020
High Intensity/Flood CFL 29%5 2009 2032
High Intensity/Flood Metal Halide 27%5 2009 2032
High Intensity/Flood High Pressure Sodium 19%5 2009 2032
High Intensity/Flood LED 18%10 2009 2032
Cooling
Heat & Cool
Space
Heating
Water
Heating
Interior
Lighting
Exterior
Lighting
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 862 of 1069
Energy-Efficiency Measure Analysis Avista Conservation Potential Assessment Study
5-4 www.gepllc.com

Table 5-1 Summary of Residential Equipment Measures (continued)

End Use Technology Efficiency Option Eff
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Appliances
Clothes Washer Baseline 100%10 2009 2032
Clothes Washer ENERGY STAR (MEF > 1.8)70%10 2009 2032
Clothes Washer Horizontal Axis 42%10 2009 2032
Clothes Dryer Baseline 100%13 2009 2032
Clothes Dryer Moisture Detection 85%13 2009 2032
Dishwasher Baseline 100%9 2009 2032
Dishwasher ENERGY STAR 85%9 2009 2010
Dishwasher ENERGY STAR (2011)81%9 2011 2032
Refrigerator Baseline 100%13 2009 2013
Refrigerator ENERGY STAR 85%13 2009 2013
Refrigerator Baseline (2014)80%13 2014 2032
Refrigerator ENERGY STAR (2014)68%13 2014 2032
Freezer Baseline 100%11 2009 2013
Freezer ENERGY STAR 85%11 2009 2013
Freezer Baseline (2014)80%11 2014 2032
Freezer ENERGY STAR (2014)68%11 2014 2032
Second Refrigerator Baseline 100%13 2009 2013
Second Refrigerator ENERGY STAR 85%13 2009 2013
Second Refrigerator Baseline (2014)80%13 2014 2032
Second Refrigerator ENERGY STAR (2014)68%13 2014 2032
Stove Baseline 100%13 2009 2032
Stove Convection Oven 98%13 2009 2032
Stove Induction (High Efficiency)88%13 2009 2032
Microwave Microwave 100%9 2009 2032
Personal Computers Baseline 100%5 2009 2032
Personal Computers ENERGY STAR 65%5 2009 2032
Personal Computers Climate Savers 50%5 2009 2032
TVs Baseline 100%11 2009 2032
TVs ENERGY STAR 80%11 2009 2032
Devices and Gadgets Devices and Gadgets 100%5 2009 2032
Pool Pump Baseline Pump 100%15 2009 2032
Pool Pump High Efficiency Pump 90%15 2009 2032
Pool Pump Two-Speed Pump 60%15 2009 2032
Furnace Fan Baseline 100%18 2009 2032
Furnace Fan Furnace Fan with ECM 75%18 2009 2032
Miscellaneous Miscellaneous 100%5 2009 2032
Appliances
Electronics
Miscellaneous
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 863 of 1069
Avista Conservation Potential Assessment Study Energy-Efficiency Measure Analysis
Global Energy Partners, LLC 5-5
An EnerNOC Company
Table 5-2 Summary of Residential Non-equipment Measures

End Use Measure Sin
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HVAC
Central AC - Early Replacement
Central AC - Maintenance and Tune-Up
Room AC - Removal of Second Unit
Air Source Heat Pump - Maintenance
Furnace - Convert to Gas
Attic Fan - Installation
Attic Fan - Photovoltaic - Installation
Ceiling Fan - Installation
Whole-House Fan - Installation
Thermostat - Clock/Programmable
Insulation - Ceiling / Attic
Insulation - Radiant Barrier
Insulation - Infiltration Control
Insulation - Ducting
Repair and Sealing - Ducting
Insulation - Foundation
Insulation - Wall Cavity
Insulation - Wall Sheathing
Doors - Storm and Thermal
Windows - Reflective Film
Windows - High Efficiency/ENERGY STAR
Roofs - High Reflectivity
Trees for Shading
Int. Lighting Interior Lighting - Occupancy Sensors
Exterior Lighting - Photovoltaic Installation
Exterior Lighting - Photosensor Control
Exterior Lighting - Timeclock Installation
Water Heater - Faucet Aerators
Water Heater - Pipe Insulation
Water Heater - Low Flow Showerheads
Water Heater - Tank Blanket/Insulation
Water Heater - Thermostat Setback
Water Heater - Timer
Water Heater - Hot Water Saver
Water Heater - Drainwater Heat Recovery
Water Heater - Convert to Gas
Water Heater - Heat Pump Water Heater
Refrigerator - Early Replacement
Refrigerator - Remove Second Unit
Freezer - Early Replacement
Freezer - Remove Second Unit
Electronics Electronics - Reduce Standby Wattage
Misc.Pool - Pump Timer
Home Energy Management System
Advanced New Construction Designs
Energy Efficient Manufactured Homes
ENERGY STAR Homes
Photovoltaic System
HVAC
Exterior
Lighting
Water Heating
Appliances
Multiple End
Uses
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 864 of 1069
Energy-Efficiency Measure Analysis Avista Conservation Potential Assessment Study
5-6 www.gepllc.com

Table 5-3 Summary of Commercial and Industrial Equipment Measures

End Use Technology Efficiency Option Sm
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Cooling
Central Chiller 1.5 kW/ton, COP 2.3
Central Chiller 1.3 kW/ton, COP 2.7
Central Chiller 1.26 kW/ton, COP 2.8
Central Chiller 1.0 kW/ton, COP 3.5
Central Chiller 0.97 kW/ton, COP 3.6
Central Chiller 0.75 kw/ton, COP 4.7
Central Chiller 0.60 kw/ton, COP 5.9
Central Chiller 0.58 kw/ton, COP 6.1
Central Chiller 0.55 kw/Ton, COP 6.4
Central Chiller 0.51 kw/ton, COP 6.9
Central Chiller 0.50 kw/Ton, COP 7.0
Central Chiller 0.48 kw/ton, COP 7.3
Central Chiller Variable Refrigerant Flow
RTU EER 9.2
RTU EER 10.1
RTU EER 11.2
RTU EER 12.0
RTU Ductless VRF
PTAC EER 9.8
PTAC EER 10.2
PTAC EER 10.8
PTAC EER 11
PTAC EER 11.5
Heat Pump EER 9.3, COP 3.1
Heat Pump EER 10.3, COP 3.2
Heat Pump EER 11.0, COP 3.3
Heat Pump EER 11.7, COP 3.4
Heat Pump EER 12, COP 3.4
Heat Pump Ductless Mini-Split System
Heat Pump Geothermal*
Electric Resistance Standard
Furnace Standard
Ventilation Constant Volume
Ventilation Variable Air Volume
* New construction only
Cooling
Heat & Cool
Space
Heating
Ventilation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 865 of 1069
Avista Conservation Potential Assessment Study Energy-Efficiency Measure Analysis
Global Energy Partners, LLC 5-7
An EnerNOC Company
Table 5-3 Summary of Commercial and Industrial Equipment Measures (continued)

End Use Technology Efficiency Option Sm
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Interior
Lighting
Interior Screw-in Incandescents
Interior Screw-in Infrared Halogen
Interior Screw-in CFL
Interior Screw-in LED
HID Metal Halides
HID High Pressure Sodium
Linear Fluorescent T12
Linear Fluorescent T8
Linear Fluorescent Super T8
Linear Fluorescent T5
Linear Fluorescent LED
Exterior Screw-in Incandescents
Exterior Screw-in Infrared Halogen
Exterior Screw-in CFL
Exterior Screw-in Metal Halides
Exterior Screw-in LED
HID Metal Halides
HID High Pressure Sodium
HID Low Pressure Sodium
Linear Fluorescent T12
Linear Fluorescent T8
Linear Fluorescent Super T8
Linear Fluorescent T5
Linear Fluorescent LED
Water Heater Baseline (EF=0.90)
Water Heater High Efficiency (EF=0.95)
Water Heater Geothermal Heat Pump
Water Heater Solar
Fryer Standard
Fryer Efficient
Oven Standard
Oven Efficient
Dishwasher Standard
Dishwasher Efficient
Hot Food Container Standard
Hot Food Container Efficient
Food Prep Misc.Standard
Food Prep Misc.Efficient
Water
Heating
Food
Preparation
Exterior
Lighting
Interior
Lighting
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 866 of 1069
Energy-Efficiency Measure Analysis Avista Conservation Potential Assessment Study
5-8 www.gepllc.com

Table 5-3 Summary of Commercial and Industrial Equipment Measures (continued)

End Use Technology Efficiency Option Sm
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Walk in Refrigeration Standard
Walk in Refrigeration Efficient
Glass Door Display Standard
Glass Door Display Efficient
Solid Door Refrigerator Standard
Solid Door Refrigerator Efficient
Open Display Case Standard
Open Display Case Efficient
Vending Machine Base
Vending Machine Base (2012)
Vending Machine High Efficiency
Vending Machine High Efficiency (2012)
Icemaker Standard
Icemaker Efficient
Desktop Computer Baseline
Desktop Computer ENERGY STAR
Desktop Computer Climate Savers
Laptop Computer Baseline
Laptop Computer ENERGY STAR
Laptop Computer Climate Savers
Server Standard
Server ENERGY STAR
Monitor Standard
Monitor ENERGY STAR
Printer/copier/fax Standard
Printer/copier/fax ENERGY STAR
POS Terminal Standard
POS Terminal ENERGY STAR
Non-HVAC Motor Standard
Non-HVAC Motor Standard (2015)
Non-HVAC Motor High Efficiency
Non-HVAC Motor High Efficiency (2015)
Non-HVAC Motor Premium
Non-HVAC Motor Premium (2015)
Other Miscellaneous Miscellaneous
Other Miscellaneous Miscellaneous (2013)
Refrigeration
Office
Equipment
Miscellaneous
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 867 of 1069
Avista Conservation Potential Assessment Study Energy-Efficiency Measure Analysis
Global Energy Partners, LLC 5-9
An EnerNOC Company
Table 5-3 Summary of Commercial and Industrial Equipment Measures (continued)

End Use Technology Efficiency Option Sm
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Less than 5 HP Standard
Less than 5 HP High Efficiency
Less than 5 HP Standard (2015)
Less than 5 HP Premium
Less than 5 HP High Efficiency (2015)
Less than 5 HP Premium (2015)
5-24 HP Standard
5-24 HP High
5-24 HP Premium
25-99 HP Standard
25-99 HP High
25-99 HP Premium
100-249 HP Standard
100-249 HP High
100-249 HP Premium
250-499 HP Standard
250-499 HP High
250-499 HP Premium
500 and more HP Standard
500 and more HP High
500 and more HP Premium
Process Cooling/Refrig.Standard
Process Cooling/Refrig.Efficient
Process Heating Standard
Process Heating Efficient
Electrochemical Process Standard
Electrochemical Process Efficient
Process
Machine
Drive
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 868 of 1069
Energy-Efficiency Measure Analysis Avista Conservation Potential Assessment Study
5-10 www.gepllc.com

Table 5-4 Summary of Commercial and Industrial Non-equipment Measures
Note: Conversion of electric furnaces to gas was only modeled for Small/Medium Commercial segment.
End Use Measure Co
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HVAC
RTU - Maintenance
RTU - Evaporative Precooler
Chiller - Chilled Water Reset
Chiller - Chilled Water Variable-Flow System
Chiller - Condenser Water Temprature Reset
Chiller - High Efficiency Cooling Tower Fans
Chiller - Turbocor Compressor
Chiller - VSD
Cooling - Economizer Installation
Heat Pump - Maintenance
Insulation - Ducting
Repair and Sealing - Ducting
Insulation - Ceiling
Insulation - Radiant Barrier
Insulation - Wall Cavity
Cooking - Exhaust Hoods with Sensor Control
Fans - Energy Efficient Motors
Fans - Variable Speed Control
Pumps - Variable Speed Control
Thermostat - Clock/Programmable
Roofs - High Reflectivity
Roofs - Green
Windows - High Efficiency
Retrocommissioning - HVAC
Commissioning - HVAC
Furnace - Convert to Gas
Interior Fluorescent - Photocell Controlled T8 Dimming Ballasts
Interior Fluorescent - Delamp and Install Reflectors
Interior Fluorescent - Bi-Level Fixture w/Occupancy Sensor
Interior Fluorescent - High Bay Fixtures
Interior Screw-in - Task Lighting
Central Lighting Controls
Occupancy Sensors
Time Clocks and Timers
LED Exit Lighting
Hotel Guestroom Controls
Retrocommissioning - Lighting
Commissioning - Lighting
Daylighting Controls
Photovoltaic Installation
Cold Cathode Lighting
Induction Lamps
HVAC
Exterior Lighting
Interior Lighting
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 869 of 1069
Avista Conservation Potential Assessment Study Energy-Efficiency Measure Analysis
Global Energy Partners, LLC 5-11
An EnerNOC Company
Table 5-4 Summary of Commercial and Industrial Non-equipment Measures
(continued)
Note: Conversion of electric water heaters to gas only modeled for Small/Medium Commercial segment.
End Use Measure Co
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Water Heating
Faucet Aerators/Low Flow Nozzles
Hot Water Saver
Pipe Insulation
Tank Blanket/Insulation
Thermostat Setback
Convert to Gas
Heat Pump Water Heater
Floating Head Pressure
Insulation - Bare Suction Lines
Demand Defrost
High Efficiency Case Lighting
Evaporator Fan Controls
Anti-Sweat Heater/Auto Door Closer
Door Gasket Replacement
Night Covers
Strip Curtain
Vending Machine - Controller
Office Equipment ENERGY STAR Power Supply
Laundry - High Efficiency Clothes Washer
Miscellaneous - Energy Star Water Cooler
Motors - Variable Frequency Drive
Motors - Magnetic Adjustable Speed Drives
Compressed Air - System Controls
Compressed Air - System Optimization & Improvements
Compressed Air - System Maintenance
Compressed Air - Compressor Replacement
Fan System - Controls
Fan System - Optimization
Fan System - Maintenance
Pumping System - Controls
Pumping System - Optimization
Pumping System - Maintenance
Pumps - Variable Speed Control
Industrial Process Improvements
Refrigeration - System Controls
Refrigeration - System Maintenance
Refrigeration - System Optimization
Energy Management System
Retrocommissioning - Comprehensive
Advanced New Construction Designs
Commissioning - Comprehensive
Pumps - Variable Speed Control
Custom Measures
Machine Drive
Industrial
Process
Miscellaneous
Multiple End Uses
Refrigeration
Water Heating
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 870 of 1069
Energy-Efficiency Measure Analysis Avista Conservation Potential Assessment Study
5-12 www.gepllc.com

5.2 MEASURE CHARACTERISTICS
For each measure considered, the Global team developed the following data for input to the
LoadMAP model:
Energy Impacts: The energy-savings impacts represent the annual reduction in consumption
attributable to each specific measure. Savings were developed as a percentage of the energy end
use that the measure affects. This approach takes into account the efficiency of the equipment
that is providing that end use. For example, savings due to increased insulation will be greater if
heating is provided by electric resistance, and lower if heating is provided by a heat pump. For
the residential and commercial sectors, the BEST simulation model was used to determine the
savings impacts. The key advantage of utilizing BEST is that interactive effects between HVAC
measures and other measures such as lighting and building construction are captured and
quantified. In addition, the prototype modeling combines the primary market data with Spokane-
specific Typical Meteorological Year (TMY) weather data to derive savings. For the industrial
sector, secondary data resources such as the EPRI National Potential Study and DEEM were used
to develop assessments of savings at the end-use level.
Peak Demand Impacts: Savings during the peak demand periods are specified for each
measure. These impacts relate to the energy savings and depend on each measure’s
―coincidence‖ with the system peak. To accurately express the peak impacts of the energy
efficiency measures considered, the project used a combined approach of prototype simulation
(BEST model) and Global’s proprietary end-use load shape database, EnergyShape.
Costs: For equipment measures, the measure characterization includes the full cost of
purchasing and installing the equipment on a per-unit or per-square-foot basis for the residential
and C&I sectors, respectively. For non-equipment measures in existing buildings, the cost
likewise represents the full installed cost. For non-equipment measures in new construction, the
approach is slightly different; the costs may be either the full cost of the measure, for example a
programmable thermostat, or as appropriate, it may be the incremental cost of upgrading from a
standard level to a higher efficiency level, such as upgrading from R13 to R26 insulation. These
costs were developed specifically for the Spokane area and drew upon sources including the Sixth
Plan databases.
Measure Lifetimes: These estimates were derived from the technical data and secondary data
sources that support the measure demand and energy savings analysis. Values were obtained
from the Sixth Plan database, DEER database, DEEM, and other secondary sources.
Applicability: This factor is an estimate of the percentage of either dwellings in the residential
sector or square feet in the C&I sectors where it is technically feasible for the specific measure to
be implemented. These figures are based on secondary data sources such as NEEA reports,
California’s DEER database, DEEM, and others.
On Market and Off Market Availability: To account for the fact that some equipment will no
longer be available for sale due to changes in appliance standards, or that some high-efficiency
equipment is expected to enter the market during the study period, the project also developed
on market and off market inputs, expressed as years, for the equipment measures.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 871 of 1069
Avista Conservation Potential Assessment Study Energy-Efficiency Measure Analysis
Global Energy Partners, LLC 5-13
An EnerNOC Company
5.2.1 Measure Cost Data Development
Costs for equipment and non-equipment measures include both material and labor costs
associated with the measure’s installation. These costs draw upon national construction cost
averages.
The following references were used to develop the equipment and measure costs:
Sixth Northwest Conservation and Electric Power Plan Conservation Supply Curves workbooks
DEER – California Database for Energy Efficient Resources
RS Means Facilities Maintenance and Repair Cost Data
RS Means Mechanical Construction Costs
RS Means Building Construction Cost Data
USGBC — LEED New Construction & Major Renovation (2008)
RS Means Green Buildings Project Planning & Cost Estimating Second Edition (2008)
Grainger Catalog Volume 398, (2007-2008)
5.2.2 Representative Measure Data Inputs
To provide an example of the measure data, Table 5-5 and Table 5-6 present samples of the
detailed data inputs behind equipment and non-equipment measures, respectively, for the case
of residential central air conditioning in single-family homes. Table 5-5 displays the various
efficiency levels available as equipment measures, as well as the corresponding useful life,
usage, and cost estimates. These values all contribute to the outcome of the stock accounting
model, in which the purchase of an above-standard unit is first analyzed for cost-effectiveness
(comparing incremental cost to lifetime benefits) and then, for the levels that pass the screen,
incorporated into the new units purchased.
Table 5-5 Sample Equipment Measures for Central Air Conditioning — Single Family
Home Segment
Efficiency Level Useful Life Equipment
Cost
Energy
Usage(kWh/yr)
On
Market
Off
Market
SEER 13 15 $3,794 1,619 2009 2014
SEER 14 (ENERGY STAR) 15 $4,072 1,485 2009 2032
SEER 15 (CEE Tier 2) 15 $4,350 1,435 2009 2032
SEER 16 (CEE Tier 3) 15 $4,628 1,393 2009 2032
Ductless Mini-split System 20 $8,193 1,214 2009 2032

Table 5-6 lists the non-equipment measures affecting an existing single-family home’s central air
conditioning electricity use. These measures are also evaluated for cost-effectiveness based on
the lifetime benefits relative to the cost of the measure. The total savings are calculated for each
year of the model and depend on the base year saturation of the measure, the overall
applicability of the measure, and the savings as a percentage of the relevant energy end uses.
Residential central air conditioning provides energy savings, but no demand savings due to
Avista’s existing heating season peak. In addition to the Applicability factor, a Feasibility factor is
applied to account for the feasibility of installing the measure.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 872 of 1069
Energy-Efficiency Measure Analysis Avista Conservation Potential Assessment Study
5-14 www.gepllc.com

Table 5-6 Sample Non-Equipment Measures – Single Family Homes, Existing
End
Use Measure
Satura-
tion in
200918
Applica-
bility
Feasi-
bility
Lifetime
(years)
Measure
Installed
Cost
Energy
Savings
(%)
Demand
Savings
(%)
Cooling Central AC — Early
Replacement 0% 80% 10% 15 $2,895 10.0% 0%
Cooling Central AC — Maintenance
and Tune-Up 41% 100% 100% 4 $125 10.0% 0%
Cooling Attic Fan — Installation 11% 50% 45% 18 $116 0.7% 0%
Cooling Attic Fan — Photovoltaic 13% 100% 45% 19 $350 1.4% 0%
Cooling Ceiling Fan 52% 100% 75% 15 $160 11.0% 0%
Cooling Whole-House Fan 7% 25% 75% 18 $200 9.0% 0%
Cooling Insulation — Ducting 15% 100% 75% 18 $500 3.0% 0%
Cooling Repair and Sealing — Ducting 12% 100% 50% 18 $500 10.0% 0%
Cooling Doors — Storm and Thermal 38% 100% 75% 11 $320 1.0% 0%
Cooling Insulation — Infiltration
Control 46% 100% 90% 12 $266 3.0% 0%
Cooling Insulation — Ceiling 68% 90% 80% 20 $594 3.0% 0%
Cooling Insulation — Radiant Barrier 5% 100% 90% 12 $923 5.0% 0%
Cooling Roofs — High Reflectivity 5% 100% 10% 15 $1,550 6.1% 0%
Cooling Windows — Reflective Film 5% 50% 90% 10 $267 7.0% 0%
Cooling Windows — High
Efficiency/ENERGY STAR 83% 100% 90% 25 $7,500 12.0% 0%
Cooling Thermostat —
Clock/Programmable 55% 75% 75% 11 $114 8.0% 0%
Cooling Home Energy Management
System 20% 50% 75% 20 $300 10.0% 0%
Cooling Photovoltaics 0% 80% 60% 15 $17,000 50.0% 0%
Cooling Trees for Shading 10% 90% 75% 20 $40 1.1% 0%

5.2.3 Conversion to Natural Gas
Conversion to natural gas (fuel switching) for both space heating and water heating was
evaluated as a special case. These options were evaluated as non-equipment measures, though
of course, they are in fact equipment changes. Modeling conversion to gas as a non-equipment
measure allowed using the applicability and feasibility factors to better account for customers’
real ability to implement these technologies.
For conversion of water heaters to natural gas, an applicability factor was developed based on
Avista GIS data combined with the market profiles to indicate that approximately 63% of
Washington homes and 57% of Idaho homes with electric water heating are within 500 feet of a
gas main. The feasibility factor of 80% assumes that other factors, such as inability to
accommodate venting, would prevent 20% of customers from making the switch to gas water
heating. For heat pump water heaters, we assumed the technology is applicable to the remaining
customers (100% – (63% * 80%) = 50% in Washington and 54% using a similar calculation for

18 Note that saturation levels reflected for 2009 change over time as more measures are adopted.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 873 of 1069
Avista Conservation Potential Assessment Study Energy-Efficiency Measure Analysis
Global Energy Partners, LLC 5-15
An EnerNOC Company
Idaho). However, the feasibility factor is 50% for single family homes because only about half of
these customers have water heating systems with tanks larger than 55 gallons that are suitable
for heat pump water heaters. For the other housing types, the feasibility factors were lower due
to the still lower saturation of larger than 55 gallon water heating systems. Conversion of electric
furnaces to gas was modeled using similar assumptions.
Table 5-7 shows assumptions for water heating non-equipment measures in Washington single-
family homes, including the conversion to gas and heat pump measures discussed above.
Table 5-7 Sample Non-Equipment Water Heating Measures – Single Family Homes,
Existing, Washington
End Use Measure
Satura-
tion in
200919
Applica-
bility
Feasi-
bility
Lifetime
(years)
Measure
Installed
Cost
Energy
Savings
(%)
Demand
Savings
(%)
Water Heating Faucet Aerators 53% 100% 90% 25 $24 3.7% 1.9%
Water Heating Pipe Insulation 17% 100% 38% 13 $180 5.7% 2.9%
Water Heating Low Flow Showerheads 75% 100% 80% 10 $96 17.1% 8.6%
Water Heating Tank Blanket/Insulation 17% 100% 75% 10 $15 9.1% 4.6%
Water Heating Thermostat Setback 17% 100% 75% 5 $40 9.1% 4.6%
Water Heating Timer 17% 100% 40% 10 $194 8.0% 4.0%
Water Heating Hot Water Saver 5% 100% 50% 5 $35 8.8% 4.4%
Water Heating Convert to Gas 0% 63% 80% 15 $3,675 100.0% 100.0%
Water Heating Heat Pump 0% 50% 50% 15 $1,500 30.0% 15.0%

The equipment measure data tables for all energy efficiency measures assessed in this study are
presented in Appendix C for the residential sector and Appendix C for the C&I sectors.
5.3 APPLICATION OF MEASURES FOR TECHNICAL POTENTIAL
Technical potential, as we defined it in Chapter 2, is a theoretical construct that assumes the
highest efficiency measures that are technically feasible to install are adopted by customers,
regardless of cost or customer preferences. Thus, determining the technical potential is relatively
straightforward; LoadMAP uses the energy use associated with the most efficient equipment
options for each end use and technology, as well as the energy savings for all defined non-
equipment measures that apply to that end use and technology, to calculate energy use at the
technical potential level. For example, for residential central air conditioning, as shown in Table
5-5, the most efficient option is a ductless mini-split system. The multiple non-equipment
measures shown in Table 5-7 are then applied to the energy used by the ductless mini-split
system to further reduce CAC energy use. LoadMAP applies the savings due to the non-
equipment measures one-by-one to avoid double counting of savings. The measures are
evaluated in order of their B/C ratio, with the measure with the highest B/C ratio applied first.
Each time a measure is applied, the baseline energy use for the end use is reduced and the
percentage savings for the next measure is applied to the revised (lower) usage.
5.4 APPLICATION OF MEASURES FOR ECONOMIC POTENTIAL
Next, to determine the economic level of efficiency potential, it is necessary to perform an
economic screen on each individual measure. The economic screen applied in this study for non-

19 Note that saturation levels reflected for 2009 change over time as more measures are adopted.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 874 of 1069
Energy-Efficiency Measure Analysis Avista Conservation Potential Assessment Study
5-16 www.gepllc.com

equipment measures is a total resource cost (TRC) test that compares the lifetime benefits (both
energy and peak demand) of each applicable measure with installed cost (including material,
labor, and administration of a delivery mechanism, such as an energy efficiency program).20 The
lifetime benefits are obtained by multiplying the annual energy and demand savings for each
measure by all appropriate avoided costs for each year, and discounting the dollar savings to the
present value equivalent. Global assigns each measure values for savings, costs, and lifetimes as
part of our measure characterization process. For economic screening of measures, incentives
are not included because they represent a simple transfer from one party to another but have no
effect on the overall measure cost.
The lifetime benefits of each energy efficiency measure depend on the forecast of Avista avoided
costs. Avista provided projected avoided costs for energy and capacity over the study period.
Figure 5-2 shows the avoided energy costs for the residential and C&I segments, which are 2009
real $/MWh and include Avista’s adjustments for risk and the 10% Power Act premium. The
avoided energy costs differ by segment due to the segments’ differing load shapes. Figure 5-2
also shows the avoided capacity costs for Avista’s overall system in 2009 real $/kW.
The LoadMAP model performs the economic screening dynamically, taking into account changing
savings and cost data over time. Thus, some measures pass the economic screen for some —
but not all — of the years in the forecast.
It is important to note the following about the economic screen:
The economic evaluation of every measure in the screen is conducted relative to a baseline
condition. For instance, in order to determine the kilowatt-hour (kWh) savings potential of a
measure, kWh consumption with the measure applied must be compared to the kWh
consumption of a baseline condition.
The economic screening was conducted only for measures that are applicable to each
building type and vintage; thus if a measure is deemed to be irrelevant to a particular
building type and vintage, it is excluded from the respective economic screen table.

20 Note that the TRC test is typically the industry standard for evaluating measure-level cost-effectiveness. There are other test
perspectives that are often considered in energy efficiency potential studies. The Participant test measures the benefits and costs from
the perspective of program participants as a whole. The Ratepayer Impact Measure (RIM) test measures the difference between the
change in total revenues paid to a utility and the change in total costs to a utility resulting from the energy efficiency and demand
response programs. The Utility Cost (UC) test measures the costs and benefits from the perspective of the utility administering the
program. Neither the RIM nor UC tests are typically applied in the context of measure-level economic screens, but rather in the
broader context of energy efficiency programs and initiatives put into place to deliver the energy efficiency measures.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 875 of 1069
Avista Conservation Potential Assessment Study Energy-Efficiency Measure Analysis
Global Energy Partners, LLC 5-17
An EnerNOC Company
Figure 5-2 Avoided Costs for Energy and Capacity

5.4.1 Equipment Measures Economic Screening
For equipment measures, LoadMAP evaluates the cost-effectiveness of each measure option,
compared to the efficiency option that immediately precedes it. Continuing with the example of
residential central air conditioning, as shown in Table 5-5, the standard efficiency option in 2010
is SEER 13. LoadMAP calculates the lifetime benefits and costs associated with each of the higher
efficiency options to select the option with the highest net present value.
Table 5-8 shows the results of the economic screen for CAC for selected years, as well as results
for two interior lighting technologies. In 2010, the most cost-effective option is SEER 14, while in
2012, due to rising energy costs, it changes to SEER 15. However, in 2015, due to federal energy
efficiency standards, the SEER 13 unit goes off the market and SEER 14 becomes the standard
efficiency unit. In 2015 and beyond, the economic screen selects the SEER 14 option because the
marginal savings between the standard efficiency SEER 14 unit and the higher-efficiency options
are not sufficient to make the higher-efficiency units economical. The table also shows how the
economic choice for two of the lighting technology options varies over the study period.

$40
$45
$50
$55
$60
$65
$70
$75
$80
$85
$90
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$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 876 of 1069
Energy-Efficiency Measure Analysis Avista Conservation Potential Assessment Study
5-18 www.gepllc.com

Table 5-8 Economic Screen Results for Selected Residential Equipment Measures
Technology 2012 2017 2022 2027 2032
Central AC SEER 13 SEER 14 SEER 14 SEER 14 SEER 14
Interior Lighting Screw-in CFL CFL CFL LED LED
Interior Lighting Linear Fluorescent T8 T8 T8 Super T8 Super T8

5.4.2 Non-equipment Measures Economic Screening
For non-equipment measures, LoadMAP evaluates the cost-effectiveness of each measure. The
kWh savings are computed as the percent savings from the measure applied to the relevant end-
use energy. If the measure passes the screen (has a B/C ratio greater than or equal to 1.0), the
measure is included in economic potential. Otherwise, it is screened out for that year.
5.5 TOTAL MEASURES EVALUATED
Table 5-9 summarizes the number of equipment and non-equipment measures evaluated for
each sector. In total, the project evaluated 4,332 energy efficiency measures.
Table 5-9 Number of Measures Evaluated
Residential C&I Total Number of
Measures
Equipment Measures Evaluated 1,284 608 1,892
Non-Equipment Measures Evaluated 1,524 916 2,440
Total Measures Evaluated 2,808 1,524 4,332

Appendix C shows the results of the economic screening process by segment, vintage, end use
and measure for the residential sector. Appendix D shows the equivalent information for the
commercial and industrial sectors.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 877 of 1069

Global Energy Partners, LLC 6-1
An EnerNOC Company
CHAPTER 6
ENERGY EFFICIENCY POTENTIAL RESULTS
This chapter presents the results of the energy-efficiency analysis. Before we provide the overall
and sector-level results, we review the four levels of potential developed for this study.
6.1 DEFINITIONS OF POTENTIAL
In this study, we estimated four types of potential: technical; economic; and achievable
potential, which is further divided into maximum achievable, and realistic achievable. Technical
and economic potential are both theoretical limits to efficiency savings. Achievable potential
embodies a set of assumptions about the decisions consumers make regarding the efficiency of
the equipment they purchase, the maintenance activities they undertake, the controls they use
for energy-consuming equipment, and the elements of building construction. Two types of
achievable potential were developed for this study, maximum achievable and realistic achievable,
to bound the range of achievable potential. For details on the types of potentials, see Chapter 2.
As with the baseline forecast, we developed the estimates of energy-efficiency potential using
the LoadMAP model. We present high-level results in the rest of this chapter for the overall
Avista electricity system. Separate results for Washington and Idaho are presented in Appendices
A and B.
6.2 OVERALL ENERGY EFFICIENCY POTENTIAL
Maximum achievable potential across all sectors is 88,760 MWh (10.1 aMW) in 2012 and
increases to a cumulative value of 2,905,702 MWh (331.7 aMW) by 2032. These savings
represents 1.0% of the baseline forecast in 2012 and 22.6% in 2032. Realistic achievable
potential in 2012 is 50,261 MWh (5.7 aMW) and reaches a cumulative value of 2,155,133 MWh
(246.0 aMW) by 2032, for savings that are 0.6% and 16.8% of the baseline in 2012 and 2032
respectively. Between 2012 and 2032, the baseline forecast shows overall electricity consumption
growth of 46%, but the realistic achievable potential forecast reduces growth by half to 23%.
Technical potential by 2032 is 37.8% of the baseline and economic potential savings are 26.4%
of the baseline, or roughly 70% of technical potential savings. MAP and RAP savings in 2012 are
86% and 64% respectively of the economic potential savings.
Figure 6-1 summarizes the energy-efficiency savings for the four potential levels relative to the
baseline forecast for selected years. Figure 6-2 displays the energy use forecast for the four
potential levels versus the baseline forecast. Table 6-1 presents the energy consumption and
peak demand for the potential levels across sectors.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 878 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-2 www.gepllc.com

Figure 6-1 Summary of Energy Efficiency Potential Savings, All Sectors

Figure 6-2 Energy Efficiency Potential Forecasts, All Sectors

Realistic Achievable
Maximum Achievable
Economic
Technical
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2032
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 879 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-3
An EnerNOC Company
Table 6-1 Summary of Energy Efficiency Potential, All Sectors
2012 2017 2022 2027 2032
Baseline Forecast (MWh) 8,799,039 9,463,880 10,417,347 11,536,869 12,851,760
Baseline Peak Demand
(MW) 1,780 1,880 2,080 2,306 2,566
Cumulative Energy Savings (MWh)
Realistic Achievable 50,261 405,985 945,183 1,536,357 2,155,133
Maximum Achievable 88,760 1,035,470 1,952,473 2,476,694 2,905,702
Economic 244,292 1,493,608 2,411,399 2,937,775 3,387,203
Technical 329,513 2,087,061 3,435,475 4,250,217 4,852,362
Cumulative Energy Savings (% of Baseline)
Realistic Achievable 0.6% 4.3% 9.1% 13.3% 16.8%
Maximum Achievable 1.0% 10.9% 18.7% 21.5% 22.6%
Economic 2.8% 15.8% 23.1% 25.5% 26.4%
Technical 3.7% 22.1% 33.0% 36.8% 37.8%
Peak Savings (MW)
Realistic Achievable 14 84 183 306 431
Maximum Achievable 22 207 386 492 566
Economic 60 302 479 580 659
Technical 78 422 669 826 943
Peak Savings (% of Baseline)
Realistic Achievable 0.8% 4.5% 8.8% 13.3% 16.8%
Maximum Achievable 1.2% 11.0% 18.6% 21.3% 22.1%
Economic 3.4% 16.0% 23.0% 25.2% 25.7%
Technical 4.4% 22.4% 32.2% 35.8% 36.8%

Table 6-2 and Figure 6-3 summarize cumulative realistic achievable potential by sector. Initially,
the residential sector accounts for about 52% of the savings, but by the end of the study, the
C&I sector becomes the source of 58% of the savings.
Table 6-2 Realistic Achievable Cumulative Energy-efficiency Potential by Sector, MWh
Segment 2012 2017 2022 2027 2032
Residential, WA 17,413 94,529 238,739 431,973 637,029
Residential, ID 8,692 43,922 97,705 172,179 260,003
C&I, WA 15,733 173,433 378,252 575,328 774,619
C&I, ID 8,423 94,102 230,487 356,878 483,482
Total 50,261 405,985 945,183 1,536,357 2,155,133

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 880 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-4 www.gepllc.com

Figure 6-3 Realistic Achievable Cumulative Potential by Sector

Table 6-3 shows the incremental annual realistic achievable potential by sector for 2012 through
2015. During this period, lighting and appliance standards slow the rate of growth in the
residential baseline energy consumption, thus reducing the amount of incremental annual
potential savings from residential conservation programs. On the other hand, C&I potential
continues to grow. Complete annual incremental savings for Washington and Idaho appear in
Appendices A and B respectively.
Table 6-3 Incremental Annual Realistic Achievable Energy-efficiency Potential by
Sector, MWh
Segment 2012 2013 2014 2015
Residential, WA 17,413 17,161 16,488 18,514
Residential, ID 8,692 8,451 7,943 8,569
C&I, WA 15,733 21,165 26,869 30,393
C&I, ID 8,423 10,734 14,543 16,956
Total 50,261 57,511 65,843 74,432

In Figure 6-4, we can see how the annual incremental realistic achievable potential throughout
the study tracks the avoided energy costs, with annual potential generally increasing or
decreasing along with avoided costs. Note however that other factors also influence potential,
particularly the rates at which programs can ramp up over time, which is particularly relevant to
how potential changes from year to year in the early years of the study.
0
500,000
1,000,000
1,500,000
2,000,000
2,500,000
2012 2017 2022 2027 2032
C&I, ID
C&I, WA
Residential, ID
Residential, WA
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 881 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-5
An EnerNOC Company
Figure 6-4 Incremental Annual Realistic Achievable Energy-efficiency (MWh)
vs. Avoided Energy Cost

Note: Avoided costs are 2009 real dollars and include energy costs, risk, and the 10% Power Act premium.

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Avoided Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 882 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-6 www.gepllc.com

6.3 RESIDENTIAL SECTOR
Realistic achievable potential savings for the residential sector in both states is 26,105 MWh in
2012, or 0.7% of the sector’s baseline forecast. It reaches 897,032 MWh, or 16.0% of the
baseline forecast by 2032. Technical and economic potential savings are 37.7% and 24.5%
respectively. Figure 6-5 depicts the potential savings estimates graphically. Figure 6-6 shows the
energy use forecasts under the four types of potential versus the baseline forecast. Table 6-3
presents estimates for energy and peak demand under the four types of potential.
Figure 6-5 Energy Efficiency Potential Savings, Residential Sector

Figure 6-6 Energy Efficiency Potential Forecast, Residential Sector

Realistic Achievable
Maximum Achievable
Economic
Technical
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2032
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Realistic Achievable
Maximum Achievable
Economic
Technical
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 883 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-7
An EnerNOC Company
Table 6-4 Energy Efficiency Potential, Residential Sector
2012 2017 2022 2027 2032
Baseline Forecast (MWh) 3,626,696 3,871,294 4,356,240 4,918,847 5,600,787
Baseline Peak Demand
(MW) 991 1,026 1,150 1,288 1,449
Cumulative Energy Savings (MWh)
Realistic Achievable 26,105 138,450 336,444 604,152 897,032
Maximum Achievable 36,300 429,065 798,829 1,024,671 1,192,794
Economic 104,111 583,427 967,788 1,188,497 1,373,869
Technical 153,100 918,965 1,468,041 1,825,587 2,112,855
Cumulative Energy Savings (% of Baseline)
Realistic Achievable 0.7% 3.6% 7.7% 12.3% 16.0%
Maximum Achievable 1.0% 11.1% 18.3% 20.8% 21.3%
Economic 2.9% 15.1% 22.2% 24.2% 24.5%
Technical 4.2% 23.7% 33.7% 37.1% 37.7%
Peak Savings (MW)
Realistic Achievable 10 44 100 179 262
Maximum Achievable 14 120 232 301 343
Economic 38 171 286 349 396
Technical 51 256 407 503 579
Peak Savings (% of Baseline)
Realistic Achievable 1.1% 4.3% 8.7% 13.9% 18.1%
Maximum Achievable 1.4% 11.7% 20.2% 23.3% 23.7%
Economic 3.8% 16.7% 24.9% 27.1% 27.3%
Technical 5.1% 24.9% 35.4% 39.0% 40.0%
6.3.1 Residential Potential by Market Segment
Table 6-5 shows the baseline forecast and realistic achievable potential energy savings for the
four residential segments in selected years. Single-family homes in Washington and Idaho
account for 65% and 68% of each state’s residential sector total sales during the base year and
throughout the forecast. Thus, as one would expect, single-family homes account for the largest
share of potential savings. Table 6-6 takes a closer look at savings by segment and potential
level in 2022, the mid-point of the 20-year period.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 884 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-8 www.gepllc.com

Table 6-5 Residential Sector, Baseline and Realistic Achievable Potential by Segment
2012 2017 2022 2027 2032
Baseline Forecast (MWh)
Single Family 2,394,930 2,551,956 2,876,301 3,252,564 3,709,958
Multi Family 203,544 222,114 253,265 288,585 330,209
Mobile Home 126,939 133,923 149,975 168,639 191,313
Limited Income 901,283 963,301 1,076,699 1,209,059 1,369,306
Total 3,626,696 3,871,294 4,356,240 4,918,847 5,600,787
Cumulative Energy Savings, Realistic Achievable Potential (MWh)
Single Family 18,783 96,418 240,911 426,483 630,128
Multi Family 1,066 5,833 14,343 28,236 42,801
Mobile Home 985 4,280 7,677 13,381 20,040
Limited Income 5,272 31,920 73,512 136,051 204,063
Total 26,105 138,450 336,444 604,152 897,032
% of Total Residential Cumulative Energy Savings
Single Family 72.0% 69.6% 71.6% 70.6% 70.2%
Multi Family 4.1% 4.2% 4.3% 4.7% 4.8%
Mobile Home 3.8% 3.1% 2.3% 2.2% 2.2%
Limited Income 20.2% 23.1% 21.8% 22.5% 22.7%

Table 6-6 Residential Realistic Achievable Potential by Housing Type, 2022
Forecast Single
Family Multi Family Mobile Home Limited
Income Total
Baseline Forecast (MWh) 2,876,301 253,265 149,975 1,076,699 4,356,240
Cumulative Energy Savings (MWh)
Realistic Achievable 240,911 14,343 7,677 73,512 336,444
Economic Potential 679,288 46,859 21,400 220,241 967,788
Technical Potential 950,449 77,463 52,154 387,975 1,468,041
Cumulative Energy Savings % of Baseline
Realistic Achievable 8.4% 5.7% 5.1% 6.8% 7.7%
Economic Potential 23.6% 18.5% 14.3% 20.5% 22.2%
Technical Potential 33.0% 30.6% 34.8% 36.0% 33.7%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 885 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-9
An EnerNOC Company
6.3.2 Residential Potential by End Use, Technology, and Measure Type
Table 6-7 provides estimates of savings for each end use and type of potential.
Water Heating offers the highest cumulative technical potential over the 20-year period,
which reflects the high potential for conversion to natural gas in homes where gas is
available (see discussion below) and use of heat pump water heaters where gas is not
available, as well as a wide range of other water heating measures. Conversion to natural
gas passes the TRC test throughout the study period for most Washington housing types and
for single family homes in Idaho. In contrast, based on the study’s assumptions of equipment
cost and avoided cost, heat pump water heaters are cost-effective in new single family
homes by 2014, but do not become cost-effective for existing homes until 2024 in Idaho and
2028 in Washington. Water heating also has the highest cumulative realistic achievable
potential.
Space Heating offers the second-highest cumulative technical potential over the study and
its economic potential is slightly higher than water heating, again due to the potential for
conversion to natural gas (see discussion below), but also due to shell measures, controls,
and advanced new construction designs. Based on realistic achievable savings, space heating
also ranks second.
Interior lighting offers the fourth-largest technical potential savings, but the third-largest
economic and realistic achievable potential. The lighting standard begins its phase-in starting
in 2012, which coincides with the availability in the market place of advanced incandescent
lamps that meet the minimum efficacy standard. The baseline forecast assumes that people
will install both advanced incandescent and CFLs in screw-in lighting applications. For
technical potential, LED lamps are the most efficient option, starting in 2012. However, LED
lamps do not pass the economic screen until 2022, when they begin to become cost-effective
for pin-based fixtures. Nonetheless, there is significant economic and realistic achievable
lighting potential due to conversion from advanced incandescents to CFLs.
Appliances rank sixth based on technical potential, but fourth in terms of realistic
achievable potential. This reflects the cost-effectiveness of the highest-efficiency white-goods
appliances for both new construction and for replacing failed units, as well as the market
acceptance of high-efficiency appliances. Removal of second refrigerators and freezers also
contributes to economic and realistic achievable potential within this end use.
Cooling offers the third-highest technical potential, but is sixth based on realistic achievable
potential. Initially technical potential is low but ramps up due to the assumption of increased
saturation of air conditioning over time. Economic potential for cooling in 2031 is about 40%
of technical potential because the higher SEER units do not pass the economic screen based
on based on the study’s assumptions of equipment cost and avoided cost.
Home electronics also offer substantial savings opportunities. Technical potential reflects
the purchase of ENERGY STAR units for all technologies, except PCs and laptops for which a
super-efficient ―climate saver‖ option is available in the marketplace. However, the climate
saver options are not cost-effective during the forecast horizon, so economic potential
reflects the purchase of ENERGY STAR units across all technologies in this end use.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 886 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-10 www.gepllc.com

Table 6-7 Residential Cumulative Savings by End Use and Potential Type (MWh)
End Use Case 2012 2017 2022 2027 2032
Cooling
Realistic Achievable 14 2,443 8,588 23,412 44,892
Economic 364 22,925 41,690 60,482 82,185
Technical 4,155 63,885 102,963 147,309 200,588
Space Heating
Realistic Achievable 306 17,366 81,141 187,511 304,466
Economic 9,645 157,044 303,749 401,120 480,554
Technical 13,047 206,921 390,626 523,886 650,322
Heat/Cool
Realistic Achievable 12 872 2,353 6,048 15,539
Economic 447 12,872 15,291 18,697 27,916
Technical 3,334 27,773 47,801 66,829 76,389
Water Heating
Realistic Achievable 636 25,578 102,451 201,179 317,521
Economic 12,121 135,781 297,102 388,156 462,418
Technical 35,027 281,264 527,056 667,224 745,280
Appliances
Realistic Achievable 1,282 12,411 26,859 42,554 59,056
Economic 5,548 61,277 80,081 85,195 91,618
Technical 7,229 78,554 105,335 113,831 120,932
Interior Lighting
Realistic Achievable 18,569 52,269 64,439 74,958 71,445
Economic 55,377 107,842 116,225 106,057 86,182
Technical 64,748 148,015 146,127 136,520 126,690
Exterior Lighting
Realistic Achievable 3,281 10,532 10,777 10,042 8,058
Economic 9,770 21,965 17,611 13,313 9,494
Technical 11,200 28,680 24,906 22,638 22,320
Electronics
Realistic Achievable 1,780 13,544 32,080 45,568 57,382
Economic 8,967 45,853 67,702 76,036 87,323
Technical 12,390 65,526 93,981 106,595 122,734
Miscellaneous
Realistic Achievable 225 3,435 7,756 12,880 18,673
Economic 1,871 17,869 28,336 39,442 46,180
Technical 1,970 18,348 29,247 40,754 47,600
Total
Realistic Achievable 26,105 138,450 336,444 604,152 897,032
Economic 104,111 583,427 967,788 1,188,497 1,373,869
Technical 153,100 918,965 1,468,041 1,825,587 2,112,855

Figure 6-7 focuses on realistic achievable potential by end use in selected years. As discussed
above, by the end of the study period, water heating and space heating are the largest
contributors to realistic achievable potential. In the early years of the study period, lighting
maintains its historic role as the largest contributor to residential sector savings, due to
remaining opportunities for conversion from incandescent lighting (both today’s standard lamps
and the new advanced incandescents) to CFLs. By 2022, however, the percentage of savings due
to lighting is projected to drop off as advanced incandescents become the new baseline.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 887 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-11
An EnerNOC Company
Figure 6-7 Residential Realistic Achievable Potential by End Use, Selected Years

Table 6-8 shows the savings by end use and market segment in 2022. The segments are similar
in terms of the savings opportunities by end use, but there are a few notable differences. Single-
family homes have more exterior lighting and so have more savings potential for this end use.
Similarly, single-family homes have swimming pools and therefore have more potential for
savings in pool pumps, which are included in miscellaneous loads. Water heating is a higher
proportion of potential savings in multi-family homes, mobile homes, and limited income homes,
reflecting the smaller home sizes and thus diminished savings potential for space conditioning
and appliances, compared to single family homes.
Table 6-8 Residential Potential by End Use and Market Segment, 2022 (MWh)
Single Family Multi Family Mobile
Home
Limited
Income Total
Cooling 4,975 258 129 3,226 8,588
Space heating 63,291 3,985 908 12,957 81,141
Heat/cool 2,138 12 88 114 2,353
Water heating 65,162 6,257 1,293 29,739 102,451
Appliances 19,090 529 950 6,290 26,859
Interior lighting 45,467 2,415 2,203 14,354 64,439
Exterior lighting 8,875 127 480 1,295 10,777
Electronics 25,054 754 1,302 4,970 32,080
Miscellaneous 6,860 6 324 566 7,756
Total 240,911 14,343 7,677 73,512 336,444

As described in Chapter 5, using our LoadMAP model, we develop separate estimates of potential for
equipment and non-equipment measures. Table 6-9 presents results for equipment at the technology
level, for which realistic chievable potential is greater than zero.

-200,000 400,000 600,000 800,000 1,000,000
2012
2017
2022
2027
2032
Cumulative Savings (MWh)
Cooling
Space heating
Heat/cool
Water heating
Appliances
Int. lighting
Ext. lighting
Electronics
Miscellaneous
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 888 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-12 www.gepllc.com

Table 6-9 Residential Cumulative Realistic Achievable Potential by End Use and
Equipment Measures, Selected Years (MWh)
End Use Technology 2012 2017 2022
Cooling Central AC - 152 167
Heat/Cool Air Source Ht. Pump - - -
Water Heating Water Heater 140 1,047 1,096
Appliances
Clothes Washer 83 1,014 2,552
Clothes Dryer 103 708 1,299
Dishwasher 115 1,074 2,621
Refrigerator 438 1,999 4,064
Freezer 333 1,651 3,592
Second Refrigerator 154 747 1,424
Stove 22 165 371
Interior Lighting
Screw-in 17,292 42,771 48,939
Linear Fluorescent 173 1,906 3,576
Pin-based 1,102 7,398 11,079
Exterior Lighting Screw-in 3,256 10,404 10,606
High Intensity/Flood 25 128 171
Electronics Personal Computers 1,148 9,279 15,975
TVs 620 3,260 6,039
Miscellaneous Pool Pump 171 1,581 3,896
Furnace Fan 45 560 1,668
Total 25,220 85,845 119,135

Conversion of electric water heaters and electric furnaces to natural gas was modeled
as a special case within the measure analysis to allow consideration of feasibility (e.g., homes
too far from a natural gas line), as well as to allow the option of a heat pump water heater for
homes where conversion to gas is not feasible. Table 6-10 shows the residential sector
achievable savings from converting electric furnaces and water heaters to natural gas.
Conversion ramps up slowly, but because it completely removes use of electricity from two of the
largest ends uses, it accounts for a substantial portion of savings by 2032: For water heating,
about one-fourth of the savings from conversion to gas occurs in new construction. For furnaces,
the fraction due to new construction is roughly one-third.
Table 6-10 Residential Realistic Achievable Savings from Conversion to Natural Gas
(MWh)
2012 2017 2022 2027 2032
Water heater —convert to gas
Realistic achievable potential (MWh) 267 10,214 69,745 145,049 216,351
Water heater –convert to gas
(% of Res. Achievable potential) 0.5% 2.5% 7.4% 9.4% 10.0%
Furnace — convert to gas
Realistic achievable potential (MWh) 244 7,803 49,719 106,607 171,095
Furnace — convert to gas (% of Res.
Achievable potential) 0.5% 1.9% 5.3% 6.9% 7.9%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 889 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-13
An EnerNOC Company
Table 6-11 presents savings results for non-equipment measures for which realistic achievable
potential is greater than zero, sorted by cumulative potential in 2032. Note that because a
measure such as insulation provides both space cooling and space heating savings, Table 6-11
does not break down savings by end use.
Table 6-11 Residential Realistic Achievable Savings for Non-equipment Measures
(MWh), Selected Years
Measure 2012 2017 2022
Water Heater - Convert to Gas 267 10,214 69,745
Furnace - Convert to Gas 244 7,803 49,719
Advanced New Construction Designs 1 180 4,206
Repair and Sealing - Ducting 20 2,713 7,763
Insulation - Infiltration Control 20 2,731 7,696
Water Heater - Thermostat Setback 142 8,150 13,721
Home Energy Management System 7 1,175 4,146
Water Heater - Hot Water Saver 6 426 5,447
Freezer - Remove Second Unit 22 3,246 6,959
Electronics - Reduce Standby Wattage 13 1,004 10,066
Thermostat - Clock/Programmable 21 2,859 7,907
Insulation - Foundation 1 438 1,979
Air Source Heat Pump - Maintenance 12 872 2,353
Refrigerator - Remove Second Unit 13 1,807 3,977
Water Heater - Faucet Aerators 12 978 2,341
Insulation - Ducting 1 195 1,024
Insulation - Wall Cavity 1 275 1,234
Water Heater - Tank Blanket/Insulation 49 2,596 4,051
Ceiling Fan - Installation 0 87 743
Room AC - Removal of Second Unit 6 919 2,280
Water Heater - Heat Pump - 23 793
Water Heater - Timer 8 1,152 2,477
Insulation - Ceiling 2 400 1,201
Water Heater - Low Flow Showerheads 9 887 1,762
Central AC - Maintenance and Tune-Up - - -
Pool - Pump Timer 8 1,294 2,192
Insulation - Wall Sheathing 0 50 230
Water Heater - Pipe Insulation 2 105 1,018
Whole-House Fan - Installation 0 27 278
Total 885 52,605 217,309

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 890 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-14 www.gepllc.com

Looking at both the equipment (Table 6-9) and non-equipment measure results (Table 6-11), we
see that initially nearly all of the savings come from the equipment measures, particularly
lighting, but over time an increasing proportion of the savings come from conversion of water
heating and space heating to natural gas. At the study mid-point in 2022, the four measures with
the greatest realistic achievable poential are:
Water heater conversion to gas (69,745 MWh)
Furnace conversion to gas (49,719 MWh)
Replacement of interior screw in lamps (48,939 MWh)
Replacement of personal computers with ENERGY STAR units (15,975 MWh)
These four measures provide realistic achievable potential of 184,378 MWh in 2022, which is
approximately 55% of the total 2022 potential for the residential sector.
6.4 COMMERCIAL AND INDUSTRIAL SECTOR POTENTIAL
Realistic achievable potential savings for the C&I sector in both states is 24,155 MWh in 2012, or
0.5% of the sector’s baseline forecast. It reaches 1,258,101 MWh, or 17.4% of the baseline
forecast by 2032. Technical and economic potential savings are 37.8% and 27.8% of the
baseline forecast respectively. Figure 6-8 depicts the potential savings estimates graphically.
Figure 6-9 shows the energy use forecasts under the four types of potential versus the baseline
forecast. Table 6-12 presents estimates for the sector’s energy and peak demand under the four
types of potential.
Figure 6-8 Energy Efficiency Potential Savings, Commercial and Industrial Sector

Realistic Achievable
Maximum Achievable
Economic
Technical
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2032
En
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 891 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-15
An EnerNOC Company
Figure 6-9 Energy Efficiency Potential Forecast, Commercial and Industrial Sector

Table 6-12 Energy Efficiency Potential, Commercial and Industrial Sector
2012 2017 2022 2027 2032
Baseline Forecast (MWh) 5,172,344 5,592,586 6,061,107 6,618,022 7,250,973
Cumulative Energy Savings (MWh)
Realistic Achievable 24,155 267,535 608,739 932,205 1,258,101
Maximum Achievable 52,460 606,406 1,153,644 1,452,022 1,712,907
Economic 140,180 910,181 1,443,612 1,749,278 2,013,333
Technical 176,414 1,168,096 1,967,434 2,424,630 2,739,507
Cumulative Energy Savings (% of Baseline)
Realistic Achievable 0.5% 4.8% 10.0% 14.1% 17.4%
Maximum Achievable 1.0% 10.8% 19.0% 21.9% 23.6%
Economic 2.7% 16.3% 23.8% 26.4% 27.8%
Technical 3.4% 20.9% 32.5% 36.6% 37.8%
Peak Savings (MW)
Realistic Achievable 4 40 84 127 169
Maximum Achievable 8 88 154 191 223
Economic 22 130 193 231 263
Technical 27 166 262 324 364
Peak Savings (% of Baseline)
Realistic Achievable 0.5% 4.7% 9.0% 12.4% 15.1%
Maximum Achievable 1.0% 10.3% 16.6% 18.8% 20.0%
Economic 2.7% 15.3% 20.8% 22.7% 23.6%
Technical 3.4% 19.4% 28.2% 31.8% 32.6%

-
1,000,000
2,000,000
3,000,000
4,000,000
5,000,000
6,000,000
7,000,000
8,000,000
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Baseline
Realistic Achievable
Maximum Achievable
Economic
Technical
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 892 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-16 www.gepllc.com

6.4.1 Commercial Potential by Market Segment and State
Table 6-13 shows the baseline forecast and realistic achievable potential energy savings for the
four C&I segments. Large Commercial customers account for the largest portion of the baseline
forecast and thus also have the largest realistic achievable potential. In 2012 the Large
Commercial segment’s realistic achievable potential is 14,754 MWh or 61.1% of C&I total realistic
achievable potential. By 2032 its share of C&I potential has dropped slightly to 50.8%. In
contrast, the Extra Large Industrial customers increase their role in savings over the study
period, beginning with only 1,673 MWh of realistic achievable potential or 6.9% of total C&I
potential in 2012, but growing by 2032 to cumulative realistic achievable savings of 285,178
MWh or 22.7% of the C&I sector savings. Table 6-14 takes a closer look at savings by segment
and potential level in 2022, the mid-point of the 20-year period.
Table 6-13 C&I Sector, Baseline and Realistic Achievable Potential by Segment
2012 2017 2022 2027 2032
Baseline Forecast (MWh)
Small/Med. Commercial 730,499 772,442 832,324 906,807 992,374
Large Commercial 2,266,380 2,403,446 2,592,110 2,822,788 3,088,354
Extra Large Commercial 347,860 421,489 457,725 497,943 541,389
Extra Large Industrial 1,827,605 1,995,209 2,178,948 2,390,485 2,628,857
Total 5,172,344 5,592,586 6,061,107 6,618,022 7,250,973
Cumulative Energy Savings, Realistic Achievable Potential (MWh)
Small/Med. Commercial 4,513 46,375 96,231 144,812 197,619
Large Commercial 14,754 164,668 338,450 491,020 638,562
Extra Large Commercial 3,216 33,198 69,605 105,163 136,743
Extra Large Industrial 1,673 23,294 104,453 191,210 285,178
Total 24,155 267,535 608,739 932,205 1,258,101
% of Total C&I Cumulative Energy Savings
Small/Med. Commercial 18.7% 17.3% 15.8% 15.5% 15.7%
Large Commercial 61.1% 61.6% 55.6% 52.7% 50.8%
Extra Large Commercial 13.3% 12.4% 11.4% 11.3% 10.9%
Extra Large Industrial 6.9% 8.7% 17.2% 20.5% 22.7%

Table 6-14 C&I Realistic Achievable Potential by Segment, 2022
Forecast Small/Med.
Commercial
Large
Commercial
Extra Large
Commercial
Extra Large
Industrial Total
Baseline Forecast (MWh) 832,324 2,592,110 457,725 2,178,948 6,061,107
Cumulative Energy Savings (MWh)
Realistic achievable 96,231 338,450 69,605 104,453 608,739
Economic Potential 193,950 646,644 144,275 458,743 1,443,612
Technical Potential 308,119 951,283 184,560 523,472 1,967,434
Cumulative Energy Savings % of Baseline
Realistic achievable 12% 13% 15% 5% 10%
Economic Potential 23% 25% 32% 21% 24%
Technical Potential 37% 37% 40% 24% 32%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 893 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-17
An EnerNOC Company
6.4.2 C&I Potential by End Use, Technology, and Measure Type
Table 6-15 presents the C&I sector savings by end use and potential type. Recall that the
Small/Medium Commercial and Large Commercial Segments include a small percentage of
industrial-type customers. Hence, we included a non-equipment measure called Industrial
Process Improvements to capture potential savings from these customers. In addition, the
miscellaneous category includes non-HVAC motors to capture motor use within small industrial
facilities. For all C&I customers, a custom measure category was included to serve as a ―catch
all‖ for measures for which costs and savings are not easily quantified and that could be part of a
program such as Avista’s existing Site-Specific incentive program. In terms of how potential is
divided among the various end uses, we note the following:
Interior lighting offers the largest technical, economic, and achievable potential. The high
technical potential of 892,840 MWh in 2032 is a result of LED lighting that is now commercially
available in screw-in and linear lighting applications, as well as numerous fixture improvement
and control options. However, LED lighting is not cost effective given the study’s avoided cost
assumptions, so economic potential reflects installation of CFL, T5, and Super T8 lamps
throughout most of the commercial sector. Still, this results in realistic achievable potential of
598,564 MWh by 2032.
Cooling has the third highest savings for technical potential at 302,301 MWh in 2032, and
many of the cooling measures are cost effective, including installation of high-efficiency
equipment, thermal shell measures, HVAC control strategies, and retrocommissioning.
Because the market for cooling technologies is mature, these savings are relatively easy to
capture, as reflected in the ramp rates for these measures. Thus realistic achievable potential
for cooling, at 119,700 MWh, is the second highest among C&I end uses.
Ventilation is second in terms of technical and economic potential due to conversion to variable
air volume systems, high-efficiency and variable speed control fans, and retrocommissioning.
Realistic achievable potential in 2032 of 117,020 MWh ranks this end use third, just behind
cooling.
Machine drive ranks fourth in realistic achievable potential at 101,018 MWh in 2032. Even
though the National Electrical Manufacturer’s Association (NEMA) standards make premium
efficiency motors the baseline efficiency level, savings remain available from upgrading to still
more efficient levels.
Office equipment, exterior lighting, and industrial process improvements offer smaller
but still significant realistic achievable potential by 2032 at 73,152 MWh, 68,467 MWh, and
60,759 MWh respectively.
Commercial refrigeration, food preparation, and water heating savings are relatively
small across the C&I sector as a whole, though these end uses can offer significant savings in
supermarkets, restaurants, hospitals, and other buildings where these end use constitute a larger
portion of overall energy use.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 894 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-18 www.gepllc.com

Table 6-15 C&I Cumulative Savings by End Use and Potential Type, Selected Years,
(MWh)
End Use Case 2012 2017 2022 2027 2032
Cooling
RAP 205 14,595 50,416 82,103 119,700
Economic 2,848 51,234 108,395 146,209 191,484
Technical 7,425 96,886 200,488 252,951 302,301
Space Heating
RAP 17 2,185 11,476 22,223 36,932
Economic 346 11,546 31,407 45,917 66,710
Technical 571 18,000 51,975 71,620 94,893
Heat/Cool
RAP 47 3,765 6,874 8,352 10,413
Economic 541 8,928 11,319 13,415 15,092
Technical 743 10,317 13,864 16,814 18,949
Ventilation
RAP 457 7,102 35,467 69,845 117,020
Economic 7,544 56,221 144,530 201,459 237,313
Technical 10,719 82,071 220,464 294,789 323,008
Water Heating
RAP 205 6,315 13,969 20,663 27,581
Economic 1,907 19,044 27,780 34,762 36,791
Technical 13,251 96,031 174,865 249,540 274,478
Food Preparation
RAP 213 2,665 7,608 14,695 22,009
Economic 2,824 17,789 32,528 39,188 42,755
Technical 3,215 19,520 35,976 43,195 47,322
Refrigeration
RAP 185 1,877 6,192 11,901 17,567
Economic 2,768 13,518 25,844 33,360 37,422
Technical 3,273 17,982 40,008 51,933 58,855
Interior Lighting
RAP 17,619 166,503 328,877 477,040 598,564
Economic 78,200 461,679 609,517 700,595 803,195
Technical 85,734 504,965 681,379 784,870 892,840
Exterior Lighting
Achievable 1,634 23,519 46,019 57,477 68,467
Economic 7,096 67,172 78,193 81,864 86,650
Technical 7,893 73,413 87,263 98,652 110,984
Office Equipment
RAP 2,642 27,112 44,602 58,637 73,152
Economic 19,053 86,895 91,341 95,389 99,348
Technical 25,452 119,267 126,773 134,377 142,248
Machine Drive
RAP 581 9,104 42,030 72,656 101,018
Economic 6,560 57,477 158,387 196,285 214,864
Technical 6,994 67,404 204,459 258,683 286,647
Process
RAP 345 2,590 14,014 33,699 60,759
Economic 10,390 57,275 120,473 154,151 172,559
Technical 10,390 57,275 120,473 154,151 172,559
Miscellaneous
RAP 7 204 1,194 2,914 4,921
Economic 103 1,403 3,897 6,684 9,150
Technical 753 4,964 9,446 13,056 14,423
Total
RAP 24,154 267,494 608,739 932,221 1,258,104
Economic 140,121 909,897 1,443,612 1,749,309 2,013,338
Technical 175,565 1,165,177 1,967,434 2,424,763 2,739,528

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 895 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-19
An EnerNOC Company
Figure 6-10 focuses on achievable potential by end use in selected years. Interior lighting
remains the largest source of potential in the C&I sector throughout the study. Cooling,
ventilation, and machine drive are the next largest contributors as discussed above.
Figure 6-10 C&I Realistic Achievable Potential by End Use, Selected Years

Table 6-16 shows the savings by end use and C&I market segment in 2022. As one would
expect, the Extra Large Industrial segment differs significantly from the other segments. Machine
drive and process improvements constitute 40% and 13% of realistic achievable potential for this
segment. Note that the three commercial building segments, which are based on Avista’s rate
structure, do include a small percentage of industrial businesses. For these customers, the
miscellaneous savings end-use includes non-HVAC motors.
Table 6-16 C&I Realistic Achievable Potential by End Use and Market Segment, 2022
(MWh)
Small/Med.
Commercial
Large
Commercial
Extra Large
Commercial
Extra Large
Industrial Total
Cooling 3,823 26,225 5,151 15,217 50,416
Space Heating 778 6,727 1,521 2,450 11,476
Combined
Heating/Cooling 572 5,264 583 455 6,874
Ventilation 8,757 5,663 5,627 15,420 35,467
Water Heating 2,190 5,825 5,954 - 13,969
Food Preparation 1,238 5,563 807 - 7,608
Refrigeration 1,313 4,383 496 - 6,192
Interior Lighting 58,481 218,078 38,555 13,764 328,877
Exterior Lighting 10,719 27,639 6,557 1,103 46,019
Office Equipment 8,011 32,404 4,187 - 44,602
Machine Drive - - - 42,030 42,030
Process - - - 14,014 14,014
Miscellaneous 349 678 168 - 1,194
Total 96,231 338,450 69,605 104,453 608,739
-200,000 400,000 600,000 800,000 1,000,000 1,200,000 1,400,000
2012
2017
2022
2027
2032 Cooling
Space Heating
Heat/cool
Ventilation
Water Heating
Food Preparation
Refrigeration
Interior Lighting
Exterior Lighting
Office Equipment
Miscellaneous
Machine Drive
Process
Cumulative Savings (MWh)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 896 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-20 www.gepllc.com

Table 6-17 presents realistic achievable potential savings for equipment measures for which
realistic achievable potential is greater than zero. These results provide additional detail at the
technology level. For example, within interior lighting, screw-in lamps initial provide the greatest
share of savings, but the EISA standards move the baseline in that category to a higher
efficiency level. Consequently, in the long run, fluorescent lamps offer the greatest savings
potential.
Table 6-17 C&I Cumulative Realistic Achievable Potential by End Use and Equipment
Measures, Selected Years (MWh)
End Use Technology 2012 2017 2022
Cooling Central Chiller 81 855 3,288
PTAC 6 6 6
Heat/Cool Heat Pump 21 391 1,172
Ventilation Ventilation 140 1,047 1,096
Water Heater Water Heater 174 2,019 4,463
Food Preparation
Fryer 13 147 392
Hot Food Container 13 275 763
Oven 187 2,203 5,881
Refrigeration
Glass Door Display 32 434 1,248
Icemaker 25 324 961
Solid Door Refrigerator 43 497 1,331
Vending Machine 83 455 1,111
Walk in Refrigeration 2 26 63
Interior Lighting
Interior Screw-in 10,283 66,690 101,556
HID 2,837 25,587 50,762
Linear Fluorescent 4,319 53,111 104,450
Exterior Lighting
Screw-in 230 3,155 5,265
HID 1,267 16,135 31,807
Linear Fluorescent 124 2,230 3,784
Office Equipment
Desktop Computer 1,546 14,363 22,986
Laptop Computer 111 1,031 1,649
Monitor 317 1,139 1,970
POS Terminal 37 514 939
Printer/copier/fax 110 1,626 2,988
Server 511 7,235 11,670
Machine Drive
Less than 5 HP 34 236 663
5-24 HP 73 532 1,536
25-99 HP 183 1,325 3,825
100-249 HP 51 373 1,077
250-499 HP 55 397 1,145
500 and more HP 103 748 2,160
Process
Electrochem. Process 49 358 1,869
Process Cooling/Refrig. 65 479 2,500
Process Heating 231 1,707 8,907
Miscellaneous Non-HVAC Motor 6 95 520
Total 23,654 212,346 405,630

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 897 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-21
An EnerNOC Company
Table 6-18 presents savings results for non-equipment measures for which realistic achievable
potential is greater than zero, sorted by cumulative potential in 2032. Note that, because a
measure such as insulation provides both space cooling and space heating savings, Table 6-18
does not break down savings by end use.
Table 6-18 C&I Cumulative Realistic Achievable Savings for Non-equipment Measures,
Selected Years (MWh)
Measure 2012 2017 2022
Energy Management System 39 2,372 25,108
Advanced New Construction Designs 1 106 1,626
Retrocommissioning - Lighting 57 11,775 21,760
Interior Fluorescent - High Bay Fixtures 21 1,262 13,307
Custom Measures 4 829 11,321
Retrocommissioning - Comprehensive 41 8,649 15,523
Fans - Variable Speed Control 12 553 5,368
RTU - Maintenance 63 7,964 14,458
Fans - Energy Efficient Motors 10 651 6,782
Photocell Controlled T8 Dimming Ballasts 0 61 535
Retrocommissioning - HVAC 5 580 5,758
Pumping System - Optimization 11 507 4,907
Compressed Air - System Optimization and Improvements 11 506 4,837
Interior Lighting - Occupancy Sensors 19 726 5,616
Motors - Variable Frequency Drive 18 2,220 4,618
Motors - Magnetic Adjustable Speed Drives 8 367 3,707
Water Heater - Faucet Aerators/Low Flow Nozzles 27 3,964 8,101
Interior Fluorescent - Delamp and Install Reflectors 18 728 5,429
Commissioning - Comprehensive 0 368 2,614
Compressed Air - System Controls 7 355 3,457
Chiller - Turbocor Compressor 4 276 3,008
Heat Pump - Maintenance 26 3,374 5,702
Roofs - High Reflectivity 2 54 426
Pumps - Variable Speed Control 5 250 2,395
Chiller - Condenser Water Temperature Reset 7 419 3,987
Chiller - VSD 3 208 2,116
Compressed Air - Compressor Replacement 4 203 1,982
Pumping System - Controls 4 202 1,942
Thermostat - Clock/Programmable 5 762 1,499
Exterior Lighting - Daylighting Controls 4 161 1,309
Commissioning - Lighting 0 248 842
Office Equipment - Energy Star Power Supply 9 1,205 2,400
Compressed Air - System Maintenance 13 717 1,198
Insulation - Ducting 1 145 1,221
Chiller - Chilled Water Reset 4 645 1,142

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 898 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-22 www.gepllc.com

Measure 2012 2017 2022
Water Heater - Heat Pump 1 69 870
Cooking - Exhaust Hoods with Sensor Control 1 14 127
Pumping System - Maintenance - 43 606
Furnace - Convert to Gas 2 80 527
Cooling - Economizer Installation 3 125 1,138
Exterior Lighting - Induction Lamps 0 29 430
Refrigeration - System Optimization 0 24 388
Insulation - Ceiling 0 2 29
Refrigeration - System Controls 0 17 272
Industrial Process Improvements 0 28 332
LED Exit Lighting 25 932 1,028
Insulation - Wall Cavity 0 12 177
Commissioning - HVAC - - 20
Water Heater - Tank Blanket/Insulation 4 255 449
Miscellaneous - Energy Star Water Cooler 0 59 173
Refrigeration - Floating Head Pressure 0 10 105
Refrigeration - Strip Curtain - 1 34
Refrigeration - System Maintenance 0 5 78
Refrigeration - Anti-Sweat Heater/Auto Door Closer 0 8 81
Water Heater - Hot Water Saver - - 4
Water Heater - High Efficiency Circulation Pump 0 8 83
Vending Machine - Controller 0 39 66
Chiller - Chilled Water Variable-Flow System 0 6 51
Exterior Lighting - Cold Cathode Lighting 0 2 24
Laundry - High Efficiency Clothes Washer 0 9 16
Refrigeration - Night Covers 0 1 9
Total 501 55,189 203,109

By the mid-point of the study period, 2022, the greatest savings come from:
Replacement of interior lamps (linear fluorescent, screw in, and HID systems: 42,202 MWh)
Replacement of office equipment with more efficient units (101,556 MWh)
Replacement of exterior lamps (40,855 GWh)
Installation of Energy Management Systems (25,108 MWh)
Retrocommissioning of lighting systems (21,760 MWh)
Together, these five measures account for 285,137 MWh or 47% of the realistic achievable
potential savings in the commercial sector in 2022.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 899 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-23
An EnerNOC Company
6.5 SENSITIVITY ANALYSIS
Global conducted two sets of sensitivity analyses to better understand the effects of changing
assumptions on conservation potential. The first looked at changes in avoided costs, and the
second considered lower rates of customer and economic growth in Avista’s service territory.
Because these sensitivity analyses were conducted using an interim, earlier set of potential
results, the potential levels in the discussion below are slightly lower than the potential levels
presented elsewhere in this chapter. For example, the 2032 realistic achievable cumulative
potential in 2032 shown above is 2,155,133 MWh, but the value in the sensitivity analyses is
2,106,548 MWh or 2% less. However, the project team agreed that the general results of the
sensitivity analyses would be essentially unchanged, and therefore the sensitivity analyses based
on interim results are presented here.
6.5.1 Sensitivity of Potential to Avoided Cost
Global modeled several scenarios with varying levels of avoided costs in addition to the base
case. The other scenarios included 150%, 125%, and 75% of the avoided costs used in the base
case. Figure 6-11 illustrates how realistic achievable potential varies under the four scenarios.
The dotted line in Figure 6-11 indicates the technical potential, which is not affected by avoided
costs. The four other lines illustrate how economic potential changes over time with avoided
costs. While the changes are significant, the relationship between avoided cost and achievable
potential is not linear and increases in avoided costs do not provide equivalent percentage
increases in economic potential, and therefore in achievable potential also. Technical potential
imposes a limit on the amount of additional conservation and each incremental unit of
conservation becomes increasingly expensive.
Figure 6-11 Energy Savings, Economic Potential Case by Avoided Costs Scenario (MWh)

Table 6-19 provides additional information on how avoided cost changes affect realistic
achievable potential. In the reference case, realistic achievable potential is approximately 16.4%
of the baseline forecast by 2032. With the 150% avoided cost case, realistic achievable potential
increased to 19.2% of the baseline forecast, while the 125% avoided cost case and the 75%
avoided cost case yielded realistic achievable potential equal to 18.1% and 13.2% of the
baseline forecast respectively.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 900 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-24 www.gepllc.com

Table 6-19 Realistic Achievable Potential with Varying Avoided Costs
Reference
Scenario
75% of
avoided costs
125% of
avoided costs
150% of
avoided costs
Realistic achievable potential savings
2032 (MWh) 2,106,584 1,690,671 2,320,926 2,464,465
Realistic achievable potential,
percentage of baseline forecast, 2032 16.4% 13.2% 18.1% 19.2%
Percentage change in savings vs.
100% avoided cost scenario -20% 10% 17%
Note: Value of 2,106,548 MWh for 2032 realistic achievable potential was based on interim results and thus
is different from the value shown elsewhere in this report.
The project developed a series of supply curves based on the four avoided cost scenarios, shown
in Figure 6-12. Each supply curve is created by stacking measures and equipment over the 20-
year planning horizon in ascending order of cost. As expected, this stacking of conservation
resources produces a traditional upward-sloping supply curve. Because there is a gap in the cost
of the energy efficiency measures as you move up the supply curve, the measures with a very
high cost cause a rapid sloping of the supply curve. The 75% of avoided cost scenario provides
roughly a 13% reduction in energy use compared with the baseline forecast in 2032, at a cost of
$0.05/kWh or less. The other three scenarios track one another closely, providing just over 15%
savings in 2032 at costs below $0.05/kWh. Results do not differ greatly until the curves begin to
reach the increasingly high-cost measures.
Figure 6-12 Supply Curves for Evaluated EE Measures and Avoided Cost Scenarios

6.5.2 Sensitivity of Potential to Customer and Economic Growth
This conservation potential assessment shows that conservation offsets roughly half of growth in
electrical energy use for the Avista system, whereas the Sixth Plan projects that conservation can
offset 80% of growth. Of course, Avista’s service territory differs from the region overall in many
ways, including its climate. Another significant factor may be the CPA study’s assumptions
regarding customer and economic growth. To better understand how growth affects the study’s
results, we used the LoadMAP model to evaluate several scenarios with lower customer and
$0.00
$0.05
$0.10
$0.15
$0.20
$0.25
0%5%10%15%20%
Co
s
t

p
e
r

k
W
h

s
a
v
e
d
% Reduction from Baseline in 2032
100% avoided costs scenario 75% avoided costs scenario
125% avoided costs scenario 150% avoided costs scenario
∆ Portfolio average cost for each scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 901 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-25
An EnerNOC Company
economic growth, as indicated in Table 6-20. Low Growth Scenario 1 assumes that home size (in
square footage) grows 1% per year but is then capped at 110% of home size in the base year.
This scenario also assumes lower rates of income growth, as shown in Table 6-20. The Low
Growth Scenario 2 uses the same assumptions but in addition assumes lower customer growth in
terms of total households for the residential sector and total square footage for the C&I sector.
Table 6-20 Varying Growth Scenario Descriptions
Reference
Scenario
Low Growth
Scenario 1
Low Growth
Scenario 2
Home size ~ 1% per year growth Capped at 110% of
existing home size
Capped at 110% of existing
home size
Per capita income growth
1.6% 2011–2015;
2.2% 2016–2020;
2.1% thereafter
1.6% after 2016 1.6% after 2016
Residential sector market
growth
1.30% after 2015 (WA)
1.25% after 2015 (ID) no change 1.0% after 2015 (WA & ID)
Commercial sector
market growth, WA & ID
~ 2.0% (varies by
segment) no change 1.0% all segments

Table 6-21 shows that as economic and customer growth decreases, the ability of conservation
to offset growth increases. In the reference scenario, energy efficiency offsets 52% of growth in
consumption, while in the lower growth scenarios, EE offsets 54% and 76% of growth
respectively. This is the case because with reduced new construction, load growth and realistic
achievable potential drop, but savings due to the retrofit of existing buildings constitute a greater
proportion of load growth.
Table 6-21 Varying Growth Scenario Results
Reference
Scenario
Low Growth
Scenario 1
Low Growth
Scenario 2
Baseline forecast 2012 (MWh) 8,799,039 8,799,039 8,799,033
Baseline forecast 2032 (MWh) 12,851,760 12,523,843 11,178,008
Load growth 2012-2032 (MWh) 4,052,720 3,724,803 2,378,975
Realistic achievable potential forecast
2032 (MWh) 10,745,176 10,500,088 9,366,471
Realistic achievable potential savings 2032
(MWh) 2,106,584 2,023,754 1,811,538
Percentage of growth offset 52% 54% 76%
Note: Value of 2,106,548 MWh for 2032 realistic achievable potential was based on an interim results
reference case and thus is different from the value shown elsewhere in this report. The general effects
would be the same with the revised reference case.

6.6 PUMPING POTENTIAL
Table 6-22 displays the 2009 electricity sales and peak demand of Avista’s pumping customers.
These customers include mostly municipal water systems and some irrigation customers. The
pumping accounts represent 2.2% of total electricity sales and 0.8% of peak demand. (Total in
this case refers to the rate classes listed in Table 3-1 and Table 3-2: residential, commercial,
industrial, and pumping). Because pumping represents a relatively small percentage of Avista’s
total sales, the project team decided to use the NWPCC Sixth Plan calculator to estimate
pumping energy efficiency potential.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 902 of 1069
Energy Efficiency Potential Results Avista Conservation Potential Assessment Study
6-26 www.gepllc.com

Table 6-22 Pumping Rate Classes, Electricity Sales and Peak Demand 2009
Sector
Rate
Schedule(s)
Number of meters
(customers)
2009 Electricity
sales (MWh)
Peak demand
(MW)
Pumping, Washington 031, 032 2,361 135,999 10
Pumping, Idaho 031, 032 1,312 58,885 4
Pumping, Total 3,673 194,884 14
Percentage of System Total 2.2% 0.8%

The Sixth Plan Calculator estimates agricultural conservation targets based on 2007 sales. It
provides annual conservation targets through 2019. Therefore, we trended the data through
2022 to provide annual savings estimates for the ten-year period 2012–2022, with the results
shown in Figure 6-13. Table 6-23 displays incremental annual savings potential for 2012–2015,
while Table 6-24 provides cumulative potential for selected years.
Figure 6-13 Sixth Plan Calculator Agriculture Incremental Annual Potential

Table 6-23 Sixth Plan Calculator Agriculture Incremental Annual Potential, Selected
Years (MWh)
Segment 2012 2013 2014 2015
Pumping, Washington 1,567 1,484 1,402 1,835
Pumping, Idaho 690 654 618 809
Pumping, Total 2,257 2,138 2,020 2,643

-
500
1,000
1,500
2,000
2,500
3,000
An
n
u
a
l

S
a
v
i
n
g
s

(
M
W
h
)
Pumping Annual Potential,
Idaho
Pumping Annual Potential,
Washington
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 903 of 1069
Avista Conservation Potential Assessment Study Energy Efficiency Potential Results
Global Energy Partners, LLC 6-27
An EnerNOC Company
Table 6-24 Sixth Plan Calculator Agriculture Cumulative Potential, Selected Years
(MWh)
Measure 2012 2017 2022
Pumping, Washington 1,567 9,979 18,892
Pumping, Idaho 690 4,397 8,324
Pumping, Total 2,257 14,375 27,217

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 904 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 905 of 1069

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 906 of 1069

Global Energy Partners An EnerNOC Company 500 Ygnacio Valley Road, Suite 450
Walnut Creek, CA 94596
P: 925.482.2000
F: 925.284.3147 E: [e-mail]
ABOUT GLOBAL
Global Energy Partners is a premier provider of energy and
environmental engineering and technical services to utilities,
energy companies, research organizations,
government/regulatory agencies and private industry.
Global’s offerings range from strategic planning to turn-key
program design and implementation and technology
applications.
Global is a wholly-owned subsidiary of EnerNOC, Inc committed
to helping its clients achieve strategic business objectives with a
staff of world-class experts, state of the art tools, and proven
methodologies.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 907 of 1069

Global Energy Partners
An EnerNOC Company 500 Ygnacio Valley Road, Suite 450
Walnut Creek, CA 94596
P: 925.482.2000
F: 925.284.3147
E: [e-mail]

AVISTA CONSERVATION
POTENTIAL ASSESSMENT
APPENDICES
Final Report — Electricity Potentials
August 19, 2011
J. Borstein, Project Manager
I. Rohmund, Director

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 908 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 909 of 1069

Global Energy Partners iii
An EnerNOC Company

This report was prepared by
Global Energy Partners
An EnerNOC Company
500 Ygnacio Valley Blvd., Suite 450
Walnut Creek, CA 94596
Principal Investigator(s):
I. Rohmund
J. Borstein
A. Duer
B. Kester
J. Prijyanonda
S. Yoshida

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 910 of 1069
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Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 911 of 1069

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CONTENTS
A WASHINGTON MARKET PROFILES, BASELINE FORECAST, AND POTENTIAL
RESULTS .................................................................................................... A-1 
B IDAHO MARKET PROFILES, BASELINE FORECAST, AND POTENTIAL
RESULTS .................................................................................................... B-1 
C RESIDENTIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA .. C-1 
D COMMERCIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA .. D-1 
E REFERENCES .............................................................................................. E-1 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 912 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 913 of 1069

Global Energy Partners vii
An EnerNOC Company

LIST OF FIGURES
Figure A–1 Residential Baseline Forecast by End Use, Washington ........................................ A-11 
Figure A-2 C&I Baseline Electricity Forecast by End Use, Washington .................................... A-11 
Figure A-3 Baseline Forecast Summary by Sector, Washington ............................................. A-12 
Figure A-4 Summary of Energy Efficiency Potential Savings, Washington, All Sectors .............. A-13 
Figure A-5 Energy Efficiency Potential Forecasts, Washington, All Sectors ............................. A-13 
Figure A-6 Achievable Cumulative Potential by Sector, Washington ....................................... A-15 
Figure A-7 Residential Energy Efficiency Potential Savings, Washington ................................ A-15 
Figure A-8 Residential Energy Efficiency Potential Forecast, Washington ............................... A-15 
Figure A–9 Residential Achievable Potential by End Use, Selected Years, Washington ............. A-19 
Figure A-10 Energy Efficiency Potential Savings, C&I Sector, Washington ................................ A-22 
Figure A-11 Energy Efficiency Potential Forecast, C&I Sector, Washington .............................. A-22 
Figure A-12 C&I Achievable Potential by End Use, Selected Years, Washington ........................ A-26 
Figure B–1 Residential Baseline Forecast by End Use, Idaho ................................................. B-11 
Figure B–2 C&I Baseline Electricity Forecast by End Use, Idaho ............................................ B-11 
Figure B–3 Baseline Forecast Summary by Sector, Idaho ...................................................... B-12 
Figure B–4 Summary of Energy Efficiency Potential Savings, Idaho, All Sectors ...................... B-13 
Figure B–5 Energy Efficiency Potential Forecasts, Idaho, All Sectors ...................................... B-13 
Figure B–6 Achievable Cumulative Potential by Sector, Idaho ............................................... B-15 
Figure B–7 Residential Energy Efficiency Potential Savings, Idaho ......................................... B-15 
Figure B–8 Residential Energy Efficiency Potential Forecast, Idaho ........................................ B-15 
Figure B–9 Residential Achievable Potential by End Use, Selected Years, Idaho ...................... B-19 
Figure B–10 Energy Efficiency Potential Savings, C&I Sector, Idaho ........................................ B-22 
Figure B–11 Energy Efficiency Potential Forecast, C&I Sector, Idaho ....................................... B-22 
Figure B-12 C&I Achievable Potential by End Use, Selected Years, Idaho ................................ B-26 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 914 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 915 of 1069

Global Energy Partners ix
An EnerNOC Company

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 916 of 1069
x www.gepllc.com
LIST OF TABLES
Table A–1 Electricity Sales and Peak Demand by Rate Class, Washington 2009 ....................... A-1 
Table A-2 Residential Electricity Usage and Intensity by Segment, Washington 2009............... A-1 
Table A-3  Single Family Market Profile, 2009, Washington .................................................... A-2 
Table A-4  Multi-family Market Profile, 2009, Washington ...................................................... A-3 
Table A-5  Mobile Home Market Profile, 2009, Washington .................................................... A-4 
Table A-6  Limited Income Market Profile, 2009, Washington ................................................. A-5 
Table A-7 Commercial Sector Market Characterization Results, Washington 2009 .................... A-6 
Table A-8 Small/Medium Commercial Segment Market Profile, Washington, 2009 ................... A-7 
Table A-9 Large Commercial Segment Market Profile, Washington, 2009 ............................... A-8 
Table A-10 Extra Large Commercial Segment Market Profile, Washington, 2009 ....................... A-9 
Table A-11 Extra Large Industrial Segment Market Profile, Washington, 2009 ........................ A-10 
Table A-12 Baseline Forecast Summary by Sector, Washington ............................................. A-12 
Table A-13 Summary of Energy Efficiency Potential, Washington, All Sectors ......................... A-14 
Table A-14 Achievable Cumulative EE Potential by Sector, Washington (MWh) ....................... A-14 
Table A-15 Energy Efficiency Potential for the Residential Sector, Washington ........................ A-16 
Table A-16 Residential Baseline & Achievable Potential by Segment, Washington ................... A-17 
Table A-17 Residential Potential by Housing Type, 2022, Washington .................................... A-17 
Table A-18 Residential Cumulative Savings by End Use and Potential Type, Washington (MWh)A-18 
Table A-19 Residential Potential by End Use and Market Segment, 2022, WA (MWh) .............. A-19 
Table A-20 Residential Cumulative Achievable Potential by End Use and Equipment Measures,
Washington, Selected Years (MWh) ................................................................... A-20 
Table A-21 Residential Achievable Savings for Non-equipment Measures, Washington (MWh) . A-21 
Table A-22 Energy Efficiency Potential, C&I Sector, Washington ........................................... A-23 
Table A-23 C&I Sector, Baseline and Achievable Potential by Segment, Washington ............... A-24 
Table A-24 C&I Potential by Segment, Washington, 2022 ..................................................... A-24 
Table A-25 C&I Cumulative Savings by End Use and Potential Type, Washington (MWh) ......... A-25 
Table A-26 C&I Achievable Potential by End Use and Market Segment, 2022, Washington (MWh)A-26 
Table A-27 C&I Cumulative Achievable Potential by End Use and Equipment Measures, Washington
(MWh) ............................................................................................................ A-27 
Table A-28 C&I Cumulative Achievable Savings for Non-equipment Measures, Washington (MWh)A-28 
Table B–1 Electricity Use and Peak Demand by Rate Class, Idaho 2009 .................................. B-1 
Table B–2 Residential Electricity Usage and Intensity by Segment, Idaho 2009 ....................... B-1 
Table B–3 Single Family Market Profile, 2009, Idaho ............................................................. B-2 
Table B–4 Multi-family Market Profile, 2009, Idaho ............................................................... B-3 
Table B–5  Mobile Home Market Profile, 2009, Idaho ............................................................. B-4 
Table B–6 Limited Income Market Profile, 2009, Idaho ......................................................... B-5 
Table B–7 Commercial Sector Market Characterization Results, Idaho 2009 ............................ B-6 
Table B–8 Small/Medium Commercial Segment Market Profile, Idaho, 2009 ............................ B-7 
Table B–9 Large Commercial Segment Market Profile, Idaho, 2009 ........................................ B-8 
Table B–10 Extra Large Commercial Segment Market Profile, Idaho, 2009 ................................ B-9 
Table B–11 Extra Large Industrial Segment Market Profile, Idaho, 2009 ................................. B-10 
Table B-12 Baseline Forecast Summary by Sector, Idaho ...................................................... B-12 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 917 of 1069
Table B–13 Summary of Energy Efficiency Potential, Idaho, All Sectors .................................. B-14 
Table B–14 Achievable Cumulative EE Potential by Sector, Idaho (MWh) ................................ B-14 
Table B–15 Energy Efficiency Potential for the Residential Sector, Idaho ................................ B-16 
Table B-16 Residential Baseline & Achievable Potential by Segment, Idaho ............................ B-17 
Table B-17 Residential Potential by Housing Type, 2022, Idaho ............................................ B-17 
Table A-18 Residential Cumulative Savings by End Use and Potential Type, Oregon (MWh) ..... B-18 
Table B-19 Residential Potential by End Use and Market Segment, 2022, WA (MWh) .............. B-19 
Table B–20 Residential Cumulative Achievable Potential by End Use and Equipment Measures,
Oregon, Selected Years (MWh) .......................................................................... B-20 
Table B–21 Residential Achievable Savings for Non-equipment Measures, Idaho (MWh) .......... B-21 
Table B–22 Energy Efficiency Potential, C&I Sector, Idaho .................................................... B-23 
Table B–23 C&I Sector, Baseline and Achievable Potential by Segment, Idaho ........................ B-24 
Table B–24 C&I Potential by Segment, Idaho, 2022 .............................................................. B-24 
Table B-25 C&I Cumulative Savings by End Use and Potential Type, Idaho (MWh) ................. B-25 
Table B-26 C&I Achievable Potential by End Use Market Segment, 2022, Idaho (MWh) ........... B-26 
Table B-27 C&I Cumulative Achievable Potential by End Use and Equipment Measures, Washington
(MWh) ............................................................................................................ B-27 
Table B-28 C&I Cumulative Achievable Savings for Non-equipment Measures, Idaho (MWh) ... B-28 
Table C–1 Residential Energy Efficiency Equipment/Measure Descriptions ............................... C-2 
Table C-2 Energy Efficiency Equipment Data — Single Family, Existing Vintage....................... C-9 
Table C-3 Energy Efficiency Equipment Data — Multi Family, Existing Vintage ...................... C-11 
Table C-4 Energy Efficiency Equipment Data — Mobile Home, Existing Vintage ..................... C-13 
Table C-5 Energy Efficiency Equipment Data — Limited Income, Existing Vintage ................. C-15 
Table C-6 Energy Efficiency Equipment Data —Single Family, New Vintage .......................... C-17 
Table C-7 Energy Efficiency Equipment Data — Multi Family, New Vintage ........................... C-19 
Table C-8 Energy Efficiency Equipment Data — Mobile Home, New Vintage ......................... C-21 
Table C-9 Energy Efficiency Equipment Data — Limited Income, New Vintage ...................... C-23 
Table C-10 Energy-Efficiency Measure Data—Single Family, Existing Vintage .......................... C-25 
Table C-11 Energy-Efficiency Measure Data — Multi Family, Existing Vintage ......................... C-26 
Table C-12 Energy-Efficiency Measure Data — Mobile Home, Existing Vintage ........................ C-27 
Table C-13 Energy-Efficiency Measure Data — Limited Income, Existing Vintage .................... C-28 
Table C-14 Energy-Efficiency Measure Data — Single Family, New Vintage ............................ C-29 
Table C-15 Energy-Efficiency Measure Data — Multi Family, New Vintage .............................. C-30 
Table C-16 Energy-Efficiency Measure Data — Mobile Home, New Vintage ............................. C-31 
Table C-17 Energy-Efficiency Measure Data — Limited Income, New Vintage ......................... C-32 
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions ........ D-2 
Table D-2 Energy Efficiency Equipment Data — Small/Medium Comm., Existing Vintage ........ D-16 
Table D-3 Energy Efficiency Equipment Data — Large Commercial, Existing Vintage .............. D-18 
Table D-4 Energy Efficiency Equipment Data — Extra Large Commercial, Existing Vintage ..... D-20 
Table D-5 Energy Efficiency Equipment Data — Extra Large Industrial, Existing Vintage ........ D-22 
Table D-6 Energy Efficiency Equipment Data — Small/Medium Commercial, New Vintage ...... D-24 
Table D-7 Energy Efficiency Equipment Data — Large Commercial, New Vintage .................. D-26 
Table D-8 Energy Efficiency Equipment Data — Extra Large Commercial, New Vintage .......... D-28 
Table D-9 Energy Efficiency Equipment Data — Extra Large Industrial, New Vintage ............. D-30 
Table D-10 Energy Efficiency Measure Data — Small/Med. Comm., Existing Vintage ............... D-32 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 918 of 1069
xii www.gepllc.com
Table D-11 Energy Efficiency Measure Data — Large Commercial, Existing Vintage ................. D-33 
Table D-12 Energy Efficiency Measure Data — Extra Large Comm., Existing Vintage ............... D-34 
Table D-13 Energy Efficiency Measure Data — Extra Large Industrial, Existing Vintage ........... D-35 
Table D-14 Energy Efficiency Measure Data — Small/Medium Comm., New Vintage ................ D-36 
Table D-15 Energy Efficiency Measure Data — Large Commercial, New Vintage...................... D-37 
Table D-16 Energy Efficiency Measure Data — Extra Large Commercial, New Vintage ............. D-38 
Table D-17 Energy Efficiency Measure Data — Extra Large Industrial, New Vintage ................ D-39 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 919 of 1069

Global Energy Partners A-1
An EnerNOC Company
APPENDIX A
WASHINGTON MARKET PROFILES, BASELINE FORECAST, AND POTENTIAL
RESULTS
This appendix contains Washington-specific tables that summarize the study assumptions, inputs,
and results for Avista’s Washington service territory only. These tables either repeat Washington-
specific information provided previously within the body of the report, or provide Washington-
specific information that corresponds to Avista system-level information in the report.
Table A–1 Electricity Sales and Peak Demand by Rate Class, Washington 2009
Sector 
Rate 
Schedule(s) 
Number of meters 
(customers) 
2009 Electricity 
sales (MWh) 
Peak demand 
(MW) 
Residential 001 200,134 2,451,687 710
General Service 011, 012 27,142 415,935 64
Large General Service 021, 022 3,352 1,556,929 232
Extra Large General Service 025 22 879,233 134
Pumping 031, 032 2,361 135,999 10
Total   233,011 5,439,850 1,150

Table A-2 Residential Electricity Usage and Intensity by Segment, Washington 2009
Washington  
Segment 
Intensity   
(kWh/Household) 
Number of  
Customers 
% of 
Customers 
2009 Electricity 
Sales (MWh) % of Sales 
Single Family 14,547 109,134 54% 1,587,572 65% 
Multi‐Family 8,728 18,219 9% 159,019 6% 
Mobile Home 13,092 5,248 3% 68,708 3% 
Limited Income 9,424 67,533 34% 636,407 26% 
Total 12,250 200,134 100% 2,451,707 100% 
Note: Minor differences with totals in Table A-1 due to calibration.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 920 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-2 www.gepllc.com

Table A-3 Single Family Market Profile, 2009, Washington

UEC Intensity Usage UEC Intensity
(kWh) (kWh/HH) (GWh)(kWh) (kWh/HH)
Cooling Central AC 36.8% 1,857            684                  75               73.4% 2,154          1,581            16%
Cooling Room AC 10.8% 683                74                     8                 1.4% 793             11                  16%
Combined Heating/Cooling Air Source Heat Pump 18.4% 6,091            1,122               122            15.0% 7,066          1,063            16%
Combined Heating/Cooling Geothermal Heat Pump 0.7% 3,655            26                     3                 0.8% 4,239          32                  16%
Space Heating Electric Resistance 6.2% 10,449          647                  71               3.0% 12,539       373                20%
Space Heating Electric Furnace 25.0% 8,360            2,088               228            25.0% 10,031       2,505            20%
Space Heating Supplemental 6.1% 117                7                       1                 6.1% 140             9                    20%
Water Heating Water Heater 55.3% 3,466            1,918               209            43.7% 4,177          1,827            21%
Interior Lighting Screw‐in 100.0% 1,452            1,452               158            100.0% 1,452          1,452            0%
Interior Lighting Linear Fluorescent 69.2% 152                105                  11               69.2% 152             105                0%
Interior Lighting Pin‐based 100.0% 60                  60                     7                 100.0% 60                60                  0%
Exterior Lighting Screw‐in 86.7% 381                330                  36               86.7% 381             330                0%
Exterior Lighting High Intensity/Flood 1.9% 146                3                       0                 1.9% 146             3                    0%
Appliances Clothes Washer 98.0% 126                124                  13               99.8% 154             154                22%
Appliances Clothes Dryer 92.8% 609                565                  62               89.0% 692             616                14%
Appliances Dishwasher 93.9% 246                231                  25               99.9% 271             271                11%
Appliances Refrigerator 100.0% 793                793                  87               100.0% 625             625                 ‐21%
Appliances Freezer 69.4% 773                536                  58               69.4% 708             491                 ‐8%
Appliances Second Refrigerator 47.3% 816                386                  42               20.5% 711             146                 ‐13%
Appliances Stove 82.1% 383                314                  34               82.1% 465             382                22%
Appliances Microwave 98.5% 168                166                  18               98.5%173             171                3%
Electronics Personal Computers 140.0% 279                391                  43               147.0% 287             422                3%
Electronics TVs 260.0% 359                933                  102            260.0% 400             1,041            12%
Electronics Devices and Gadgets 100.0% 60                  60                     7                 100.0% 67                67                  10%
Miscellaneous Pool Pump 13.3% 1,500            200                  22               14.0% 1,526          214                2%
Miscellaneous Furnace Fan 30.1% 500                151                  16               30.1% 614             185                23%
Miscellaneous Miscellaneous 100.0% 1,180            1,180               129            100.0% 1,416          1,416            20%
14,547            1,588         15,549          
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 921 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners, LLC A-3
Table A-4 Multi-family Market Profile, 2009, Washington

UEC Intensity Usage UEC Intensity
(kWh) (kWh/HH) (GWh)(kWh) (kWh/HH)
Cooling Central AC 5.0% 928                46                     1                 24.1% 1,003          241                8%
Cooling Room AC 25.0% 355                89                     2                 18.9% 384             73                  8%
Combined Heating/Cooling Air Source Heat Pump 1.0% 2,928            29                     1                 3.4% 3,163          108                8%
Combined Heating/Cooling Geothermal Heat Pump 0.0% 1,757            ‐                    ‐             0.5% 1,898          9                    8%
Space Heating Electric Resistance 59.0% 5,476            3,231               59               59.0% 6,023          3,554            10%
Space Heating Electric Furnace 5.0% 4,381            219                  4                 5.0% 4,819          241                10%
Space Heating Supplemental 18.0% 61                  11                     0                 18.9% 67                13                  10%
Water Heating Water Heater 77.0% 2,142            1,650               30               71.3% 2,362          1,684            10%
Interior Lighting Screw‐in 100.0% 750                750                  14               100.0% 750             750                0%
Interior Lighting Linear Fluorescent 32.0% 76                  24                     0                 32.0% 76                24                  0%
Interior Lighting Pin‐based 3.0% 75                  2                       0                 3.0% 75                2                    0%
Exterior Lighting Screw‐in 38.5% 55                  21                     0                 38.5% 55                21                  0%
Exterior Lighting High Intensity/Flood 0.2% 73                  0                       0                 0.2% 73                0                    0%
Appliances Clothes Washer 32.0% 63                  20                     0                 32.0% 70                22                  11%
Appliances Clothes Dryer 30.7% 582                179                  3                 30.7% 621             191                7%
Appliances Dishwasher 64.0% 88                  56                     1                 64.0% 93                59                  5%
Appliances Refrigerator 100.0% 677                677                  12               100.0% 665             665                 ‐2%
Appliances Freezer 8.4% 734                62                     1                 8.4% 703             59                   ‐4%
Appliances Second Refrigerator 5.0% 687                34                     1                 5.0% 631             32                   ‐8%
Appliances Stove 96.4% 163                158                  3                 96.4% 181             175                11%
Appliances Microwave 90.0% 99                  89                     2                 90.0% 101             91                  1%
Electronics Personal Computers 63.0% 223                141                  3                 66.2% 226             150                1%
Electronics TVs 165.0% 178                293                  5                 165.0% 188             310                6%
Electronics Devices and Gadgets 100.0% 25                  25                     0                 100.0% 26                26                  5%
Miscellaneous Pool Pump 0.0%‐                 ‐                    ‐             0.0%‐              ‐                0%
Miscellaneous Furnace Fan 13.0% 38                  5                       0                 13.0% 42                5                    11%
Miscellaneous Miscellaneous 100.0% 917                917                  17               100.0% 963             963                5%
8,728               159            9,468            
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 922 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-4 www.gepllc.com

Table A-5 Mobile Home Market Profile, 2009, Washington

UEC Intensity Usage UEC Intensity
(kWh) (kWh/HH) (GWh)(kWh) (kWh/HH)
Cooling Central AC 23.2% 1,106            256                  1                 35.9% 1,194          428                8%
Cooling Room AC 23.2% 407                94                     0                 22.0% 439             97                  8%
Combined Heating/Cooling Air Source Heat Pump 21.7% 3,488            759                  4                 22.8% 3,767          860                8%
Combined Heating/Cooling Geothermal Heat Pump 0.0% 2,093            ‐                    ‐             0.0% 2,260          ‐                8%
Space Heating Electric Resistance 0.0% 5,888            ‐                    ‐             0.0% 6,476          ‐                10%
Space Heating Electric Furnace 68.1% 4,710            3,209               17               68.1% 5,181          3,530            10%
Space Heating Supplemental 1.4% 34                  0                       0                 1.5% 37                1                    10%
Water Heating Water Heater 96.3% 1,766            1,702               9                 91.0% 1,947          1,771            10%
Interior Lighting Screw‐in 100.0% 1,307            1,307               7                 100.0% 1,307          1,307            0%
Interior Lighting Linear Fluorescent 69.2% 137                95                     0                 69.2% 137             95                  0%
Interior Lighting Pin‐based 100.0% 54                  54                     0                 100.0% 54                54                  0%
Exterior Lighting Screw‐in 86.7% 343                297                  2                 86.7% 343             297                0%
Exterior Lighting High Intensity/Flood 1.9% 131                2                       0                 1.9% 131             2                    0%
Appliances Clothes Washer 96.3% 128                124                  1                 96.3% 142             137                11%
Appliances Clothes Dryer 98.8% 620                612                  3                 98.8% 662             653                7%
Appliances Dishwasher 89.0% 250                222                  1                 89.0% 263             234                5%
Appliances Refrigerator 100.0% 806                806                  4                 100.0% 792             792                 ‐2%
Appliances Freezer 59.3% 786                466                  2                 59.3% 753             446                 ‐4%
Appliances Second Refrigerator 19.5% 830                162                  1                 19.5% 762             149                 ‐8%
Appliances Stove 93.9% 344                323                  2                 93.9% 381             358                11%
Appliances Microwave 82.0% 151                124                  1                 82.0%154             126                2%
Electronics Personal Computers 116.5% 262                305                  2                 122.3% 265             324                1%
Electronics TVs 260.0% 359                933                  5                 260.0% 380             987                6%
Electronics Devices and Gadgets 100.0% 60                  60                     0                 100.0% 64                64                  5%
Miscellaneous Pool Pump 11.1% 1,500            167                  1                 11.7% 1,513          177                1%
Miscellaneous Furnace Fan 8.3% 500                42                     0                 8.3% 557             47                  11%
Miscellaneous Miscellaneous 100.0% 971                971                  5                 100.0% 1,020          1,020            5%
13,092            69               13,955          
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 923 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners, LLC A-5
Table A-6 Limited Income Market Profile, 2009, Washington

UEC Intensity Usage UEC Intensity
(kWh) (kWh/HH) (GWh)(kWh) (kWh/HH)
Cooling Central AC 22.2% 1,049            233                  16               28.7% 1,133          325                8%
Cooling Room AC 35.4% 712                252                  17               18.0% 769             138                8%
Combined Heating/Cooling Air Source Heat Pump 10.4% 2,372            247                  17               10.4% 2,561          267                8%
Combined Heating/Cooling Geothermal Heat Pump 0.0% 1,423            ‐                    ‐             0.5% 1,537          8                    8%
Space Heating Electric Resistance 32.0% 5,164            1,651               112            28.8% 5,680          1,635            10%
Space Heating Electric Furnace 19.3% 4,123            796                  54               21.2% 4,536          963                10%
Space Heating Supplemental 12.7% 63                  8                       1                 13.4% 69                9                    10%
Water Heating Water Heater 83.9% 2,334            1,958               132            67.0% 2,574          1,725            10%
Interior Lighting Screw‐in 100.0% 728                728                  49               100.0% 728             728                0%
Interior Lighting Linear Fluorescent 69.2% 75                  52                     3                 69.2% 75                52                  0%
Interior Lighting Pin‐based 100.0% 59                  59                     4                 100.0% 59                59                  0%
Exterior Lighting Screw‐in 47.1% 106                50                     3                 47.1% 106             50                  0%
Exterior Lighting High Intensity/Flood 2.7% 84                  2                       0                 2.7%84                2                    0%
Appliances Clothes Washer 71.3% 55                  39                     3                 71.3% 61                43                  11%
Appliances Clothes Dryer 68.6% 652                447                  30               68.6% 696             477                7%
Appliances Dishwasher 78.5% 72                  56                     4                 78.5% 75                59                  5%
Appliances Refrigerator 100.0% 677                677                  46               100.0% 665             665                 ‐2%
Appliances Freezer 63.4% 734                466                  31               63.4% 703             446                 ‐4%
Appliances Second Refrigerator 23.4% 687                161                  11               23.4% 631             148                 ‐8%
Appliances Stove 89.7% 196                176                  12               89.7% 217             195                11%
Appliances Microwave 92.6% 109                101                  7                 92.6% 111             102                1%
Electronics Personal Computers 101.4% 230                233                  16               106.5% 233             248                1%
Electronics TVs 165.0% 204                337                  23               165.0% 216             356                6%
Electronics Devices and Gadgets 100.0% 30                  30                     2                 105.0% 32                33                  5%
Miscellaneous Pool Pump 5.8% 617                36                     2                 5.8% 622             36                  1%
Miscellaneous Furnace Fan 25.2% 213                54                     4                 25.2% 238             60                  11%
Miscellaneous Miscellaneous 100.0% 575                575                  39               100.0% 604             604                5%
9,424               636            9,434            
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 924 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-6 www.gepllc.com

Table A-7 Commercial Sector Market Characterization Results, Washington 2009
Avista Rate Schedule LoadMAP Segment 
and Typical Building 
Electricity 
sales (MWh) 
Intensity 
(kWh/sq.ft.) 
General Service  011, 012 Small and Medium Commercial —Retail 415,935 17.5
Large General Service  021, 022 Large Commercial —Office 1,556,929 16.7
Extra Large General 
Service Commercial  
025C Extra Large Commercial —University 265,686 13.9
Extra Large General 
Service Industrial  
025I Extra Large Industrial 613,615 40.0
Total     2,852,165 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 925 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners, LLC A-7
Table A-8 Small/Medium Commercial Segment Market Profile, Washington, 2009

EUI Intensity Usage EUI Intensity
(kWh) (kWh/Sqft.) (GWh)(kWh) (kWh/Sqft.)
Cooling Central Chiller 13.8% 2.39               0.33                 8                 13.8% 2.15            0.30               ‐10%
Cooling RTU 63.1% 2.46               1.55                 37               63.1% 2.22            1.40               ‐10%
Cooling PTAC 3.3% 2.44               0.08                 2                 3.3% 2.20            0.07               ‐10%
Combined Heating/Cooling Heat Pump 3.6% 6.19               0.22                 5                 3.6% 5.57            0.20               ‐10%
Space Heating Electric Resistance 5.9% 6.72               0.39                 9                 5.9% 6.72            0.39              0%
Space Heating Furnace 17.7% 7.05               1.25                 30               17.7% 6.34            1.13               ‐10%
Ventilation Ventilation 76.9% 2.09               1.61                 38               76.9% 1.88            1.45               ‐10%
Interior Lighting Interior Screw‐in 100.0%1.00               1.00                 24               100.0% 0.90            0.90               ‐10%
Interior Lighting HID 100.0% 0.68               0.68                 16               100.0% 0.61            0.61               ‐10%
Interior Lighting Linear Fluorescent 100.0% 3.37               3.37                 80               100.0% 3.03            3.03               ‐10%
Exterior Lighting Exterior Screw‐in 82.6% 0.20               0.16                 4                 82.6% 0.18            0.15               ‐10%
Exterior Lighting HID 82.6% 0.76               0.63                 15               82.6% 0.68            0.56               ‐10%
Exterior Lighting Linear Fluorescent 82.6% 0.16               0.13                 3                 82.6% 0.14            0.12               ‐10%
Water Heating Water Heater 63.0% 2.00               1.26                 30               63.0% 1.90            1.19              ‐5%
Food Preparation Fryer 25.8% 0.16               0.04                 1                 25.8% 0.16            0.04              0%
Food Preparation Oven 25.8% 0.98               0.25                 6                 25.8% 0.98            0.25              0%
Food Preparation Dishwasher 25.8% 0.06               0.01                 0                 25.8% 0.06            0.01              0%
Food Preparation Hot Food Container 25.8% 0.31               0.08                 2                 25.8% 0.31            0.08              0%
Food Preparation Food Prep 25.8% 0.01               0.00                 0                 25.8% 0.01            0.00              0%
Refrigeration Walk in Refrigeration 0.0%‐                 ‐                    ‐             0.0%‐              ‐                
Refrigeration Glass Door Display 52.4% 0.45               0.23                 6                 52.4% 0.40            0.21               ‐10%
Refrigeration Solid Door Refrigerator 52.4% 0.50               0.26                 6                 52.4% 0.45            0.24               ‐10%
Refrigeration Open Display Case 52.4% 0.04               0.02                 1                 52.4% 0.04            0.02               ‐10%
Refrigeration Vending Machine 52.4% 0.30               0.16                 4                 52.4% 0.30            0.16              0%
Refrigeration Icemaker 52.4% 0.34               0.18                 4                 52.4% 0.34            0.18              0%
Office Equipment Desktop Computer 99.9% 0.48               0.48                 11               99.9% 0.48            0.48              0%
Office Equipment Laptop Computer 99.9% 0.06               0.06                 1                 99.9% 0.06            0.06              0%
Office Equipment Server 99.9% 0.36               0.36                 9                 99.9% 0.36            0.36              0%
Office Equipment Monitor 99.9% 0.25               0.25                 6                 99.9% 0.25            0.25              0%
Office Equipment Printer/copier/fax 99.9% 0.24               0.24                 6                 99.9% 0.24            0.24              0%
Office Equipment POS Terminal 99.9% 0.27               0.27                 7                 99.9% 0.27            0.27              0%
Miscellaneous Non‐HVAC Motor 40.2% 1.22               0.49                 12               40.2% 1.22            0.49              0%
Miscellaneous Other Miscellaneous 100.0% 1.43               1.43                 34               100.0% 1.43            1.43              0%
17.50             416          16.3            
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 926 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-8 www.gepllc.com

Table A-9 Large Commercial Segment Market Profile, Washington, 2009

EUI Intensity Usage EUI Intensity
(kWh) (kWh/Sqft.) (GWh)(kWh) (kWh/Sqft.)
Cooling Central Chiller 24.7% 2.15               0.53                 49               24.7% 1.93            0.48               ‐10%
Cooling RTU 37.8% 2.52               0.95                 89               37.8% 2.26            0.86               ‐10%
Cooling PTAC 3.8% 2.49               0.09                 9                 3.8% 2.24            0.08               ‐10%
Combined Heating/Cooling Heat Pump 9.1% 4.81               0.44                 41               9.1% 4.33            0.40               ‐10%
Space Heating Electric Resistance 5.9% 3.62               0.21                 20               5.9% 3.62            0.21              0%
Space Heating Furnace 12.7% 4.68               0.60                 55               12.7% 4.21            0.54               ‐10%
Ventilation Ventilation 75.1% 1.66               1.24                 116            75.1% 1.49            1.12               ‐10%
Interior Lighting Interior Screw‐in 100.0% 0.94               0.94                 88               100.0% 0.85            0.85               ‐10%
Interior Lighting HID 100.0% 0.71               0.71                 66               100.0% 0.64            0.64               ‐10%
Interior Lighting Linear Fluorescent 100.0% 3.29               3.29                 307            100.0% 2.96            2.96               ‐10%
Exterior Lighting Exterior Screw‐in 89.6% 0.11               0.10                 9                 89.6% 0.10            0.09               ‐10%
Exterior Lighting HID 89.6% 0.62               0.56                 52               89.6% 0.56            0.50               ‐10%
Exterior Lighting Linear Fluorescent 89.6% 0.16               0.14                 13               89.6% 0.14            0.13               ‐10%
Water Heating Water Heater 54.2% 2.31               1.25                 117            54.2% 2.20            1.19              ‐5%
Food Preparation Fryer 18.4% 0.35               0.06                 6                 18.4% 0.35            0.06              0%
Food Preparation Oven 18.4% 1.88               0.35                 32               18.4% 1.88            0.35              0%
Food Preparation Dishwasher 18.4% 0.19               0.03                 3                 18.4% 0.19            0.03              0%
Food Preparation Hot Food Container 18.4% 0.27               0.05                 5                 18.4% 0.27            0.05              0%
Food Preparation Food Prep 18.4% 0.02               0.00                 0                 18.4% 0.02            0.00              0%
Refrigeration Walk in Refrigeration 39.1% 0.48               0.19                 17               39.1% 0.43            0.17               ‐10%
Refrigeration Glass Door Display 39.1% 0.37               0.14                 13               39.1% 0.33            0.13               ‐10%
Refrigeration Solid Door Refrigerator 39.1% 0.77               0.30                 28               39.1% 0.69            0.27               ‐10%
Refrigeration Open Display Case 39.1% 0.27               0.10                 10               39.1% 0.24            0.09               ‐10%
Refrigeration Vending Machine 39.1% 0.36               0.14                 13               39.1% 0.36            0.14              0%
Refrigeration Icemaker 39.1% 0.66               0.26                 24               39.1% 0.66            0.26              0%
Office Equipment Desktop Computer 98.4% 0.90               0.88                 82               98.4% 0.90            0.88              0%
Office Equipment Laptop Computer 98.4% 0.07               0.07                 6                 98.4% 0.07            0.07              0%
Office Equipment Server 98.4% 0.42               0.41                 38               98.4% 0.42            0.41              0%
Office Equipment Monitor 98.4% 0.21               0.20                 19               98.4% 0.21            0.20              0%
Office Equipment Printer/copier/fax 98.4% 0.21               0.21                 19               98.4% 0.21            0.21              0%
Office Equipment POS Terminal 98.4% 0.07               0.07                 6                 98.4% 0.07            0.07              0%
Miscellaneous Non‐HVAC Motor 57.7% 1.40               0.81                 75               57.7% 1.40            0.81              0%
Miscellaneous Other Miscellaneous 100.0% 1.36               1.36                 127            100.0% 1.36            1.36              0%
16.70               1,557         15.6              
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 927 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners, LLC A-9
Table A-10 Extra Large Commercial Segment Market Profile, Washington, 2009

EUI Intensity Usage EUI Intensity
(kWh) (kWh/Sqft.) (GWh)(kWh) (kWh/Sqft.)
Cooling Central Chiller 52.2% 2.13               1.11                 21               52.2% 1.92            1.00               ‐10%
Cooling RTU 24.7% 2.22               0.55                 10               24.7% 2.00            0.49               ‐10%
Cooling PTAC 0.0% 2.22               ‐                    ‐             0.0% 2.00            ‐                 ‐10%
Combined Heating/Cooling Heat Pump 4.4% 5.23               0.23                 4                 4.4% 4.70            0.21               ‐10%
Space Heating Electric Resistance 15.8% 4.39               0.69                 13               15.8% 4.39            0.69              0%
Space Heating Furnace 5.6% 5.67               0.32                 6                 5.6% 5.11            0.29               ‐10%
Ventilation Ventilation 90.2% 1.94               1.75                 33               90.2% 1.74            1.57               ‐10%
Interior Lighting Interior Screw‐in 100.0%1.37               1.37                 26               100.0% 1.23            1.23               ‐10%
Interior Lighting HID 100.0% 0.29               0.29                 6                 100.0% 0.26            0.26               ‐10%
Interior Lighting Linear Fluorescent 100.0% 2.19               2.19                 42               100.0% 1.97            1.97               ‐10%
Exterior Lighting Exterior Screw‐in 96.3% 0.03               0.03                 1                 96.3% 0.03            0.03               ‐10%
Exterior Lighting HID 96.3% 0.88               0.85                 16               96.3% 0.79            0.76               ‐10%
Exterior Lighting Linear Fluorescent 96.3% 0.04               0.03                 1                 96.3% 0.03            0.03               ‐10%
Water Heating Water Heater 26.3% 3.72               0.98                 19               26.3% 3.53            0.93               ‐5%
Food Preparation Fryer 13.8% 0.13               0.02                 0                 13.8% 0.13            0.02              0%
Food Preparation Oven 13.8% 2.12               0.29                 6                 13.8% 2.12            0.29              0%
Food Preparation Dishwasher 13.8% 0.08               0.01                 0                 13.8% 0.08            0.01              0%
Food Preparation Hot Food Container 13.8% 0.13               0.02                 0                 13.8% 0.13            0.02              0%
Food Preparation Food Prep 13.8% 0.01               0.00                 0                 13.8% 0.01            0.00              0%
Refrigeration Walk in Refrigeration 26.6% 0.19               0.05                 1                 26.6% 0.17            0.04               ‐10%
Refrigeration Glass Door Display 26.6% 0.11               0.03                 1                 26.6% 0.10            0.03               ‐10%
Refrigeration Solid Door Refrigerator 26.6% 0.71               0.19                 4                 26.6% 0.64            0.17               ‐10%
Refrigeration Open Display Case 26.6% 0.50               0.13                 3                 26.6% 0.45            0.12               ‐10%
Refrigeration Vending Machine 26.6% 0.38               0.10                 2                 26.6% 0.38            0.10              0%
Refrigeration Icemaker 26.6% 0.31               0.08                 2                 26.6% 0.31            0.08              0%
Office Equipment Desktop Computer 100.0% 0.64               0.64                 12               100.0% 0.64            0.64              0%
Office Equipment Laptop Computer 100.0% 0.07               0.07                 1                 100.0% 0.07            0.07              0%
Office Equipment Server 100.0% 0.17               0.17                 3                 100.0% 0.17            0.17              0%
Office Equipment Monitor 100.0% 0.13               0.13                 2                 100.0% 0.13            0.13              0%
Office Equipment Printer/copier/fax 100.0% 0.05               0.05                 1                 100.0% 0.05            0.05              0%
Office Equipment POS Terminal 100.0% 0.01               0.01                 0                 100.0% 0.01            0.01              0%
Miscellaneous Non‐HVAC Motor 88.8% 0.82               0.73                 14               88.8% 0.82            0.73              0%
Miscellaneous Other Miscellaneous 100.0% 0.80               0.80                 15               100.0% 0.80            0.80              0%
13.90               266            12.9              
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 928 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-10 www.gepllc.com

Table A-11 Extra Large Industrial Segment Market Profile, Washington, 2009

EUI Intensity Usage EUI Intensity
(kWh) (kWh/Sqft.) (GWh)(kWh) (kWh/Sqft.)
Cooling Central Chiller 14.4% 7.98               1.15                 18               14.4% 7.18            1.04               ‐10%
Cooling RTU 17.1% 6.32               1.08                 17               17.1% 5.68            0.97               ‐10%
Cooling PTAC 1.1% 5.50               0.06                 1                 1.1% 4.95            0.05               ‐10%
Combined Heating/Cooling Heat Pump 1.6% 11.13            0.18                 3                 1.6% 10.01          0.16               ‐10%
Space Heating Electric Resistance 10.8% 8.67               0.93                 14               10.8% 8.67            0.93              0%
Space Heating Furnace 2.0% 9.10               0.18                 3                 2.0% 8.19            0.17               ‐10%
Ventilation Ventilation 27.4% 12.31            3.37                 52               27.4% 11.08          3.04               ‐10%
Interior Lighting Interior Screw‐in 100.0% 0.33               0.33                 5                 100.0% 0.30            0.30               ‐10%
Interior Lighting HID 100.0% 1.05               1.05                 16               100.0% 0.94            0.94               ‐10%
Interior Lighting Linear Fluorescent 100.0% 1.10               1.10                 17               100.0% 0.99            0.99               ‐10%
Exterior Lighting Exterior Screw‐in 92.5% 0.02               0.02                 0                 92.5% 0.02            0.02               ‐10%
Exterior Lighting HID 92.5% 0.25               0.23                 4                 92.5% 0.23            0.21               ‐10%
Exterior Lighting Linear Fluorescent 92.5% 0.01               0.01                 0                 92.5% 0.01            0.01               ‐10%
Process Process Cooling/Refrigeration 2.4% 99.67            2.40                 37               2.4%99.67          2.40              0%
Process Process Heating 26.2% 13.74            3.60                 55               26.2% 13.74          3.60              0%
Process Electrochemical Process 2.6% 77.43            2.00                 31               2.6% 77.43          2.00              0%
Machine Drive Less than 5 HP 90.5% 0.92               0.84                 13               90.5% 0.92            0.84              0%
Machine Drive 5‐24 HP 80.1% 2.26               1.81                 28               80.1% 2.26            1.81              0%
Machine Drive 25‐99 HP 72.4% 6.10               4.42                 68               72.4% 6.10            4.42              0%
Machine Drive 100‐249 HP 65.3% 3.84               2.51                 38               65.3%3.84            2.51              0%
Machine Drive 250‐499 HP 23.7% 11.61            2.75                 42               23.7% 11.61          2.75              0%
Machine Drive 500 and more HP 26.1% 19.50            5.08                 78               26.1% 19.50          5.08              0%
Miscellaneous Miscellaneous 100.0% 4.90               4.90                 75               100.0% 4.90            4.90              0%
40.00               614            39.1              
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 929 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-11
An EnerNOC Company

Figure A–1 Residential Baseline Forecast by End Use, Washington

Figure A-2 C&I Baseline Electricity Forecast by End Use, Washington

‐
500,000 
1,000,000 
1,500,000 
2,000,000 
2,500,000 
3,000,000 
3,500,000 
4,000,000 
2009 2012 2017 2022 2027 2032
An
n
u
a
l
 Us
e
 (M
W
h
)
Cooling
Space Heating
Heat & Cool
Water Heating
Appliances
Interior Lighting
Exterior Lighting
Electronics
Miscellaneous
‐
500,000 
1,000,000 
1,500,000 
2,000,000 
2,500,000 
3,000,000 
3,500,000 
4,000,000 
4,500,000 
2009 2012 2017 2022 2027 2032
An
n
u
a
l
 Us
e
 (M
W
h
)
Cooling
Space Heating
Heat & Cool
Ventilation
Water Heating
Food Preparation
Refrigeration
Interior Lighting
Exterior Lighting
Office Equipment
Miscellaneous
Machine Drive
Process
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 930 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-12 www.gepllc.com

Table A-12 Baseline Forecast Summary by Sector, Washington
End Use 2009 2012 2017 2022 2027 2032 
% Change 
('09–'32) 
Avg. Growth 
Rate 
('09–'32) 
Res. WA 2,451,707 2,448,104 2,617,630 2,947,427 3,329,882 3,792,486 54.7%1.9%
C&I WA 2,852,165 2,955,156 3,209,083 3,509,816 3,869,176 4,280,649 50.1%1.8%
Total 5,303,872 5,403,260 5,826,712 6,457,243 7,199,059 8,073,136 52.2%1.8%

Figure A-3 Baseline Forecast Summary by Sector, Washington

‐
1,000,000 
2,000,000 
3,000,000 
4,000,000 
5,000,000 
6,000,000 
7,000,000 
8,000,000 
9,000,000 
An
n
u
a
l
 Us
e
 (M
W
h
)
Residential ‐WA C&I ‐WA
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 931 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-13
An EnerNOC Company
Figure A-4 Summary of Energy Efficiency Potential Savings, Washington, All Sectors

Figure A-5 Energy Efficiency Potential Forecasts, Washington, All Sectors

Realistic Achievable 
Maximum Achievable 
Economic 
Technical 
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2032
En
e
r
g
y
 Sa
v
i
n
g
s

( % of
 Ba
s
e
l
i
n
e

Fo
r
e
c
a
s
t
)
‐
1,000,000 
2,000,000 
3,000,000 
4,000,000 
5,000,000 
6,000,000 
7,000,000 
8,000,000 
9,000,000 
En
e
r
g
y
 Co
n
s
u
m
p
t
i
o
n
 (M
W
h
)
Baseline 
Realistic Achievable 
Maximum Achievable 
Economic 
Technical 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 932 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-14 www.gepllc.com

Table A-13 Summary of Energy Efficiency Potential, Washington, All Sectors
 2012 2017 2022 2027 2032 
Baseline Forecast 
(MWh) 5,403,260 5,826,712 6,457,243 7,199,059 8,073,136 
Baseline Peak 
Demand(MW) 1,170 1,236 1,374 1,531 1,713 
Cumulative Energy Savings (MWh)    
Realistic Achievable 33,146 267,962 616,991 1,007,301 1,411,648 
Maximum Achievable 57,434 679,603 1,258,467 1,598,673 1,869,605 
Economic 156,759 956,924 1,517,670 1,853,199 2,143,779 
Technical 212,980 1,349,814 2,191,746 2,718,118 3,118,733 
Cumulative Energy Savings (% of Baseline)    
Realistic Achievable 0.6% 4.6% 9.6% 14.0% 17.5% 
Maximum Achievable 1.1% 11.7% 19.5% 22.2% 23.2% 
Economic 2.9% 16.4% 23.5% 25.7% 26.6% 
Technical 3.9% 23.2% 33.9% 37.8% 38.6% 
Peak Savings (MW)    
Realistic Achievable 10 57 126 212 298 
Maximum Achievable 15 142 266 339 388 
Economic 41 204 325 394 447 
Technical 53 289 457 565 645 
Peak Savings (% of Baseline)    
Realistic Achievable 0.8% 4.6% 9.2% 13.8% 17.4% 
Maximum Achievable 1.3% 11.5% 19.3% 22.1% 22.6% 
Economic 3.5% 16.5% 23.7% 25.8% 26.1% 
Technical 4.6% 23.4% 33.3% 36.9% 37.6% 
Table A-14 Achievable Cumulative EE Potential by Sector, Washington (MWh)
Segment 2012 2017 2022 2027 2032
Residential, WA 17,413 94,529 238,739 431,973 637,029
C&I, WA 15,733 173,433 378,252 575,328 774,619
Total 33,146 267,962 616,991 1,007,301 1,411,648
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 933 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-15
An EnerNOC Company
Figure A-6 Achievable Cumulative Potential by Sector, Washington

Figure A-7 Residential Energy Efficiency Potential Savings, Washington

Figure A-8 Residential Energy Efficiency Potential Forecast, Washington
0
200,000
400,000
600,000
800,000
1,000,000
1,200,000
1,400,000
1,600,000
2012 2017 2022 2027 2032
C&I, WA
Residential, WASa
v
i
n
g
s
 (M
W
h
)
Realistic Achievable 
Maximum Achievable 
Economic 
Technical 
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2032
En
e
r
g
y
 Sa
v
i
n
g
s
 (%
 of
 Ba
s
e
l
i
n
e

Fo
r
e
c
a
s
t
)
‐
500,000 
1,000,000 
1,500,000 
2,000,000 
2,500,000 
3,000,000 
3,500,000 
4,000,000 
En
e
r
g
y
 Co
n
s
u
m
p
t
i
o
n
 (M
W
h
)
Baseline 
Realistic Achievable
Maximum Achievable
Economic 
Technical 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 934 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-16 www.gepllc.com

Table A-15 Energy Efficiency Potential for the Residential Sector, Washington
 2012 2017 2022 2027 2032 
Baseline Forecast (MWh) 2,448,104 2,617,630 2,947,427 3,329,882 3,792,486 
Baseline Peak Demand 
(MW) 710 736 825 925 1,041 
Cumulative Energy Savings (MWh)    
Realistic achievable 17,413 94,529 238,739 431,973 637,029 
Maximum achievable 24,459 298,135 567,960 730,774 843,186 
Economic 70,743 404,323 687,451 847,003 970,769 
Technical 103,446 626,769 1,005,455 1,250,538 1,446,982 
Cumulative Energy Savings (% of Baseline)    
Realistic Achievable 0.7% 3.6% 8.1% 13.0% 16.8% 
Maximum achievable 1.0% 11.4% 19.3% 21.9% 22.2% 
Economic 2.9% 15.4% 23.3% 25.4% 25.6% 
Technical 4.2%23.9% 34.1% 37.6% 38.2%
Peak Savings (MW)    
Realistic Achievable 7 32 74 133 193 
Maximum achievable 10 87 171 222 251 
Economic 27 124 211 258 290 
Technical 37 187 298 368 422 
Peak Savings (% of Baseline)    
Realistic Achievable 1.0% 4.3% 9.0% 14.4% 18.5% 
Maximum achievable 1.4% 11.9% 20.7% 24.0% 24.1% 
Economic 3.9% 16.8% 25.5% 27.9% 27.8% 
Technical 5.2% 25.4% 36.1% 39.8% 40.5% 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 935 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-17
An EnerNOC Company
Table A-16 Residential Baseline & Realistic Achievable Potential by Segment, WA
 2012 2017 2022 2027 2032
Baseline Forecast (MWh)    
Single Family 1,585,536 1,691,161 1,906,692 2,156,609 2,459,834 
Multi Family 160,305 175,186 199,898 227,929 260,943 
Mobile Home 68,448 72,476 81,311 91,591 104,051 
Limited Income 633,816 678,807 759,527 853,753 967,658 
Total 2,448,104 2,617,630 2,947,427 3,329,882 3,792,486 
Energy Savings, Realistic Achievable Potential (MWh)    
Single Family 12,388 64,350 164,414 291,057 426,412
Multi Family 830 4,691 12,243 24,346 36,864
Mobile Home 520 2,283 4,274 7,827 11,714
Limited Income 3,674 23,204 57,808 108,744 162,039
Total 17,413 94,529 238,739 431,973 637,029
% of Total Residential Energy Savings 
Single Family 71.1% 68.1% 68.9% 67.4% 66.9% 
Multi Family 4.8% 5.0% 5.1% 5.6% 5.8% 
Mobile Home 3.0% 2.4% 1.8% 1.8% 1.8% 
Limited Income 21.1% 24.5% 24.2% 25.2% 25.4% 
Table A-17 Residential Potential by Housing Type, 2022, Washington
Forecast Single 
Family 
Multi 
Family 
Mobile 
Home 
Limited 
Income Total 
Baseline Forecast (MWh) 1,906,692 199,898 81,311 759,527 2,947,427 
Cumulative Energy Savings (MWh) 
Realistic Achievable 164,414 12,243 4,274 57,808 238,739 
Maximum Achievable 386,645 31,832 9,576 139,906 567,960 
Economic Potential  463,459 39,746 11,955 172,291 687,451 
Technical Potential 639,003 61,512 28,913 276,028 1,005,455 
Energy Savings % of Baseline 
Realistic Achievable 8.6% 6.1% 5.3% 7.6% 8.1% 
Maximum Achievable 20.3% 15.9% 11.8% 18.4% 19.3% 
Economic Potential  24.3% 19.9% 14.7% 22.7% 23.3% 
Technical Potential 33.5% 30.8% 35.6% 36.3% 34.1% 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 936 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-18 www.gepllc.com

Table A-18 Residential Cumulative Savings by End Use and Potential Type,
Washington (MWh)
End Use Case 2012 2017 2022 2027 2032 
Cooling 
Realistic Achievable 9 1,659 5,876 15,615 29,687 
Economic 246 15,452 28,210 40,243 54,276 
Technical 2,766 42,662 68,576 97,845 132,886 
Space Heating 
Realistic Achievable 216 12,242 57,209 132,448 215,198 
Economic 6,791 110,158 213,315 282,271 338,227 
Technical 9,175 144,853 273,139 365,838 453,464 
Heat/Cool 
Realistic Achievable  9 595 1,581 4,130 10,179 
Economic 311 8,778 10,272 12,770 18,457 
Technical 2,278 18,977 32,657 45,591 52,056 
Water Heating 
Realistic Achievable 469 18,949 78,476 154,418 239,950 
Economic 9,253 101,513 227,153 297,020 348,485 
Technical 24,475 195,999 366,992 463,545 517,698 
Appliances 
Realistic Achievable 848 8,195 17,794 28,160 39,054 
Economic 3,663 40,418 53,006 56,444 60,723 
Technical 4,768 51,790 69,442 75,057 79,777 
Interior Lighting 
Realistic Achievable 12,389 34,835 44,682 52,336 47,795 
Economic 36,945 71,839 81,146 74,030 56,992 
Technical 43,188 98,598 97,421 91,087 84,570 
Exterior Lighting 
Realistic Achievable  2,156 6,922 7,102 6,615 5,305 
Economic 6,420 14,434 11,588 8,760 6,252 
Technical 7,353 18,822 16,360 14,884 14,685 
Electronics 
Realistic Achievable 1,173 8,913 21,007 29,939 37,810 
Economic 5,909 30,195 44,462 50,005 57,525 
Technical 8,171 43,205 61,954 70,337 81,054 
Miscellaneous 
Realistic Achievable 145 2,218 5,012 8,312 12,051 
Economic 1,205 11,535 18,300 25,461 29,833 
Technical 1,273 11,864 18,916 26,354 30,793 
Total 
Realistic Achievable 17,413 94,529 238,739 431,973 637,029 
Economic 70,743 404,323 687,451 847,003 970,769 
Technical 103,446 626,769 1,005,455 1,250,538 1,446,982 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 937 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-19
An EnerNOC Company
Figure A–9 Residential Achievable Potential by End Use, Selected Years, Washington

Table A-19 Residential Realistic Achievable Potential by End Use and Market Segment,
2022, WA (MWh)
 Single Family Multi Family Mobile 
Home 
Limited 
Income Total 
Cooling  3,239 206 70 2,360 5,876
Space heating 44,225 3,196 506 9,282 57,209
Heat/cool 1,464 10 49 58 1,581
Water heating 44,891 5,834 886 26,864 78,476
Appliances 12,433 426 499 4,436 17,794
Interior lighting 31,573 1,880 1,155 10,074 44,682
Exterior lighting 5,854 99 252 896 7,102
Electronics 16,296 587 685 3,438 21,007
Miscellaneous 4,438 5 171 399 5,012
Total 164,414 12,243 4,274 57,808 238,739

‐100,000 200,000 300,000 400,000 500,000 600,000 700,000 
2012
2017
2022
2027
2032
Cumulative Savings (MWh)
Cooling 
Space heating
Heat/cool
Water heating
Appliances
Int. lighting
Ext. lighting
Electronics
Miscellaneous
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 938 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-20 www.gepllc.com

Table A-20 Residential Cumulative Realistic Achievable Potential by End Use and
Equipment Measures, Washington, Selected Years (MWh)
End Use Technology 2012 2017 2022 
Cooling Central AC ‐100 112
Heat/Cool Air Source Ht. Pump ‐‐ ‐
Water Heating Water Heater 97 726 760
Appliances 
Clothes Washer 54 661 1,664
Clothes Dryer 68 468 858
Dishwasher 75 701 1,709
Refrigerator 293 1,347 2,798
Freezer 220 1,091 2,371
Second Refrigerator 101 490 949
Stove 14 109 245
Interior Lighting 
Screw‐in 11,536 28,508 34,316
Linear Fluorescent 117 1,267 2,373
Pin‐based 735 4,932 7,438
Exterior Lighting 
Screw‐in 2,139 6,837 6,987
High Intensity/Flood 17 85 115
Electronics Personal Computers 758 6,128 10,557
TVs 407 2,139 3,960
Miscellaneous Pool Pump 110 1,022 2,525
Furnace Fan 29 358 1,066
Total 16,770 56,971 80,803

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 939 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-21
An EnerNOC Company
Table A-21 Residential Realistic Achievable Savings for Non-equipment Measures,
Washington (MWh)
Measure 2012 2017 2022 
Water Heater ‐ Convert to Gas 211 8,173 55,933 
Furnace ‐ Convert to Gas 172 5,504 35,051 
Advanced New Construction Designs 1 119 2,781
Repair and Sealing ‐ Ducting 13 1,860 5,347
Insulation ‐ Infiltration Control 14 1,927 5,432
Water Heater ‐ Thermostat Setback 98 5,644 9,489
Home Energy Management System 5 798 2,822
Water Heater ‐ Hot Water Saver 4 296 3,785
Freezer ‐ Remove Second Unit 15 2,142 4,592
Thermostat ‐ Clock/Programmable 15 2,060 5,686
Electronics ‐ Reduce Standby Wattage 8 646 6,490
Insulation ‐ Foundation 1 298 1,351
Air Source Heat Pump ‐ Maintenance 9 595 1,581
Refrigerator ‐ Remove Second Unit 8 1,185 2,608
Water Heater ‐ Faucet Aerators 9 685 1,639
Insulation ‐ Ducting 1 146 836
Insulation ‐ Wall Cavity 0 190 865
Water Heater ‐ Tank Blanket/Insulation 34 1,803 2,812
Room AC ‐ Removal of Second Unit 4 638 1,582
Ceiling Fan ‐ Installation 0 63 576
Water Heater ‐ Timer 8 934 1,676
Insulation ‐ Ceiling 2 285 862
Water Heater ‐ Low Flow Showerheads 6 617 1,233
Water Heater ‐ Heat Pump ‐11 458
Central AC ‐ Maintenance and Tune‐Up ‐ ‐  ‐
Insulation ‐ Wall Sheathing 0 36 172
Pool ‐ Pump Timer 5 838 1,421
Water Heater ‐ Pipe Insulation 1 72 692
Whole‐House Fan ‐ Installation ‐6 166
Total 643 37,558 157,936 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 940 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-22 www.gepllc.com

Figure A-10 Energy Efficiency Potential Savings, C&I Sector, Washington

Figure A-11 Energy Efficiency Potential Forecast, C&I Sector, Washington

Realistic Achievable 
Maximum Achievable 
Economic 
Technical 
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2032
En
e
r
g
y
 Sa
v
i
n
g
s
 ( % of
 Ba
s
e
l
i
n
e
 Fo
r
e
c
a
s
t
)
‐
500,000 
1,000,000 
1,500,000 
2,000,000 
2,500,000 
3,000,000 
3,500,000 
4,000,000 
4,500,000 
En
e
r
g
y
 Co
n
s
u
m
p
t
i
o
n
 (M
W
h
)
Baseline 
Realistic Achievable 
Maximum Achievable 
Economic 
Technical 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 941 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-23
An EnerNOC Company
Table A-22 Energy Efficiency Potential, C&I Sector, Washington
 2012 2017 2022 2027 2032
Baseline Forecast (MWh) 2,955,156 3,209,083 3,509,816 3,869,176 4,280,649 
Baseline Peak 
Demand(MW) 460 500 549 607 671 
Cumulative Energy Savings (MWh)  
Realistic Achievable 15,733 173,433 378,252 575,328 774,619
Maximum Achievable   32,975 381,468 690,507 867,899 1,026,419
Economic 86,016 552,602 830,218 1,006,195 1,173,010
Technical 109,533 723,045 1,186,290 1,467,580 1,671,750
Cumulative Energy Savings (% of Baseline) 
Realistic Achievable 0.5% 5.4%10.8% 14.9% 18.1%
Maximum Achievable   1.1%11.9% 19.7% 22.4% 24.0%
Economic 2.9%17.2% 23.7% 26.0% 27.4%
Technical 3.7%22.5% 33.8% 37.9% 39.1%
Peak Savings (MW)  
Realistic Achievable 2 25 52 79 105
Maximum Achievable   5 55 95 117 137
Economic 13 80 114 137 157
Technical 17 102 159 197 223
Peak Savings (% of Baseline)  
Realistic Achievable 0.5% 5.1% 9.5%13.0% 15.7%
Maximum Achievable   1.1%11.0% 17.2% 19.4% 20.4%
Economic 2.9%15.9% 20.8% 22.6% 23.4%
Technical 3.6%20.4% 28.9% 32.5% 33.2%

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 942 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-24 www.gepllc.com

Table A-23 C&I Sector, Baseline and Realistic Achievable Potential by Segment,
Washington
 2012 2017 2022 2027 2032 
Baseline Forecast (MWh)    
Small/Med. Commercial  413,131 436,628 470,488 512,594 560,964 
Large Commercial  1,558,848 1,641,938 1,770,523 1,927,937 2,109,236 
Extra Large Commercial  275,848 338,184 367,338 399,653 434,542 
Extra Large Industrial  707,328 792,332 901,468 1,028,993 1,175,907 
Total  2,955,156 3,209,083 3,509,816 3,869,176 4,280,649 
Cumulative Energy Savings, Achievable Potential (MWh)    
Small/Med. Commercial  2,551 25,567 52,366 79,356 108,891 
Large Commercial  10,092 112,528 231,487 335,497 435,628 
Extra Large Commercial  2,607 27,021 56,555 85,997 112,469 
Extra Large Industrial  483 8,317 37,844 74,477 117,630 
Total  15,733 173,433 378,252 575,328 774,619 
% of Total C&I Cumulative Energy Savings 
Small/Med. Commercial  16.2% 14.7% 13.8% 13.8% 14.1% 
Large Commercial  64.1% 64.9% 61.2% 58.3% 56.2% 
Extra Large Commercial  16.6% 15.6% 15.0% 14.9% 14.5% 
Extra Large Industrial  3.1% 4.8% 10.0% 12.9% 15.2% 

Table A-24 C&I Potential by Segment, Washington, 2022
Forecast Small/Med.
Commercial 
Large 
Commercial 
Extra Large 
Commercial 
Extra Large 
Industrial Total 
Baseline Forecast (MWh) 470,488 1,770,523 367,338 901,468 3,509,816 
Cumulative Energy Savings (MWh) 
Realistic Achievable 52,366 231,487 56,555 37,844 378,252 
Economic Potential  106,676 441,853 118,311 163,378 830,218 
Technical Potential 172,714 650,066 148,095 215,416 1,186,290 
Cumulative Energy Savings % of Baseline
Realistic Achievable 11% 13% 15% 4% 11% 
Economic Potential  23% 25% 32% 18% 24% 
Technical Potential 37% 37% 40% 24% 34% 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 943 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-25
An EnerNOC Company
Table A-25 C&I Cumulative Savings by End Use and Potential Type, Washington
(MWh)
End Use Case 2012 2017 2022 2027 2032 
Cooling 
Realistic Achievable 127 8,672 29,166 48,498 72,425 
Economic 1,709 30,259 62,983 86,699 116,136 
Technical 4,457 60,126 124,114 157,093 189,090 
Space Heating 
Realistic Achievable 10 1,427 7,180 14,045 23,624 
Economic 212 7,563 19,650 28,833 42,274 
Technical 356 11,555 32,534 45,033 60,186 
Heat/Cool 
Realistic Achievable 31 2,494 4,572 5,575 6,982 
Economic 357 5,927 7,558 8,984 10,138 
Technical 483 6,778 9,118 11,073 12,505 
Ventilation 
Realistic Achievable 246 4,256 20,112 40,397 69,089 
Economic 4,017 29,775 75,187 107,501 130,189 
Technical 6,107 47,417 127,261 172,058 190,303 
Water Heating 
Realistic Achievable 181 4,769 10,742 16,921 23,513 
Economic 1,709 15,526 22,956 29,467 31,482 
Technical 8,806 63,741 116,091 166,541 183,186 
Food 
Preparation 
Realistic Achievable 140 1,796 5,159 9,950 14,898 
Economic 1,863 11,976 21,990 26,511 28,922 
Technical 2,173 13,179 24,316 29,162 31,947 
Refrigeration 
Realistic Achievable 123 1,246 4,138 7,959 11,717 
Economic 1,843 8,978 17,215 22,233 24,920 
Technical 2,183 11,986 26,785 34,794 39,418 
Interior Lighting 
Realistic Achievable 11,768 111,221 218,748 316,260 394,891 
Economic 50,511 299,598 396,845 456,682 523,557 
Technical 55,416 327,215 442,057 510,066 581,362 
Exterior Lighting 
Realistic Achievable 1,108 15,661 30,450 38,068 45,433 
Economic 4,693 44,035 50,942 53,236 56,711 
Technical 5,191 48,166 57,089 64,537 72,708 
Office 
Equipment 
Realistic Achievable 1,779 18,258 30,020 39,448 49,199 
Economic 12,800 58,446 61,458 64,159 66,791 
Technical 17,214 80,539 85,590 90,712 96,009 
Machine Drive 
Realistic Achievable 199 2,492 8,718 15,739 23,806 
Economic 2,252 17,069 40,392 50,946 58,527 
Technical 2,653 26,498 84,466 111,180 128,005 
Process 
Realistic Achievable 17 999 8,473 20,545 35,763 
Economic 3,980 22,472 50,483 66,505 77,283 
Technical 3,980 22,472 50,483 66,505 77,283 
Miscellaneous 
Realistic Achievable 5 142 775 1,924 3,280 
Economic 70 977 2,561 4,439 6,080 
Technical 514 3,373 6,388 8,826 9,749 
Total 
Realistic Achievable 15,733 173,433 378,252 575,328 774,619 
Economic 86,016 552,602 830,218 1,006,195 1,173,010 
Technical 109,533 723,045 1,186,290 1,467,580 1,671,750 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 944 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-26 www.gepllc.com

Figure A-12 C&I Achievable Potential by End Use, Selected Years, Washington

Table A-26 C&I Realistic Achievable Potential by End Use and Market Segment, 2022,
Washington (MWh)
 Small/Med. 
Commercial 
Large 
Commercial 
Extra Large 
Commercial 
Extra Large 
Industrial Total 
Cooling 1,017 17,942 4,119 6,087 29,166
Space Heating 440 4,617 1,216 906 7,180
Combined 
Heating/Cooling 323 3,597 464 188 4,572 
Ventilation 4,268 3,818 4,496 7,530 20,112
Water Heating 1,238 3,974 5,530 ‐ 10,742
Food Preparation 700 3,815 644 ‐ 5,159
Refrigeration 741 3,001 396 ‐ 4,138
Interior Lighting 33,054 149,244 30,943 5,507 218,748
Exterior Lighting 5,854 18,916 5,246 434 30,450
Office Equipment 4,529 22,130 3,362 ‐ 30,020
Machine Drive  ‐  ‐ ‐8,718 8,718
Process  ‐  ‐ ‐8,473 8,473
Miscellaneous 202 432 141 ‐ 775
Total 52,366 231,487 56,555 37,844 378,252

‐100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 
2012
2017
2022
2027
2032
Cooling
Space Heating
Heat/cool
Ventilation
Water Heating
Food Preparation
Refrigeration
Interior Lighting
Exterior Lighting
Office Equipment
Miscellaneous
Machine Drive
Process
Cumulative Savings(MWh)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 945 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-27
An EnerNOC Company
Table A-27 C&I Cumulative Achievable Potential by End Use and Equipment Measures,
Washington (MWh)
End Use Technology 2012 2017 2022 
Cooling Central Chiller 53 551 2,062 
PTAC 4 4 4 
Heat/Cool Heat Pump 14 263 795 
Ventilation Ventilation 235 3,625 13,529 
Water Heater Water Heater 160 1,908 4,354 
Food Preparation  
Fryer 9 101 271 
Hot Food Container 5 172 488 
Oven 127 1,495 3,996 
Refrigeration 
Glass Door Display 21 279 808 
Icemaker 16 216 644 
Solid Door Refrigerator 29 332 893 
Vending Machine 55 303 740 
Walk in Refrigeration 21 279 808 
Interior Lighting 
Interior Screw‐in 6,957 45,558 69,399 
HID 1,823 16,436 32,323 
Linear Fluorescent 2,869 35,193 69,229 
Exterior Lighting 
Screw‐in 154 2,018 3,288 
HID 864 10,866 21,367 
Linear Fluorescent 82 1,472 2,497 
Office Equipment 
Desktop Computer 1,056 9,794 15,665 
Laptop Computer 75 700 1,119 
Monitor 211 757 1,307 
POS Terminal 23 318 580 
Printer/copier/fax 66 1,061 1,963 
Server 342 4,823 7,781 
Machine Drive 
Less than 5 HP 13 92 280 
5‐24 HP 28 208 649 
25‐99 HP 69 518 1,616 
100‐249 HP 19 146 455 
250‐499 HP 21 155 484 
500 and more HP 39 292 913 
Process 
Electrochem. Process 2 138 1,150 
Process Cooling/Refrig. 3 185 1,538 
Process Heating 11 658 5,482 
Miscellaneous Non‐HVAC Motor 4 70 339 
Total 15,460 140,725 268,060 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 946 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results

A-28 www.gepllc.com

Table A-28 C&I Cumulative Achievable Savings for Non-equipment Measures,
Washington (MWh)
Measure 2012 2017 2022 
Energy Management System 25 1,553 16,501 
Advanced New Construction Designs 1 70 1,070 
Retrocommissioning ‐ Lighting 37 7,653 14,120 
Interior Fluorescent ‐ High Bay Fixtures 13 787 8,430 
Retrocommissioning ‐ Comprehensive 29 6,096 10,951 
Custom Measures 2 533 7,173 
RTU ‐ Maintenance 39 4,686 8,093 
Fans ‐ Variable Speed Control 5 218 2,179 
Fans ‐ Energy Efficient Motors 5 304 3,318 
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts 0 39 342 
Interior Lighting ‐ Occupancy Sensors 13 477 3,666 
Interior Fluorescent ‐ Delamp and Install Reflectors 12 506 3,807 
Water Heater ‐ Faucet Aerators/Low Flow Nozzles 18 2,657 5,409 
Commissioning ‐ Comprehensive 0 245 1,809 
Retrocommissioning ‐ HVAC 2 258 2,720 
Heat Pump ‐ Maintenance 17 2,231 3,777 
Motors ‐ Variable Frequency Drive 7 883 1,911 
Motors ‐ Magnetic Adjustable Speed Drives 3 146 1,535 
Roofs ‐ High Reflectivity 1 33 262 
Chiller ‐ Turbocor Compressor 2 109 1,244 
Chiller ‐ Condenser Water Temperature Reset 4 222 2,148 
Chiller ‐ VSD 1 81 859 
Commissioning ‐ Lighting 0 155 528 
Thermostat ‐ Clock/Programmable 3 458 904 
Office Equipment ‐ ENERGY STAR Power Supply 6 806 1,605 
Exterior Lighting ‐ Daylighting Controls 2 92 747 
Water Heater ‐ Heat Pump 0 54 659 
Cooking ‐ Exhaust Hoods with Sensor Control 0 8 71 
Cooling ‐ Economizer Installation 2 83 760 
Insulation ‐ Ducting 1 53 443 
Exterior Lighting ‐ Induction Lamps 0 20 290 
Furnace ‐ Convert to Gas 1 45 297 
Chiller ‐ Chilled Water Reset 1 242 437 
Insulation ‐ Wall Cavity 0 10 146 
Insulation ‐ Ceiling 0 1 17 
Refrigeration ‐ System Optimization 0 10 159 
LED Exit Lighting 17 613 670 
Industrial Process Improvements 0 17 205 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 947 of 1069
Washington Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners A-29
An EnerNOC Company
Measure 2012 2017 2022 
Refrigeration ‐ System Controls 0 7 112 
Commissioning ‐ HVAC  ‐ ‐ 16 
Water Heater ‐ Tank Blanket/Insulation 2 144 254 
Pumps ‐ Variable Speed Control 0 9 106 
Miscellaneous ‐ ENERGY STAR Water Cooler 0 40 115 
Refrigeration ‐ Strip Curtain  ‐ 1 20 
Refrigeration ‐ Floating Head Pressure 0 6 59 
Water Heater ‐ Hot Water Saver  ‐ ‐ 2 
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer 0 4 46 
Refrigeration ‐ System Maintenance 0 2 32 
Water Heater ‐ High Efficiency Circulation Pump 0 6 64 
Vending Machine ‐ Controller 0 26 44 
Chiller ‐ Chilled Water Variable‐Flow System 0 4 32 
Exterior Lighting ‐ Cold Cathode Lighting 0 1 16 
Laundry ‐ High Efficiency Clothes Washer 0 6 10 
Refrigeration ‐ Night Covers 0 0 5 
Total 273 32,708 110,192 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 948 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 949 of 1069

Global Energy Partners B-1
An EnerNOC Company
APPENDIX B
IDAHO MARKET PROFILES, BASELINE FORECAST, AND POTENTIAL
RESULTS
This appendix contains Idaho-specific tables that summarize the study assumptions, inputs, and
results for Avista’s Idaho service territory only. These tables either repeat Idaho-specific
information provided previously within the body of the report, or provide Idaho-specific
information that corresponds to Avista system-level information in the report.
Table B–1 Electricity Use and Peak Demand by Rate Class, Idaho 2009
Sector 
Rate 
Schedule(s) 
Number of meters 
(customers) 
2009 Electricity 
sales (MWh) 
Peak demand 
(MW) 
Residential 001 99,580 1,182,368 283
General Service 011, 012 19,245 322,570 61
Large General Service 021, 022 1,456 699,953 115
Extra Large General Service 025, 025P 10 266,044 40
Extra Large GS Potlatch 025P 1 892 101
Pumping 031, 032 1,312 58,885 4
Total   121,604 3,422,111 603

Table B–2 Residential Electricity Usage and Intensity by Segment, Idaho 2009
Idaho 
Segment 
Intensity   
(kWh/Household) 
Number of  
Customers 
% of 
Customers 
2009 Electricity 
Sales (MWh) % of Sales 
Single Family 13,703 59,205 59% 811,302 69% 
Multi‐Family 8,213 5,237 5% 43,013 4% 
Mobile Home 12,320 4,774 5% 58,815 5% 
Limited Income 8,868 30,363 31% 269,249 23% 
Total 11,874 99,580 100% 1,182,379 100% 
Note: Minor differences with totals in Table B–1 due to calibration.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 950 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-2 www.gepllc.com

Table B–3 Single Family Market Profile, 2009, Idaho

UEC Intensity Usage UEC Intensity
(kWh) (kWh/HH) (GWh)(kWh) (kWh/HH)
Cooling Central AC 36.8% 1,857            684                  41               73.4% 2,154          1,581            16%
Cooling Room AC 10.8% 683                74                     4                 1.4% 793             11                  16%
Combined Heating/Cooling Air Source Heat Pump 14.7% 6,377            940                  56               13.6% 7,398          1,004            16%
Combined Heating/Cooling Geothermal Heat Pump 0.7% 3,826            27                     2                 0.8% 4,439          33                  16%
Space Heating Electric Resistance 5.0% 11,494          570                  34               2.5% 13,793       342                20%
Space Heating Electric Furnace 20.0% 9,195            1,837               109            21.0% 11,035       2,315            20%
Space Heating Supplemental 6.1% 128                8                       0                 6.1% 154             9                    20%
Water Heating Water Heater 44.4% 3,813            1,694               100            37.8% 4,595          1,736            21%
Interior Lighting Screw‐in 100.0% 1,394            1,394               83               100.0% 1,394          1,394            0%
Interior Lighting Linear Fluorescent 69.2% 146                101                  6                 69.2% 146             101                0%
Interior Lighting Pin‐based 100.0% 58                  58                     3                 100.0% 58                58                  0%
Exterior Lighting Screw‐in 86.7% 366                317                  19               86.7% 366             317                0%
Exterior Lighting High Intensity/Flood 1.9% 140                3                       0                 1.9% 140             3                    0%
Appliances Clothes Washer 98.0% 126                124                  7                 99.8% 154             154                22%
Appliances Clothes Dryer 92.8% 609                565                  33               89.0% 692             616                14%
Appliances Dishwasher 93.9% 246                231                  14               99.9% 271             271                11%
Appliances Refrigerator 100.0% 793                793                  47               100.0% 625             625                 ‐21%
Appliances Freezer 69.4% 773                536                  32               69.4% 708             491                 ‐8%
Appliances Second Refrigerator 47.3% 816                386                  23               20.5% 711             146                 ‐13%
Appliances Stove 82.1% 383                314                  19               82.1% 465             382                22%
Appliances Microwave 98.5% 168                166                  10               98.5%173             171                3%
Electronics Personal Computers 140.0% 279                391                  23               147.0% 287             422                3%
Electronics TVs 260.0% 359                933                  55               260.0% 400             1,041            12%
Electronics Devices and Gadgets 100.0% 60                  60                     4                 100.0% 67                67                  10%
Miscellaneous Pool Pump 13.3% 1,500            200                  12               14.0% 1,526          214                2%
Miscellaneous Furnace Fan 30.1% 550                166                  10               30.1% 675             203                23%
Miscellaneous Miscellaneous 100.0% 1,132            1,132               67               100.0% 1,359          1,359            20%
13,703            811            15,063          
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 951 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-3
An EnerNOC Company
Table B–4 Multi-family Market Profile, 2009, Idaho

UEC Intensity Usage UEC Intensity
(kWh) (kWh/HH) (GWh)(kWh) (kWh/HH)
Cooling Central AC 5.0% 845                42                     0                 24.1% 912             220                8%
Cooling Room AC 25.0% 324                81                     0                 18.9% 350             66                  8%
Combined Heating/Cooling Air Source Heat Pump 1.0% 2,665            27                     0                 3.4% 2,878          98                  8%
Combined Heating/Cooling Geothermal Heat Pump 0.0% 1,599            ‐                    ‐             0.5% 1,727          9                    8%
Space Heating Electric Resistance 59.0% 4,983            2,940               15               59.0% 5,481          3,234            10%
Space Heating Electric Furnace 5.0% 3,986            199                  1                 5.0% 4,385          219                10%
Space Heating Supplemental 18.0% 56                  10                     0                 18.9% 61                12                  10%
Water Heating Water Heater 77.0% 1,936            1,491               8                 71.3% 2,134          1,522            10%
Interior Lighting Screw‐in 100.0% 750                750                  4                 100.0% 750             750                0%
Interior Lighting Linear Fluorescent 32.0% 76                  24                     0                 32.0% 76                24                  0%
Interior Lighting Pin‐based 3.0% 75                  2                       0                 3.0% 75                2                    0%
Exterior Lighting Screw‐in 38.5% 55                  21                     0                 38.5% 55                21                  0%
Exterior Lighting High Intensity/Flood 0.2% 73                  0                       0                 0.2%73                0                    0%
Appliances Clothes Washer 32.0% 63                  20                     0                 32.0% 70                22                  11%
Appliances Clothes Dryer 30.7% 582                179                  1                 30.7% 621             191                7%
Appliances Dishwasher 64.0% 88                  56                     0                 64.0% 93                59                  5%
Appliances Refrigerator 100.0% 677                677                  4                 100.0% 665             665                 ‐2%
Appliances Freezer 8.4% 734                62                     0                 8.4% 703             59                   ‐4%
Appliances Second Refrigerator 5.0% 687                34                     0                 5.0% 631             32                   ‐8%
Appliances Stove 96.4% 163                158                  1                 96.4% 181             175                11%
Appliances Microwave 90.0% 99                  89                     0                 90.0% 101             91                  1%
Electronics Personal Computers 63.0% 223                141                  1                 66.2% 226             150                1%
Electronics TVs 165.0% 178                293                  2                 165.0% 188             310                6%
Electronics Devices and Gadgets 100.0% 25                  25                     0                 100.0% 26                26                  5%
Miscellaneous Pool Pump 0.0%‐                 ‐                    ‐             0.0%‐              ‐                0%
Miscellaneous Furnace Fan 13.0% 38                  5                       0                 13.0% 42                5                    11%
Miscellaneous Miscellaneous 100.0% 888                888                  5                 100.0% 932             932                5%
8,213               43               8,893            
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 952 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-4 www.gepllc.com

Table B–5 Mobile Home Market Profile, 2009, Idaho

UEC Intensity Usage UEC Intensity
(kWh) (kWh/HH) (GWh)(kWh) (kWh/HH)
Cooling Central AC 23.2% 962                223                  1                 35.9% 1,039          373                8%
Cooling Room AC 23.2% 354                82                     0                 22.0% 382             84                  8%
Combined Heating/Cooling Air Source Heat Pump 21.7% 3,035            660                  3                 22.8% 3,277          748                8%
Combined Heating/Cooling Geothermal Heat Pump 0.0% 1,821            ‐                    ‐             0.0% 1,966          ‐                8%
Space Heating Electric Resistance 0.0% 5,122            ‐                    ‐             0.0% 5,634          ‐                10%
Space Heating Electric Furnace 68.1% 4,098            2,792               13               68.1% 4,508          3,071            10%
Space Heating Supplemental 1.4% 30                  0                       0                 1.5% 33                0                    10%
Water Heating Water Heater 96.3% 1,607            1,549               7                 91.0% 1,772          1,612            10%
Interior Lighting Screw‐in 100.0% 1,307            1,307               6                 100.0% 1,307          1,307            0%
Interior Lighting Linear Fluorescent 69.2% 137                95                     0                 69.2% 137             95                  0%
Interior Lighting Pin‐based 100.0% 54                  54                     0                 100.0% 54                54                  0%
Exterior Lighting Screw‐in 86.7% 343                297                  1                 86.7% 343             297                0%
Exterior Lighting High Intensity/Flood 1.9% 131                2                       0                 1.9% 131             2                    0%
Appliances Clothes Washer 96.3% 128                124                  1                 96.3% 142             137                11%
Appliances Clothes Dryer 98.8% 620                612                  3                 98.8% 662             653                7%
Appliances Dishwasher 89.0% 250                222                  1                 89.0% 263             234                5%
Appliances Refrigerator 100.0% 806                806                  4                 100.0% 792             792                 ‐2%
Appliances Freezer 59.3% 786                466                  2                 59.3% 753             446                 ‐4%
Appliances Second Refrigerator 19.5% 830                162                  1                 19.5% 762             149                 ‐8%
Appliances Stove 93.9% 344                323                  2                 93.9% 381             358                11%
Appliances Microwave 82.0% 151                124                  1                 82.0%154             126                2%
Electronics Personal Computers 116.5% 262                305                  1                 122.3% 265             324                1%
Electronics TVs 260.0% 359                933                  4                 260.0% 380             987                6%
Electronics Devices and Gadgets 100.0% 60                  60                     0                 100.0% 64                64                  5%
Miscellaneous Pool Pump 11.1% 1,500            167                  1                 11.7% 1,513          177                1%
Miscellaneous Furnace Fan 8.3% 500                42                     0                 8.3% 557             47                  11%
Miscellaneous Miscellaneous 100.0% 913                913                  4                 100.0% 959             959                5%
12,320            59               13,096          
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 953 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-5
An EnerNOC Company
Table B–6 Limited Income Market Profile, 2009, Idaho

UEC Intensity Usage UEC Intensity
(kWh) (kWh/HH) (GWh)(kWh) (kWh/HH)
Cooling Central AC 22.2% 944                210                  6                 28.7% 1,019          293                8%
Cooling Room AC 35.4% 641                227                  7                 18.0% 692             124                8%
Combined Heating/Cooling Air Source Heat Pump 10.4% 2,134            222                  7                 10.4% 2,305          240                8%
Combined Heating/Cooling Geothermal Heat Pump 0.0% 1,281            ‐                    ‐             0.5% 1,383          7                    8%
Space Heating Electric Resistance 32.0% 4,647            1,486               45               28.8% 5,112          1,471            10%
Space Heating Electric Furnace 19.3% 3,711            716                  22               21.2% 4,082          867                10%
Space Heating Supplemental 12.7% 57                  7                       0                 13.4% 62                8                    10%
Water Heating Water Heater 83.9% 2,101            1,762               54               67.0% 2,316          1,552            10%
Interior Lighting Screw‐in 100.0% 728                728                  22               100.0% 728             728                0%
Interior Lighting Linear Fluorescent 69.2% 75                  52                     2                 69.2% 75                52                  0%
Interior Lighting Pin‐based 100.0% 59                  59                     2                 100.0% 59                59                  0%
Exterior Lighting Screw‐in 47.1% 106                50                     2                 47.1% 106             50                  0%
Exterior Lighting High Intensity/Flood 2.7% 84                  2                       0                 2.7%84                2                    0%
Appliances Clothes Washer 71.3% 55                  39                     1                 71.3% 61                43                  11%
Appliances Clothes Dryer 68.6% 652                447                  14               68.6% 696             477                7%
Appliances Dishwasher 78.5% 72                  56                     2                 78.5% 75                59                  5%
Appliances Refrigerator 100.0% 677                677                  21               100.0% 665             665                 ‐2%
Appliances Freezer 63.4% 734                466                  14               63.4% 703             446                 ‐4%
Appliances Second Refrigerator 23.4% 687                161                  5                 23.4% 631             148                 ‐8%
Appliances Stove 89.7% 196                176                  5                 89.7% 217             195                11%
Appliances Microwave 92.6% 109                101                  3                 92.6% 111             102                1%
Electronics Personal Computers 101.4% 230                233                  7                 106.5% 233             248                1%
Electronics TVs 165.0% 204                337                  10               165.0% 216             356                6%
Electronics Devices and Gadgets 100.0% 30                  30                     1                 105.0% 32                33                  5%
Miscellaneous Pool Pump 5.8% 617                36                     1                 5.8% 622             36                  1%
Miscellaneous Furnace Fan 25.2% 213                54                     2                 25.2% 238             60                  11%
Miscellaneous Miscellaneous 100.0% 534                534                  16               100.0% 561             561                5%
8,868               269            8,884            
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 954 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-6 www.gepllc.com

Table B–7 Commercial Sector Market Characterization Results, Idaho 2009
Avista Rate Schedule LoadMAP Segment and Typical 
Building 
Electricity 
sales (MWh) 
Intensity 
(kWh/sq.ft.) 
General Service  011, 012 Small and Medium Commercial —Retail 322,570 17.5
Large General Service  021, 022 Large Commercial —Office 699,953 16.7
Extra Large General 
Service Commercial  
025C Extra Large Commercial —University 70,361 13.9
Extra Large General 
Service Industrial  
025I, 025P Extra Large Industrial 1,087,974 40.0
Total   2,180,858 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 955 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-7
An EnerNOC Company
Table B–8 Small/Medium Commercial Segment Market Profile, Idaho, 2009

EUI Intensity Usage EUI Intensity
(kWh) (kWh/Sqft.) (GWh)(kWh) (kWh/Sqft.)
Cooling Central Chiller 13.8% 2.39               0.33                 6                 13.8% 2.15            0.30               ‐10%
Cooling RTU 63.1% 2.46               1.55                 29               63.1% 2.22            1.40               ‐10%
Cooling PTAC 3.3% 2.44               0.08                 1                 3.3% 2.20            0.07               ‐10%
Combined Heating/Cooling Heat Pump 3.6% 6.19               0.22                 4                 3.6% 5.57            0.20               ‐10%
Space Heating Electric Resistance 5.9% 6.72               0.39                 7                 5.9% 6.72            0.39              0%
Space Heating Furnace 17.7% 7.05               1.25                 23               17.7% 6.34            1.13               ‐10%
Ventilation Ventilation 76.9% 2.09               1.61                 30               76.9% 1.88            1.45               ‐10%
Interior Lighting Interior Screw‐in 100.0%1.00               1.00                 18               100.0% 0.90            0.90               ‐10%
Interior Lighting HID 100.0% 0.68               0.68                 13               100.0% 0.61            0.61               ‐10%
Interior Lighting Linear Fluorescent 100.0% 3.37               3.37                 62               100.0% 3.03            3.03               ‐10%
Exterior Lighting Exterior Screw‐in 82.6% 0.20               0.16                 3                 82.6% 0.18            0.15               ‐10%
Exterior Lighting HID 82.6% 0.76               0.63                 12               82.6% 0.68            0.56               ‐10%
Exterior Lighting Linear Fluorescent 82.6% 0.16               0.13                 2                 82.6% 0.14            0.12               ‐10%
Water Heating Water Heater 63.0% 2.00               1.26                 23               63.0% 1.90            1.19              ‐5%
Food Preparation Fryer 25.8% 0.16               0.04                 1                 25.8% 0.16            0.04              0%
Food Preparation Oven 25.8% 0.98               0.25                 5                 25.8% 0.98            0.25              0%
Food Preparation Dishwasher 25.8% 0.06               0.01                 0                 25.8% 0.06            0.01              0%
Food Preparation Hot Food Container 25.8% 0.31               0.08                 1                 25.8% 0.31            0.08              0%
Food Preparation Food Prep 25.8% 0.01               0.00                 0                 25.8% 0.01            0.00              0%
Refrigeration Walk in Refrigeration 52.4%‐                 ‐                    ‐             52.4%‐              ‐                0%
Refrigeration Glass Door Display 52.4% 0.45               0.23                 4                 52.4% 0.40            0.21               ‐10%
Refrigeration Solid Door Refrigerator 52.4% 0.50               0.26                 5                 52.4% 0.45            0.24               ‐10%
Refrigeration Open Display Case 52.4% 0.04               0.02                 0                 52.4% 0.04            0.02               ‐10%
Refrigeration Vending Machine 52.4% 0.30               0.16                 3                 52.4% 0.30            0.16              0%
Refrigeration Icemaker 52.4% 0.34               0.18                 3                 52.4% 0.34            0.18              0%
Office Equipment Desktop Computer 99.9% 0.48               0.48                 9                 99.9% 0.48            0.48              0%
Office Equipment Laptop Computer 99.9% 0.06               0.06                 1                 99.9% 0.06            0.06              0%
Office Equipment Server 99.9% 0.36               0.36                 7                 99.9% 0.36            0.36              0%
Office Equipment Monitor 99.9% 0.25               0.25                 5                 99.9% 0.25            0.25              0%
Office Equipment Printer/copier/fax 99.9% 0.24               0.24                 4                 99.9% 0.24            0.24              0%
Office Equipment POS Terminal 99.9% 0.27               0.27                 5                 99.9% 0.27            0.27              0%
Miscellaneous Non‐HVAC Motor 40.2% 1.22               0.49                 9                 40.2% 1.22            0.49              0%
Miscellaneous Other Miscellaneous 100.0% 1.43               1.43                 26               100.0% 1.43            1.43              0%
17.50               323            16.3              
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 956 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-8 www.gepllc.com

Table B–9 Large Commercial Segment Market Profile, Idaho, 2009

EUI Intensity Usage EUI Intensity
(kWh) (kWh/Sqft.) (GWh)(kWh) (kWh/Sqft.)
Cooling Central Chiller 24.7% 2.15               0.53                 22               24.7% 1.93            0.48               ‐10%
Cooling RTU 37.8% 2.52               0.95                 40               37.8% 2.26            0.86               ‐10%
Cooling PTAC 3.8% 2.49               0.09                 4                 3.8% 2.24            0.08               ‐10%
Combined Heating/Cooling Heat Pump 9.1% 4.81               0.44                 18               9.1% 4.33            0.40               ‐10%
Space Heating Electric Resistance 5.9% 3.62               0.21                 9                 5.9% 3.62            0.21              0%
Space Heating Furnace 12.7% 4.68               0.60                 25               12.7% 4.21            0.54               ‐10%
Ventilation Ventilation 75.1% 1.66               1.24                 52               75.1% 1.49            1.12               ‐10%
Interior Lighting Interior Screw‐in 100.0%0.94               0.94                 39               100.0% 0.85            0.85               ‐10%
Interior Lighting HID 100.0% 0.71               0.71                 30               100.0% 0.64            0.64               ‐10%
Interior Lighting Linear Fluorescent 100.0% 3.29               3.29                 138            100.0% 2.96            2.96               ‐10%
Exterior Lighting Exterior Screw‐in 89.6% 0.11               0.10                 4                 89.6% 0.10            0.09               ‐10%
Exterior Lighting HID 89.6% 0.62               0.56                 23               89.6% 0.56            0.50               ‐10%
Exterior Lighting Linear Fluorescent 89.6% 0.16               0.14                 6                 89.6% 0.14            0.13               ‐10%
Water Heating Water Heater 54.2% 2.31               1.25                 53               54.2%2.20            1.19              ‐5%
Food Preparation Fryer 18.4% 0.35               0.06                 3                 18.4% 0.35            0.06              0%
Food Preparation Oven 18.4% 1.88               0.35                 14               18.4% 1.88            0.35              0%
Food Preparation Dishwasher 18.4% 0.19               0.03                 1                 18.4% 0.19            0.03              0%
Food Preparation Hot Food Container 18.4% 0.27               0.05                 2                 18.4% 0.27            0.05              0%
Food Preparation Food Prep 18.4% 0.02               0.00                 0                 18.4% 0.02            0.00              0%
Refrigeration Walk in Refrigeration 39.1% 0.48               0.19                 8                 39.1% 0.43            0.17               ‐10%
Refrigeration Glass Door Display 39.1%0.37               0.14                 6                 39.1% 0.33            0.13               ‐10%
Refrigeration Solid Door Refrigerator 39.1% 0.77               0.30                 13               39.1% 0.69            0.27               ‐10%
Refrigeration Open Display Case 39.1% 0.27               0.10                 4                 39.1% 0.24            0.09               ‐10%
Refrigeration Vending Machine 39.1% 0.36               0.14                 6                 39.1% 0.36            0.14              0%
Refrigeration Icemaker 39.1% 0.66               0.26                 11               39.1% 0.66            0.26              0%
Office Equipment Desktop Computer 98.4% 0.90               0.88                 37               98.4% 0.90            0.88              0%
Office Equipment Laptop Computer 98.4% 0.07               0.07                 3                 98.4% 0.07            0.07              0%
Office Equipment Server 98.4% 0.42               0.41                 17               98.4% 0.42            0.41              0%
Office Equipment Monitor 98.4% 0.21               0.20                 9                 98.4% 0.21            0.20              0%
Office Equipment Printer/copier/fax 98.4% 0.21               0.21                 9                 98.4% 0.21            0.21              0%
Office Equipment POS Terminal 98.4% 0.07               0.07                 3                 98.4% 0.07            0.07              0%
Miscellaneous Non‐HVAC Motor 57.7% 1.40               0.81                 34               57.7% 1.40            0.81              0%
Miscellaneous Other Miscellaneous 100.0% 1.36               1.36                 57               100.0% 1.36            1.36              0%
16.70               700            15.6              
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 957 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-9
An EnerNOC Company
Table B–10 Extra Large Commercial Segment Market Profile, Idaho, 2009

EUI Intensity Usage EUI Intensity
(kWh) (kWh/Sqft.) (GWh)(kWh) (kWh/Sqft.)
Cooling Central Chiller 52.2% 2.13               1.11                 6                 52.2% 1.92            1.00               ‐10%
Cooling RTU 24.7% 2.22               0.55                 3                 24.7% 2.00            0.49               ‐10%
Cooling PTAC 0.0% 2.22               ‐                    ‐             0.0% 2.00            ‐                 ‐10%
Combined Heating/Cooling Heat Pump 4.4% 5.23               0.23                 1                 4.4% 4.70            0.21               ‐10%
Space Heating Electric Resistance 15.8% 4.39               0.69                 4                 15.8% 4.39            0.69              0%
Space Heating Furnace 5.6% 5.67               0.32                 2                 5.6% 5.11            0.29               ‐10%
Ventilation Ventilation 90.2% 1.94               1.75                 9                 90.2% 1.74            1.57               ‐10%
Interior Lighting Interior Screw‐in 100.0%1.37               1.37                 7                 100.0% 1.23            1.23               ‐10%
Interior Lighting HID 100.0% 0.29               0.29                 1                 100.0% 0.26            0.26               ‐10%
Interior Lighting Linear Fluorescent 100.0% 2.19               2.19                 11               100.0% 1.97            1.97               ‐10%
Exterior Lighting Exterior Screw‐in 96.3% 0.03               0.03                 0                 96.3% 0.03            0.03               ‐10%
Exterior Lighting HID 96.3% 0.88               0.85                 4                 96.3% 0.79            0.76               ‐10%
Exterior Lighting Linear Fluorescent 96.3% 0.04               0.03                 0                 96.3% 0.03            0.03               ‐10%
Water Heating Water Heater 26.3% 3.72               0.98                 5                 26.3%3.53            0.93               ‐5%
Food Preparation Fryer 13.8% 0.13               0.02                 0                 13.8% 0.13            0.02              0%
Food Preparation Oven 13.8% 2.12               0.29                 1                 13.8% 2.12            0.29              0%
Food Preparation Dishwasher 13.8% 0.08               0.01                 0                 13.8% 0.08            0.01              0%
Food Preparation Hot Food Container 13.8% 0.13               0.02                 0                 13.8% 0.13            0.02              0%
Food Preparation Food Prep 13.8% 0.01               0.00                 0                 13.8% 0.01            0.00              0%
Refrigeration Walk in Refrigeration 26.6% 0.19               0.05                 0                 26.6% 0.17            0.04               ‐10%
Refrigeration Glass Door Display 26.6% 0.11               0.03                 0                 26.6% 0.10            0.03               ‐10%
Refrigeration Solid Door Refrigerator 26.6% 0.71               0.19                 1                 26.6% 0.64            0.17               ‐10%
Refrigeration Open Display Case 26.6% 0.50               0.13                 1                 26.6% 0.45            0.12               ‐10%
Refrigeration Vending Machine 26.6% 0.38               0.10                 1                 26.6% 0.38            0.10              0%
Refrigeration Icemaker 26.6% 0.31               0.08                 0                 26.6% 0.31            0.08              0%
Office Equipment Desktop Computer 100.0% 0.64               0.64                 3                 100.0% 0.64            0.64              0%
Office Equipment Laptop Computer 100.0% 0.07               0.07                 0                 100.0% 0.07            0.07              0%
Office Equipment Server 100.0% 0.17               0.17                 1                 100.0% 0.17            0.17              0%
Office Equipment Monitor 100.0% 0.13               0.13                 1                 100.0% 0.13            0.13              0%
Office Equipment Printer/copier/fax 100.0% 0.05               0.05                 0                 100.0% 0.05            0.05              0%
Office Equipment POS Terminal 100.0% 0.01               0.01                 0                 100.0% 0.01            0.01              0%
Miscellaneous Non‐HVAC Motor 88.8% 0.82               0.73                 4                 88.8% 0.82            0.73              0%
Miscellaneous Other Miscellaneous 100.0% 0.80               0.80                 4                 100.0% 0.80            0.80              0%
13.90               70               12.9              
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 958 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-10 www.gepllc.com

Table B–11 Extra Large Industrial Segment Market Profile, Idaho, 2009

EUI Intensity Usage EUI Intensity
(kWh) (kWh/Sqft.) (GWh)(kWh) (kWh/Sqft.)
Cooling Central Chiller 14.4% 7.98               1.15                 31               14.4% 7.18            1.04               ‐10%
Cooling RTU 17.1% 6.32               1.08                 29               17.1% 5.68            0.97               ‐10%
Cooling PTAC 1.1% 5.50               0.06                 2                 1.1% 4.95            0.05               ‐10%
Combined Heating/Cooling Heat Pump 1.6% 11.13            0.18                 5                 1.6% 10.01          0.16               ‐10%
Space Heating Electric Resistance 10.8% 8.67               0.93                 25               10.8% 8.67            0.93              0%
Space Heating Furnace 2.0% 9.10               0.18                 5                 2.0% 8.19            0.17               ‐10%
Ventilation Ventilation 27.4% 12.31            3.37                 92               27.4% 11.08          3.04               ‐10%
Interior Lighting Interior Screw‐in 100.0%0.33               0.33                 9                 100.0% 0.30            0.30               ‐10%
Interior Lighting HID 100.0% 1.05               1.05                 28               100.0% 0.94            0.94               ‐10%
Interior Lighting Linear Fluorescent 100.0% 1.10               1.10                 30               100.0% 0.99            0.99               ‐10%
Exterior Lighting Exterior Screw‐in 92.5% 0.02               0.02                 1                 92.5% 0.02            0.02               ‐10%
Exterior Lighting HID 92.5% 0.25               0.23                 6                 92.5% 0.23            0.21               ‐10%
Exterior Lighting Linear Fluorescent 92.5% 0.01               0.01                 0                 92.5% 0.01            0.01               ‐10%
Process Process Cooling/Refrigeration 2.4% 99.67            2.40                 65               2.4% 99.67          2.40              0%
Process Process Heating 26.2% 13.74            3.60                 98               26.2% 13.74          3.60              0%
Process Electrochemical Process 2.6% 77.43            2.00                 54               2.6% 77.43          2.00              0%
Machine Drive Less than 5 HP 90.5% 0.92               0.84                 23               90.5% 0.92            0.84              0%
Machine Drive 5‐24 HP 80.1% 2.26               1.81                 49               80.1% 2.26            1.81              0%
Machine Drive 25‐99 HP 72.4% 6.10               4.42                 120            72.4% 6.10            4.42              0%
Machine Drive 100‐249 HP 65.3% 3.84               2.51                 68               65.3%3.84            2.51              0%
Machine Drive 250‐499 HP 23.7% 11.61            2.75                 75               23.7% 11.61          2.75              0%
Machine Drive 500 and more HP 26.1% 19.50            5.08                 138            26.1% 19.50          5.08              0%
Miscellaneous Miscellaneous 100.0% 4.90               4.90                 133            100.0% 4.90            4.90              0%
40.00               1,088         39.1              
New Units
Compared to 
Average
Average Market Profiles
Saturation
Total
End Use Technology Saturation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 959 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-11
An EnerNOC Company
Figure B–1 Residential Baseline Forecast by End Use, Idaho

Figure B–2 C&I Baseline Electricity Forecast by End Use, Idaho

‐
200,000 
400,000 
600,000 
800,000 
1,000,000 
1,200,000 
1,400,000 
1,600,000 
1,800,000 
2,000,000 
2009 2012 2017 2022 2027 2032
An
n
u
a
l
 Us
e
 (M
W
h
)
Cooling
Space Heating
Heat & Cool
Water Heating
Appliances
Interior Lighting
Exterior Lighting
Electronics
Miscellaneous
‐
500,000 
1,000,000 
1,500,000 
2,000,000 
2,500,000 
3,000,000 
3,500,000 
2009 2012 2017 2022 2027 2032
An
n
u
a
l
 Us
e
 (M
W
h
)
Cooling
Space Heating
Heat & Cool
Ventilation
Water Heating
Food Preparation
Refrigeration
Interior Lighting
Exterior Lighting
Office Equipment
Miscellaneous
Machine Drive
Process
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 960 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-12 www.gepllc.com

Table B-12 Baseline Forecast Summary by Sector, Idaho
End Use 2009 2012 2017 2022 2027 2032 
% Change 
('09–'32) 
Avg. Growth 
Rate 
('09–'32) 
Res. ID 1,182,379 1,178,591 1,253,664 1,408,812 1,588,965 1,808,300 52.9%1.8%
C&I ID 2,180,858 2,217,188 2,383,504 2,551,291 2,748,846 2,970,324 36.2%1.3%
Total 3,363,237 3,395,780 3,637,168 3,960,104 4,337,811 4,778,624 42.1%1.5%

Figure B–3 Baseline Forecast Summary by Sector, Idaho
‐
1,000,000 
2,000,000 
3,000,000 
4,000,000 
5,000,000 
6,000,000 
An
n
u
a
l
 Us
e
 (M
W
h
)
Residential ‐ID C&I ‐ID
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 961 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-13
An EnerNOC Company
Figure B–4 Summary of Energy Efficiency Potential Savings, Idaho, All Sectors

Figure B–5 Energy Efficiency Potential Forecasts, Idaho, All Sectors

Realistic Achievable 
Maximum Achievable 
Economic 
Technical 
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2032
En
e
r
g
y
 Sa
v
i
n
g
s
 ( % of
 Ba
s
e
l
i
n
e
 Fo
r
e
c
a
s
t
)
‐
1,000,000 
2,000,000 
3,000,000 
4,000,000 
5,000,000 
6,000,000 
En
e
r
g
y
 Co
n
s
u
m
p
t
i
o
n
 (M
W
h
)
Baseline 
Achievable
Economic 
Technical 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 962 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-14 www.gepllc.com

Table B–13 Summary of Energy Efficiency Potential, Idaho, All Sectors
 2012 2017 2022 2027 2032 
Baseline Forecast 
(MWh) 3,395,780 3,637,168 3,960,104 4,337,811 4,778,624 
Baseline Peak 
Demand(MW) 610 644 705 775 854 
Cumulative Energy Savings (MWh)    
Realistic Achievable 17,115 138,024 328,192 529,056 743,485
Maximum Achievable 31,326 355,867 694,006 878,021 1,036,097
Economic 87,533 536,684 893,730 1,084,577 1,243,423
Technical 116,533 737,247 1,243,729 1,532,099 1,733,629
Cumulative Energy Savings (% of Baseline)    
Realistic Achievable 0.5% 3.8% 8.3% 12.2% 15.6% 
Maximum Achievable 0.9% 9.8% 17.5% 20.2% 21.7% 
Economic 2.6% 14.8% 22.6% 25.0% 26.0% 
Technical 3.4% 20.3% 31.4% 35.3% 36.3% 
Peak Savings (MW)    
Realistic Achievable 4 27 57 94 133 
Maximum Achievable 7 65 120 153 178 
Economic 19 98 154 186 213 
Technical 24 133 212 262 299 
Peak Savings (% of Baseline)    
Realistic Achievable 0.7% 4.1% 8.1% 12.1% 15.6% 
Maximum Achievable 1.1% 10.1% 17.1% 19.7% 20.9% 
Economic 3.1% 15.2% 21.9% 24.0% 24.9% 
Technical 4.0% 20.6% 30.1% 33.8% 35.0% 
Table B–14 Achievable Cumulative EE Potential by Sector, Idaho (MWh)
Segment 2012 2017 2022 2027 2032
Residential, Idaho 8,692 43,922 97,705 172,179 260,003
C&I, Idaho 8,423 94,102 230,487 356,878 483,482
Total 17,115 138,024 328,192 529,056 743,485
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 963 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-15
An EnerNOC Company
Figure B–6 Achievable Cumulative Potential by Sector, Idaho

Figure B–7 Residential Energy Efficiency Potential Savings, Idaho

Figure B–8 Residential Energy Efficiency Potential Forecast, Idaho

0
100,000
200,000
300,000
400,000
500,000
600,000
700,000
800,000
2012 2017 2022 2027 2032
C&I, ID
Residential, IDSa
v
i
n
g
s
 (M
W
h
)
Realistic Achievable 
Maximum Achievable 
Economic 
Technical 
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2032
En
e
r
g
y
 Sa
v
i
n
g
s
 (%
 of
 Ba
s
e
l
i
n
e
 Fo
r
e
c
a
s
t
)
‐
200,000 
400,000 
600,000 
800,000 
1,000,000 
1,200,000 
1,400,000 
1,600,000 
1,800,000 
2,000,000 
En
e
r
g
y
 Co
n
s
u
m
p
t
i
o
n
 (M
W
h
)
Baseline 
Realistic Achievable
Maximum Achievable
Economic 
Technical 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 964 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-16 www.gepllc.com

Table B–15 Energy Efficiency Potential for the Residential Sector, Idaho
 2012 2017 2022 2027 2032 
Baseline Forecast 
(MWh) 1,178,591 1,253,664 1,408,812 1,588,965 1,808,300 
Baseline Peak 
Demand(MW) 281 290 325 363 408 
Cumulative Energy Savings (MWh)    
Realistic achievable 8,692 43,922 97,705 172,179 260,003 
Maximum achievable 11,841 130,930 230,870 293,897 349,609 
Economic 33,369 179,104 280,336 341,494 403,100 
Technical 49,653 292,196 462,586 575,049 665,872 
Cumulative Energy Savings (% of Baseline)    
Realistic achievable 0.7% 3.5% 6.9% 10.8% 14.4% 
Maximum achievable 1.0% 10.4% 16.4% 18.5% 19.3% 
Economic 2.8% 14.3% 19.9% 21.5% 22.3% 
Technical 4.2% 23.3% 32.8% 36.2% 36.8% 
Peak Savings (MW)    
Realistic achievable 3 12 26 47 70 
Maximum achievable 4 32 61 79 92 
Economic 11 47 75 92 106 
Technical 14 69 109 135 157 
Peak Savings (% of Baseline)    
Realistic achievable 1.1% 4.2% 7.9% 12.8% 17.0% 
Maximum achievable 1.4% 11.2% 18.7% 21.7% 22.5% 
Economic 3.8% 16.3% 23.2% 25.3% 26.1% 
Technical 4.9% 23.8% 33.5% 37.2% 38.6% 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 965 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-17
An EnerNOC Company
Table B-16 Residential Baseline & Realistic Achievable Potential by Segment, Idaho
 2012 2017 2022 2027 2032
Baseline Forecast (MWh)    
Single Family 809,394 860,796 969,610 1,095,955 1,250,124 
Multi Family 43,239 46,927 53,367 60,656 69,266 
Mobile Home 58,491 61,447 68,664 77,048 87,262 
Limited Income 267,467 284,494 317,172 355,306 401,648 
Total 1,178,591 1,253,664 1,408,812 1,588,965 1,808,300 
Energy Savings, Realistic Achievable Potential (MWh)    
Single Family 6,394 32,068 76,498 135,426 203,716 
Multi Family 236 1,141 2,100 3,891 5,937 
Mobile Home 465 1,997 3,403 5,554 8,326 
Limited Income 1,597 8,715 15,705 27,307 42,024 
Total 8,692 43,922 97,705 172,179 260,003 
% of Total Residential Energy Savings 
Single Family 73.6% 73.0% 78.3% 78.7% 78.4% 
Multi Family 2.7% 2.6% 2.1% 2.3% 2.3% 
Mobile Home 5.3% 4.5% 3.5% 3.2% 3.2% 
Limited Income 18.4% 19.8% 16.1% 15.9% 16.2% 
Table B-17 Residential Potential by Housing Type, 2022, Idaho
Forecast Single 
Family 
Multi 
Family 
Mobile 
Home 
Limited 
Income Total 
Baseline Forecast (MWh) 969,610 53,367 68,664 317,172 1,408,812 
Cumulative Energy Savings (MWh) 
Realistic Achievable 76,498 2,100 3,403 15,705 97,705 
Maximum Achievable 180,146 5,514 7,612 37,597 230,870 
Economic Potential  215,829 7,112 9,445 47,950 280,336 
Technical Potential 311,446 15,951 23,241 111,948 462,586 
Energy Savings % of Baseline 
Realistic Achievable 7.9% 3.9% 5.0% 5.0% 6.9% 
Maximum Achievable 18.6% 10.3% 11.1% 11.9% 16.4% 
Economic Potential  22.3% 13.3% 13.8% 15.1% 19.9% 
Technical Potential 32.1% 29.9% 33.8% 35.3% 32.8% 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 966 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-18 www.gepllc.com

Table A-18 Residential Cumulative Savings by End Use and Potential Type, Oregon
(MWh)
End Use Case 2012 2017 2022 2027 2032 
Cooling 
Realistic Achievable 4 784 2,713 7,797 15,205
Economic 118 7,473 13,481 20,239 27,909
Technical 1,389 21,223 34,387 49,464 67,702
Space Heating 
Realistic Achievable 90 5,124 23,932 55,063 89,268
Economic 2,854 46,886 90,434 118,849 142,327
Technical 3,872 62,068 117,487 158,049 196,858
Heat/Cool 
Realistic Achievable  4 277 772 1,917 5,360
Economic 136 4,094 5,019 5,928 9,460
Technical 1,056 8,796 15,144 21,238 24,333
Water Heating 
Realistic Achievable 167 6,629 23,974 46,762 77,570
Economic 2,868 34,268 69,949 91,136 113,933
Technical 10,553 85,265 160,064 203,679 227,582
Appliances 
Realistic Achievable 434 4,216 9,065 14,393 20,002
Economic 1,885 20,859 27,076 28,751 30,895
Technical 2,461 26,764 35,893 38,774 41,155
Interior Lighting 
Realistic Achievable 6,180 17,434 19,757 22,622 23,650
Economic 18,432 36,002 35,080 32,028 29,190
Technical 21,560 49,417 48,706 45,433 42,120
Exterior Lighting 
Realistic Achievable  1,125 3,610 3,675 3,426 2,753
Economic 3,350 7,531 6,023 4,553 3,242
Technical 3,846 9,858 8,546 7,753 7,635
Electronics 
Realistic Achievable 607 4,630 11,073 15,629 19,572
Economic 3,058 15,658 23,240 26,031 29,797
Technical 4,219 22,321 32,027 36,258 41,681
Miscellaneous 
Realistic Achievable 80 1,217 2,744 4,568 6,622
Economic 667 6,334 10,036 13,980 16,348
Technical 697 6,484 10,331 14,400 16,807
Total 
Realistic Achievable 8,692 43,922 97,705 172,179 260,003
Economic 33,369 179,104 280,336 341,494 403,100
Technical 49,653 292,196 462,586 575,049 665,872

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 967 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-19
An EnerNOC Company
Figure B–9 Residential Realistic Achievable Potential by End Use, Selected Years,
Idaho

Table B-19 Residential Realistic Achievable Potential by End Use and Market Segment,
2022, Idaho (MWh)
 Single Family Multi Family Mobile 
Home 
Limited 
Income Total 
Cooling  1,736 51 59 866 2,713
Space heating 19,066 789 402 3,676 23,932
Heat/cool 675 3 39 56 772
Water heating 20,270 422 407 2,875 23,974
Appliances 6,657 103 451 1,854 9,065
Interior lighting 13,894 535 1,047 4,281 19,757
Exterior lighting 3,020 28 227 399 3,675
Electronics 8,757 167 617 1,531 11,073
Miscellaneous 2,422 1 153 168 2,744
Total 76,498 2,100 3,403 15,705 97,705

‐50,000 100,000 150,000 200,000 250,000 300,000 
2012
2017
2022
2027
2032
Cumulative Savings (MWh)
Cooling 
Space heating
Heat/cool
Water heating
Appliances
Int. lighting
Ext. lighting
Electronics
Miscellaneous
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 968 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-20 www.gepllc.com

Table B–20 Residential Cumulative Realistic Achievable Potential by End Use and
Equipment Measures, Idaho, Selected Years (MWh)
End Use Technology 2012 2017 2022 
Cooling Central AC ‐ 51 55 
Heat/Cool Air Source Ht. Pump ‐ ‐ ‐ 
Water Heating Water Heater 43 321 336 
Appliances 
Clothes Washer 29 352 888 
Clothes Dryer 35 240 440 
Dishwasher 40 373 912 
Refrigerator 146 652 1,266 
Freezer 113 560 1,221 
Second Refrigerator 53 257 475 
Stove 7 56 126 
Interior Lighting 
Screw‐in 5,757 14,262 14,623 
Linear Fluorescent 56 639 1,202 
Pin‐based 367 2,466 3,641 
Exterior Lighting 
Screw‐in 1,117 3,567 3,619 
High Intensity/Flood 8 43 56 
Electronics Personal Computers 389 3,151 5,418 
TVs 213 1,121 2,079 
Miscellaneous Pool Pump 61 559 1,372 
Furnace Fan 16 202 602 
Total 8,450 28,875 38,332 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 969 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-21
An EnerNOC Company
Table B–21 Residential Realistic Achievable Savings for Non-equipment Measures,
Idaho (MWh)
Measure 2012 2017 2022 
Furnace ‐ Convert to Gas 72 2,299 14,668 
Water Heater ‐ Convert to Gas 56 2,041 13,812 
Advanced New Construction Designs 0 62 1,426 
Repair and Sealing ‐ Ducting 6 853 2,417 
Insulation ‐ Infiltration Control 6 804 2,265 
Water Heater ‐ Thermostat Setback 44 2,506 4,232 
Home Energy Management System 2 377 1,323 
Freezer ‐ Remove Second Unit 8 1,104 2,367 
Water Heater ‐ Hot Water Saver 2 130 1,663 
Electronics ‐ Reduce Standby Wattage 4 358 3,576 
Thermostat ‐ Clock/Programmable 6 799 2,222 
Insulation ‐ Foundation 0 141 628 
Air Source Heat Pump ‐ Maintenance 4 277 772 
Refrigerator ‐ Remove Second Unit 4 622 1,369 
Water Heater ‐ Heat Pump  ‐ 12 334 
Water Heater ‐ Faucet Aerators 4 293 702 
Insulation ‐ Ducting 0 49 188 
Water Heater ‐ Tank Blanket/Insulation 15 794 1,238 
Insulation ‐ Wall Cavity 0 85 369 
Ceiling Fan ‐ Installation 0 24 167 
Room AC ‐ Removal of Second Unit 2 281 698 
Insulation ‐ Ceiling 1 115 339 
Water Heater ‐ Timer 0 231 801 
Water Heater ‐ Low Flow Showerheads 3 270 529 
Central AC ‐ Maintenance and Tune‐Up  ‐ ‐ ‐ 
Whole‐House Fan ‐ Installation 0 21 112 
Pool ‐ Pump Timer 3 456 771 
Water Heater ‐ Pipe Insulation 0 34 326 
Insulation ‐ Wall Sheathing 0 13 58 
Total 242 15,047 59,373 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 970 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-22 www.gepllc.com

Figure B–10 Energy Efficiency Potential Savings, C&I Sector, Idaho

Figure B–11 Energy Efficiency Potential Forecast, C&I Sector, Idaho

Realistic Achievable 
Maximum Achievable 
Economic 
Technical 
0%
5%
10%
15%
20%
25%
30%
35%
40%
2012 2017 2022 2027 2032
En
e
r
g
y
 Sa
v
i
n
g
s
 ( % of
 Ba
s
e
l
i
n
e
 Fo
r
e
c
a
s
t
)
‐
500,000 
1,000,000 
1,500,000 
2,000,000 
2,500,000 
3,000,000 
3,500,000 
En
e
r
g
y
 Co
n
s
u
m
p
t
i
o
n
 (M
W
h
)
Baseline 
Realistic Achievable 
Maximum Achievable 
Economic 
Technical 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 971 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-23
An EnerNOC Company
Table B–22 Energy Efficiency Potential, C&I Sector, Idaho
 2012 2017 2022 2027 2032
Baseline Forecast (MWh) 2,217,188 2,383,504 2,551,291 2,748,846 2,970,324 
Baseline Peak 
Demand(MW) 329 354 380 411 446 
Cumulative Energy Savings (MWh)    
Realistic Achievable 8,423 94,102 230,487 356,878 483,482 
Maximum Achievable   19,485 224,938 463,136 584,124 686,488 
Economic 54,164 357,579 613,394 743,082 840,323 
Technical 66,880 445,051 781,143 957,050 1,067,757 
Cumulative Energy Savings (% of Baseline)    
Realistic Achievable 0.4% 3.9% 9.0% 13.0% 16.3% 
Maximum Achievable   0.9% 9.4% 18.2% 21.2% 23.1% 
Economic 2.4% 15.0% 24.0% 27.0% 28.3% 
Technical 3.0% 18.7% 30.6% 34.8% 35.9% 
Peak Savings (MW)    
Realistic Achievable 1 14 31 48 64 
Maximum Achievable   3 33 60 74 86 
Economic 8 51 79 94 106 
Technical 10 64 103 127 141 
Peak Savings (% of Baseline)    
Realistic Achievable 0.4% 4.1% 8.3% 11.6% 14.3% 
Maximum Achievable   0.9% 9.2% 15.7% 17.9% 19.4% 
Economic 2.5% 14.3% 20.7% 22.9% 23.8% 
Technical 3.1% 18.1% 27.2% 30.8% 31.7% 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 972 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-24 www.gepllc.com

Table B–23 C&I Sector, Baseline and Realistic Achievable Potential by Segment, Idaho
 2012 2017 2022 2027 2032 
Baseline Forecast (MWh)    
Small/Med. Commercial  317,367 335,813 361,837 394,213 431,409 
Large Commercial  707,532 761,508 821,587 894,850 979,118 
Extra Large Commercial  72,013 83,305 90,387 98,291 106,847 
Extra Large Industrial  1,120,277 1,202,878 1,277,480 1,361,492 1,452,949 
Total  2,217,188 2,383,504 2,551,291 2,748,846 2,970,324 
Cumulative Energy Savings, Achievable Potential (MWh)    
Small/Med. Commercial  1,962 20,807 43,865 65,456 88,728 
Large Commercial  4,662 52,140 106,963 155,523 202,933 
Extra Large Commercial  609 6,178 13,050 19,166 24,274 
Extra Large Industrial  1,190 14,977 66,609 116,733 167,548 
Total  8,423 94,102 230,487 356,878 483,482 
% of Total C&I Cumulative Energy Savings 
Small/Med. Commercial  23.3% 22.1% 19.0% 18.3% 18.4% 
Large Commercial  55.4% 55.4% 46.4% 43.6% 42.0% 
Extra Large Commercial  7.2% 6.6% 5.7% 5.4% 5.0% 
Extra Large Industrial  14.1% 15.9% 28.9% 32.7% 34.7% 

Table B–24 C&I Potential by Segment, Idaho, 2022
Forecast Small/Med.
Commercial 
Large 
Commercial 
Extra Large 
Commercial 
Extra Large 
Industrial Total 
Baseline Forecast (MWh) 361,837 821,587 90,387 1,277,480 2,551,291 
Cumulative Energy Savings (MWh) 
Realistic Achievable 43,865 106,963 13,050 66,609 230,487 
Economic Potential  87,274 204,790 25,964 295,365 613,394 
Technical Potential 135,405 301,217 36,465 308,056 781,143 
Cumulative Energy Savings % of Baseline
Realistic Achievable 12% 13% 14% 5% 9% 
Economic Potential  24% 25% 29% 23% 24% 
Technical Potential 37% 37% 40% 24% 31% 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 973 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-25
An EnerNOC Company
Table B-25 C&I Cumulative Savings by End Use and Potential Type, Idaho (MWh)
End Use Case 2012 2017 2022 2027 2032 
Cooling 
Realistic Achievable 78 5,923 21,250 33,605 47,275 
Economic 1,138 20,975 45,413 59,510 75,348 
Technical 2,968 36,760 76,374 95,858 113,212 
Space Heating 
Realistic Achievable 6 758 4,296 8,178 13,308 
Economic 133 3,983 11,757 17,084 24,436 
Technical 215 6,445 19,442 26,587 34,707 
Heat/Cool 
Realistic Achievable 16 1,271 2,302 2,778 3,432 
Economic 185 3,001 3,761 4,432 4,954 
Technical 260 3,540 4,747 5,741 6,445 
Ventilation 
Realistic Achievable 211 2,846 15,356 29,448 47,931 
Economic 3,528 26,446 69,343 93,958 107,124 
Technical 4,612 34,655 93,204 122,731 132,705 
Water Heating 
Realistic Achievable 25 1,545 3,227 3,742 4,068 
Economic 198 3,518 4,823 5,295 5,309 
Technical 4,444 32,290 58,774 82,998 91,291 
Food Preparation 
Realistic Achievable 72 868 2,449 4,745 7,111 
Economic 962 5,813 10,539 12,677 13,834 
Technical 1,043 6,341 11,660 14,033 15,375 
Refrigeration 
Realistic Achievable 62 631 2,054 3,943 5,850 
Economic 925 4,540 8,629 11,127 12,502 
Technical 1,091 5,996 13,223 17,139 19,437 
Interior Lighting 
Realistic Achievable 5,851 55,282 110,129 160,780 203,673 
Economic 27,689 162,081 212,672 243,913 279,638 
Technical 30,318 177,750 239,322 274,804 311,478 
Exterior Lighting 
Realistic Achievable 526 7,858 15,569 19,409 23,034 
Economic 2,403 23,137 27,251 28,628 29,938 
Technical 2,701 25,247 30,174 34,115 38,276 
Office Equipment 
Realistic Achievable 862 8,854 14,582 19,189 23,952 
Economic 6,253 28,449 29,883 31,230 32,556 
Technical 8,238 38,728 41,183 43,665 46,239 
Machine Drive 
Realistic Achievable 382 6,612 33,312 56,917 77,212 
Economic 4,308 40,409 117,995 145,338 156,337 
Technical 4,341 40,906 119,993 147,502 158,642 
Process 
Realistic Achievable 328 1,590 5,541 13,154 24,996 
Economic 6,410 34,803 69,990 87,646 95,276 
Technical 6,410 34,803 69,990 87,646 95,276 
Miscellaneous 
Realistic Achievable 2 62 419 989 1,641 
Economic 33 426 1,336 2,245 3,070 
Technical 239 1,591 3,058 4,230 4,673 
Total 
Realistic Achievable 8,423 94,102 230,487 356,878 483,482 
Economic 54,164 357,579 613,394 743,082 840,323 
Technical 66,880 445,051 781,143 957,050 1,067,757 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 974 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-26 www.gepllc.com

Figure B-12 C&I Achievable Potential by End Use, Selected Years, Idaho

Table B-26 C&I Realistic Achievable Potential by End Use Market Segment, 2022,
Idaho (MWh)
 Small/Med. 
Commercial 
Large 
Commercial 
Extra Large 
Commercial 
Extra Large 
Industrial Total 
Cooling 2,805 8,283 1,032 9,129 21,250
Space Heating 338 2,110 305 1,544 4,296
Combined 
Heating/Cooling 249 1,666 119 267 2,302 
Ventilation 4,489 1,846 1,131 7,890 15,356
Water Heating 952 1,851 424 ‐ 3,227
Food Preparation 538 1,748 163 ‐ 2,449
Refrigeration 572 1,382 100 ‐ 2,054
Interior Lighting 25,426 68,834 7,612 8,256 110,129
Exterior Lighting 4,866 8,723 1,312 669 15,569
Office Equipment 3,482 10,274 825 ‐ 14,582
Machine Drive  ‐  ‐ ‐33,312 33,312
Process  ‐  ‐ ‐5,541 5,541
Miscellaneous 146 246 26 ‐ 419
Total 43,865 106,963 13,050 66,609 230,487

‐100,000 200,000 300,000 400,000 500,000 
2012
2017
2022
2027
2032
Cooling
Space Heating
Heat/cool
Ventilation
Water Heating
Food Preparation
Refrigeration
Interior Lighting
Exterior Lighting
Office Equipment
Miscellaneous
Machine Drive
Process
Cumulative Savings(MWh)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 975 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-27
An EnerNOC Company
Table B-27 C&I Cumulative Achievable Potential by End Use and Equipment Measures,
Washington (MWh)
End Use Technology 2012 2017 2022 
Cooling Central Chiller 29 304 1,225 
PTAC 2 2 2 
Heat/Cool Heat Pump 7 128 376 
Ventilation Ventilation 196 2,023 7,393 
Water Heater Water Heater 14 111 109 
Food Preparation  
Fryer 4 46 121 
Hot Food Container 9 102 274 
Oven 60 708 1,884 
Refrigeration 
Glass Door Display 11 155 440 
Icemaker 8 108 317 
Solid Door Refrigerator 14 165 438 
Vending Machine 27 152 371 
Walk in Refriger’n 0 5 13 
Interior Lighting 
Interior Screw‐in 3,326 21,132 32,157 
HID 1,014 9,151 18,439 
Linear Fluorescent 1,450 17,918 35,222 
Exterior Lighting 
Screw‐in 76 1,138 1,977 
HID 403 5,269 10,440 
Linear Fluorescent 42 758 1,287 
Office Equipment 
Desktop Computer 490 4,569 7,322 
Laptop Computer 35 331 530 
Monitor 106 383 662 
POS Terminal 14 196 359 
Printer/copier/fax 44 564 1,025 
Server 169 2,412 3,889 
Machine Drive 
Less than 5 HP 21 144 383 
5‐24 HP 46 324 887 
25‐99 HP 114 808 2,209 
100‐249 HP 32 227 622 
250‐499 HP 34 242 661 
500 and more HP 64 456 1,247 
Process 
Electrochem. Process 46 220 719 
Process Cooling/Refrig. 62 294 961 
Process Heating 220 1,048 3,426 
Miscellaneous Non‐HVAC Motor 2 25 181 
Total 8,194 71,620 137,570 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 976 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results

B-28 www.gepllc.com

Table B-28 C&I Cumulative Achievable Savings for Non-equipment Measures, Idaho
(MWh)
Measure 2012 2017 2022 
Energy Management System 13 819 8,607 
Advanced New Construction Designs 0 36 557 
Retrocommissioning ‐ Lighting 20 4,122 7,640 
Interior Fluorescent ‐ High Bay Fixtures 8 475 4,877 
Pumping System ‐ Optimization 11 507 4,907 
Compressed Air ‐ System Optimization and Improvements 11 506 4,837 
Custom Measures 2 296 4,148 
Fans ‐ Variable Speed Control 7 335 3,189 
Compressed Air ‐ System Controls 7 355 3,457 
RTU ‐ Maintenance 24 3,277 6,364 
Fans ‐ Energy Efficient Motors 6 346 3,463 
Retrocommissioning ‐ Comprehensive 12 2,552 4,572 
Retrocommissioning ‐ HVAC 3 323 3,038 
Motors ‐ Variable Frequency Drive 11 1,338 2,707 
Pumps ‐ Variable Speed Control 5 241 2,289 
Motors ‐ Magnetic Adjustable Speed Drives 5 221 2,171 
Compressed Air ‐ Compressor Replacement 4 203 1,982 
Pumping System ‐ Controls 4 202 1,942 
Chiller ‐ Turbocor Compressor 3 167 1,764 
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts 0 22 193 
Interior Lighting ‐ Occupancy Sensors 7 249 1,949 
Water Heater ‐ Faucet Aerators/Low Flow Nozzles 9 1,306 2,692 
Chiller ‐ VSD 2 127 1,257 
Interior Fluorescent ‐ Delamp and Install Reflectors 6 222 1,622 
Roofs ‐ High Reflectivity 1 21 165 
Commissioning ‐ Comprehensive 0 123 805 
Chiller ‐ Condenser Water Temperature Reset 3 196 1,839 
Heat Pump ‐ Maintenance 9 1,143 1,925 
Compressed Air ‐ System Maintenance 13 717 1,198 
Pumping System ‐ Maintenance  ‐ 43 606 
Exterior Lighting ‐ Daylighting Controls 2 70 562 
Insulation ‐ Ducting 1 93 778 
Chiller ‐ Chilled Water Reset 2 403 705 
Thermostat ‐ Clock/Programmable 2 304 595 
Commissioning ‐ Lighting 0 94 314 
Office Equipment ‐ ENERGY STAR Power Supply 3 399 795 
Cooking ‐ Exhaust Hoods with Sensor Control 0 6 56 
Refrigeration ‐ System Optimization 0 15 229 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 977 of 1069
Idaho Market Profiles, Baseline Forecast, and Potential Results
Global Energy Partners B-29
An EnerNOC Company
Measure 2012 2017 2022 
Furnace ‐ Convert to Gas 1 35 229 
Water Heater ‐ Heat Pump 0 16 211 
Refrigeration ‐ System Controls 0 10 160 
Cooling ‐ Economizer Installation 1 42 378 
Exterior Lighting ‐ Induction Lamps 0 10 140 
Insulation ‐ Ceiling 0 1 13 
Industrial Process Improvements 0 11 127 
LED Exit Lighting 9 319 358 
Commissioning ‐ HVAC  ‐ ‐ 4 
Water Heater ‐ Tank Blanket/Insulation 2 111 195 
Miscellaneous ‐ ENERGY STAR Water Cooler 0 20 58 
Refrigeration ‐ System Maintenance 0 3 46 
Refrigeration ‐ Floating Head Pressure 0 4 46 
Insulation ‐ Wall Cavity 0 2 31 
Refrigeration ‐ Strip Curtain  ‐ 0 14 
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer 0 3 35 
Water Heater ‐ Hot Water Saver  ‐ ‐ 1 
Water Heater ‐ High Efficiency Circulation Pump 0 2 19 
Vending Machine ‐ Controller 0 13 22 
Chiller ‐ Chilled Water Variable‐Flow System 0 2 19 
Exterior Lighting ‐ Cold Cathode Lighting 0 1 8 
Refrigeration ‐ Night Covers 0 0 4 
Laundry ‐ High Efficiency Clothes Washer 0 3 5 
Total 228 22,482 92,917 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 978 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 979 of 1069

Global Energy Partners C-1
An EnerNOC Company

APPENDIX C
RESIDENTIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA
This appendix presents detailed information for all residential energy efficiency equipment and
measures that were evaluated in LoadMAP. Several sets of tables are provided.
Table C-1 provides brief descriptions for all equipment and measures that were assessed for
potenital.
Tables C-2 through C-9 list the detailed unit-level data for the equipment measures for each of
the housing type segments — single family, multi-family, mobile home, and limited income —
and for existing and new construction, respectively. Savings are in kWh/yr/household, and
incremental costs are in $/household, unless noted otherwise. The B/C ratio is zero if the
measure represents the baseline technology or if the technology is not available in the first year
of the forecast (2012). The B/C ratio is calculated within LoadMAP for each year of the forecast
and is available once the technology or measure becomes available.
Tables C-10 through C-17 list the detailed unit-level data for the non-equipment energy
efficiency measures for each of the housing type segments and for existing and new
construction, respectively. Because these measures can produce energy-use savings for multiple
end-use loads (e.g., insulation affects heating and cooling energy use) savings are expressed as
a percentage of the end-use loads. Base saturation indicates the percentage of homes in which
the measure is already installed. Applicability/Feasibility is the product of two factors that
account for whether the measure is applicable to the building. Cost is expressed in $/household.
The detailed measure-level tables present the results of the benefit/cost (B/C) analysis for the
first year of the forecast. The B/C ratio is zero if the measure represents the baseline technology
or if the measure is not available in the first year of the forecast (2012). The B/C ratio is
calculated within LoadMAP for each year of the forecast and is available once the technology or
measure becomes available.
Note that Tables C-2 through C-17 present information for Washington. For Idaho, savings and
B/C ratios may be slightly different due to weather-related usage, differences in the states’
market profiles, and different retail electricity prices. Although Idaho-specific values are not
presented here, they are available within the LoadMAP files.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 980 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-2 www.gepllc.com

Table C–1 Residential Energy Efficiency Equipment/Measure Descriptions
End‐Use 
Equipment/ 
Measure Description 
Cooling Air Conditioner — 
Central (CAC) 
Central air conditioners consist of a refrigeration system using a direct 
expansion cycle. Equipment includes a compressor, an air‐cooled condenser 
(located outdoors), an expansion valve, and an evaporator coil. A supply fan 
near the evaporator coil distributes supply air through air ducts to the building. 
Cooling efficiencies vary based on materials used, equipment size, condenser 
type, and system configuration. CACs may be unitary (all components housed 
in a factory‐built assembly) or split system (an outdoor condenser section and 
an indoor evaporator section connected by refrigerant lines and with the 
compressor either indoors or outdoors). Energy efficiency is rated according to 
the size of the unit using the Seasonal Energy Efficiency Rating (SEER). Systems 
with Variable Refrigerant Flow further improve the operating efficiency. A 
high‐efficiency option for a ductless mini‐split system was also analyzed.  
Cooling Central Air 
Conditioner, Early 
Replacement 
CAC systems currently on the market are significantly more efficient that older 
units, due to technology improvement and stricter appliance standards. This 
measure incents homeowners to replace an aging but still working unit with a 
new, higher‐efficiency one. 
Cooling Central Air 
Conditioner 
Maintenance and 
Tune Up 
An air conditioner's filters, coils, and fins require regular cleaning and 
maintenance for the unit to function effectively and efficiently throughout its 
life. Neglecting necessary maintenance leads to a steady decline in 
performance, requiring the AC unit to use more energy for the same cooling 
load.  
Cooling Air Conditioner ‐ 
Room, ENERGY STAR 
or better 
Room air conditioners are designed to cool a single room or space. They 
incorporate a complete air‐cooled refrigeration and air‐handling system in an 
individual package. Room air conditioners come in several forms, including 
window, split‐type, and packaged terminal units. Energy efficiency is rated 
according to the size of the unit using the Energy Efficiency Rating (EER).  
Cooling Room AC — Removal 
of Second Unit 
Homeowners may have a second room AC unit that is extremely inefficient. 
This measure incents homeowners to recycle the second unit and thus also 
eliminates associated electricity use. 
Cooling Attic Fan 

Attic Fan, 
Photovoltaic 
Attic fans can reduce the need for AC by reducing heat transfer from the attic 
through the ceiling of the house. A well‐ventilated attic can be several degrees 
cooler than a comparable, unventilated attic. An option for an attic fan 
equipped with a small solar photovoltaic generator was also modeled. 
Cooling Ceiling Fan Ceiling fans can reduce the need for air conditioning. However, the house 
occupants must also select a ceiling fan with a high‐efficiency motor and either 
shutoff the AC system or setup the thermostat temperature of the air 
conditioning system to realize the potential energy savings. Some ceiling fans 
also come with lamps. In this analysis, it is assumed that there are no lamps, 
and installing a ceiling fan will allow occupants to increase the thermostat 
cooling setpoint up by 2°F. 
Cooling Whole‐House Fan Whole‐house fans can reduce the need for AC on moderate‐weather days or 
on cool evenings. The fan facilitates a quick air change throughout the entire 
house. Several windows must be open to achieve the best results. The fan is 
mounted on the top floor of the house, usually in a hallway ceiling. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 981 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-3
An EnerNOC Company
End‐Use 
Equipment/ 
Measure Description 
Space Heating Convert to Gas This fuel‐switching measure is the replacement of an electric furnace with a 
gas‐fired furnace. This measure will eliminate all electricity consumption and 
demand due to electric space heating. In this study, it is assumed that this 
measure can be implemented only in homes within 500 feet of a gas main. 
Heat/Cool Air Source Heat 
Pump 
A central heat pump consists of components similar to a CAC system, but is 
usually designed to function both as a heat pump and an air conditioner. It 
consists of a refrigeration system using a direct expansion (DX) cycle. 
Equipment includes a compressor, an air‐cooled condenser (located outdoors), 
an expansion valve, and an evaporator coil (located in the supply air duct near 
the supply fan) and a reversing valve to change the DX cycle from cooling to 
heating when required. The cooling and heating efficiencies vary based on the 
materials used, equipment size, condenser type, and system configuration. 
Heat pumps may be unitary (all components housed in a factory‐built 
assembly) or a split system (an outdoor condenser section and an indoor 
evaporator section connected by refrigerant lines, with either outdoors or 
indoors. A high‐efficiency option for a ductless mini‐split system was also 
analyzed. 
Heat / Cool Geothermal Heat 
Pump 
Geothermal heat pumps are similar to air‐source heat pumps, but use the 
ground or groundwater instead of outside air to provide a heat source/sink. A 
geothermal heat pump system generally consists of three major subsystems or 
parts: a geothermal heat pump to move heat between the building and the 
fluid in the earth connection, an earth connection for transferring heat 
between the fluid and the earth, and a distribution subsystem for delivering 
heating or cooling to the building. The system may also have a desuperheater 
to supplement the building's water heater, or a full‐demand water heater to 
meet all of the building's hot water needs.  
Heat / Cool Air Source Heat 
Pump Maintenance 
A heat pump's filters, coils, and fins require regular cleaning and maintenance 
for the unit to function effectively and efficiently throughout its life. Neglecting 
necessary maintenance ensures a steady decline in performance while energy 
use steadily increases.  
HVAC (all) Insulation – Ducting Air distribution ducts can be insulated to reduce heating or cooling losses. Best 
results can be achieved by covering the entire surface area with insulation. 
Several types of ducts and duct insulation are available, including flexible duct, 
pre‐insulated duct, duct board, duct wrap, tacked, or glued rigid insulation, and 
waterproof hard shell materials for exterior ducts.  This analysis assumes that 
installing duct insulation can reduce the temperature drop/gain in ducts by 
50%. 
HVAC (all) Repair and Sealing –
Ducting 
An ideal duct system would be free of leaks. Leakage in unsealed ducts varies 
considerably because of differences in fabricating machinery used, methods 
for assembly, installation workmanship, and age of the ductwork. Air leaks 
from the system to the outdoors result in a direct loss proportional to the 
amount of leakage and the difference in enthalpy between the outdoor air and 
the conditioned air. This analysis assumes that over time air loss from ducts 
has doubled, and conducting repair and sealing of the ducts will restore 
leakage from ducts to the original baseline level. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 982 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-4 www.gepllc.com

End‐Use 
Equipment/ 
Measure Description 
HVAC (all) Thermostat — 
Clock/Programmable 

A programmable thermostat can be added to most heating/cooling systems.  
They are typically used during winter to lower temperatures at night and in 
summer to increase temperatures during the afternoon. The energy savings 
from this type of thermostat are identical to those of a "setback" strategy with 
standard thermostats, but the convenience of a programmable thermostat 
makes it a much more attractive option.  In this analysis, the baseline is 
assumed to have no thermostat setback. 
HVAC (all) Doors — Storm and 
Thermal 
Like other components of the shell, doors are subject to several types of heat 
loss: conduction, infiltration, and radiant losses. Similar to a storm window, a 
storm door creates an insulating air space between the storm and primary 
doors. A tight fitting storm door can also help reduce air leakage or infiltration.  
Thermal doors have exceptional thermal insulation properties and also are 
provided with weather‐stripping on the doorframe to reduce air leakage. 
HVAC (all) Insulation — 
Infiltration Control 

Lowering the air infiltration rate by caulking small leaks and weather‐stripping 
around window frames, doorframes, power outlets, plumbing, and wall 
corners can provide significant energy savings. Weather‐stripping doors and 
windows will create a tight seal and further reduce air infiltration.  
HVAC (all) Insulation —Ceiling Thermal insulation is material or combinations of materials that are used to 
inhibit the flow of heat energy by conductive, convective, and radiative 
transfer modes. Thus, thermal insulation above ceilings can conserve energy by 
reducing the heat loss or gain into attics and/or through roofs. The type of 
building construction defines insulating possibilities. Typical insulating 
materials include:  loose‐fill (blown) cellulose, loose‐fill (blown) fiberglass, and 
rigid polystyrene. 
HVAC (all) Insulation — Radiant 
Barrier 
Radiant barriers are materials installed to reduce the heat gain in buildings. 
Radiant barriers are made from materials that are highly reflective and have 
low emissivity like aluminum. The closer the emissivity is to 0 the better they 
will perform.  Radiant barriers can be placed above the insulation or on the 
roof rafters.   
HVAC (all) Insulation — 
Foundation  
Insulation  — Wall 
Cavity 
Insulation  — Wall 
Sheathing 
Thermal insulation is material or combinations of materials that are used to 
inhibit the flow of heat energy by conductive, convective, and radiative 
transfer modes. Thus, thermal insulation can conserve energy by reducing heat 
loss or gain from a building. The type of building construction defines insulating 
possibilities. Typical insulating materials include:  loose‐fill (blown) cellulose, 
loose‐fill (blown) fiberglass, and rigid polystyrene. Foundation, insulation, wall 
cavity insulation, and wall sheathing were modeled for new construction / 
major retrofits only. 
Cooling Roof — High 
Reflectivity 
The color and material of a building structure surface determine the amount of 
solar radiation absorbed by that surface and subsequently transferred into a 
building. This is called solar absorptance. Using a roofing material with low 
solar absorptance or painting the roof a light color reduces the cooling load.  
This analysis assumes that implementing high reflectivity roofs will decrease 
the roof’s absorptance of solar radiation by 45%. 
Cooling Windows — 
Reflective Film 
Reflective films applied to the window interior help reduce solar gain into the 
space and thus lower cooling energy use. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 983 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-5
An EnerNOC Company
End‐Use 
Equipment/ 
Measure Description 
HVAC (all) Windows — High 
Efficiency / ENERGY 
STAR 
High‐efficiency windows, such as those labeled under the ENERGY STAR 
Program, are designed to reduce energy use and increase occupant comfort.  
High‐efficiency windows reduce the amount of heat transfer through the 
glazing surface. For example, some windows have a low‐E coating, a thin film 
of metallic oxide coating on the glass surface that allows passage of short‐wave 
solar energy through glass and prevents long‐wave energy from escaping. 
Another example is double‐pane glass that reduces conductive and convective 
heat transfer.  Some double‐pane windows are gas‐filled (usually argon) to 
further increase the insulating properties of the window. 
Water Heating Water Heater ‐ 
Electric, High 
Efficiency 
For electric hot water heating, the most common type is a storage heater, 
which incorporates an electric heating element, storage tank, outer jacket, 
insulation, and controls in a single unit. Efficient units are characterized by a 
high recovery or thermal efficiency and low standby losses (the ratio of heat 
lost per hour to the content of the stored water). Electric instantaneous water 
heaters are available, but are excluded from this study due to potentially high 
instantaneous demand concerns. 
Water Heating Water Heater, Heat 
Pump 
An electric heat pump water heater (HPWH) uses a vapor‐compression 
thermodynamic cycle similar to that found in an air‐conditioner or refrigerator. 
Electrical work input allows a heat pump water heater to extract heat from an 
available source (e.g., air) and reject that heat to a higher temperature sink, in 
this case, the water in the water heater. Because a HPWH makes use of 
available ambient heat, the coefficient of performance is greater than one —
typically in the range of 2 to 3. These devices are available as an alternative to 
conventional tank water heaters of 55 gallons or larger. By utilizing the earth as 
a thermal reservoir, ground source HPWH systems can reach even higher levels 
of efficiency. The heat pump can be integrated with a traditional water storage 
tank or installed remote to the storage tank.  
Water Heating Water Heating, Solar Solar water heating systems can be used in residential buildings that have an 
appropriate near‐south‐facing roof or nearby unshaded grounds for installing a 
collector. Although system types vary, in general these systems use a solar 
absorber surface within a solar collector or an actual storage tank. Either a 
heat‐transfer fluid or the actual potable water flows through tubes attached to 
the absorber and transfers heat from it. (Systems with a separate heat‐
transfer‐fluid loop include a heat exchanger that then heats the potable 
water.) The heated water is stored in a separate preheat tank or a 
conventional water heater tank. If additional heat is needed, it is provided by a 
conventional water‐heating system. 
Water Heating Convert to Gas This fuel‐switching measure is the replacement of an electric water heater with 
a gas‐fired water heater. This measure will eliminate all electricity consumption 
and demand due to electric water heating.  In this study, it is assumed that this 
measure can be implemented only in home within 500 feet of a gas main. 
Water Heating Faucet Aerators Water faucet aerators are threaded screens that attach to existing faucets. 
They reduce the volume of water coming out of faucets while introducing air 
into the water stream. This measure provides energy saving by reducing hot 
water use, as well as water conservation for both hot and cold water. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 984 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-6 www.gepllc.com

End‐Use 
Equipment/ 
Measure Description 
Water Heating Pipe Insulation Insulating hot water pipes decreases energy losses from piping that distributes 
hot water throughout the building. I also results in quicker delivery of hot 
water and may allow lower the hot water set point, which saves energy. The 
most common insulation materials for this purpose are polyethylene and 
neoprene.       
Water Heating Low‐Flow 
Showerheads 
Similar to faucet aerators, low‐flow showerheads reduce the consumption of 
hot water, which in turn decreases water heating energy use.   
Water Heating Tank Blanket Insulating hot water tanks decreases standby energy losses from the tank. Pre‐
fitted insulating blankets are readily available. 
Water Heating Thermostat Setback 
/ Timer 
These measures use either a programmable thermostat or a timer to adjust the 
water heater setpoint at times of low usage, typically when a home is 
unoccupied. 
Water Heating Hot Water Saver A hot water saver is a plumbing device that attaches to the showerhead and 
that pauses the flow of water until the water is hot enough for use. The water 
is re‐started by the flip of a switch. 
Interior Lighting 
/ Exterior 
Lighting  
Infrared Halogen 
Lamps 
Infrared halogen lamps are designed to be a replacement for standards 
incandescent lamps. Also referred to as advanced incandescent lamps, these 
products meet the Energy Independence and Security Act (EISA) lighting 
standards and are phased in as the baseline technology screw‐in lamp 
technology to reflect the timeline over which the EISA lighting standards take 
effect. 
Interior Lighting 
/ Exterior 
Lighting 
Compact Fluorescent 
Lamps 
Compact fluorescent lamps are designed to be a replacement for standard 
incandescent lamps and use about 25% of the energy used by standard 
incandescent lamps to produce the same lumen output. The can use either 
electronic or magnetic ballasts. Integral compact fluorescent lamps have the 
ballast integrated into the base of the lamp and have a standard screw‐in base 
that permits installation into existing incandescent fixtures. 
Interior Lighting 
/ Exterior 
Lighting 
Solid State Lighting, 
LEDs (Screw‐in and 
linear) 
Light‐emitting diode (LED) lighting has seen recent penetration in specific 
applications such as traffic lights and exit signs. With the potential for 
extremely high efficiency, LEDs show promise to provide general‐use lighting 
for interior spaces. Current models commercially available have efficacies 
comparable to CFLs. However, theoretical efficiencies are significantly higher. 
LED models under development are expected to provide improved efficacies. 
Interior Lighting Fluorescent, T8, 
Super T8, and T5 
Lamps and Electronic 
Ballasts 
T8 fluorescent lamps are smaller in diameter than standard T12 lamps, 
resulting in greater light output per watt. T8 lamps also operate at a lower 
current and wattage, which increases the efficiency of the ballast but requires 
the lamps to be compatible with the ballast. Fluorescent lamp fixtures can 
include a reflector that increases the light output from the fixture, and thus 
make it possible to use a fewer number of lamps in each fixture. T5 lamps 
further increase efficiency by reducing the lamp diameter to 5/8”. 
Exterior Lighting Metal Halide and 
High Pressure 
Sodium 
These lamps technologies can provide slightly higher efficiencies than CFLs in 
exterior applications. 
Interior Lighting Occupancy Sensors Occupancy sensors turn lights off when a space is unoccupied. They are 
appropriate for areas with intermittent use, such as bathrooms or storage 
areas.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 985 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-7
An EnerNOC Company
End‐Use 
Equipment/ 
Measure Description 
Exterior Lighting Photovoltaic 
Installation 
Solar photovoltaic generation may be used to power exterior lighting and thus 
eliminate all or part of the electrical energy use.  
Exterior Lighting Photosensor Control Photosensor controls turn exterior lighting on or off based on ambient lighting 
levels. Compared with manual operation, this can reduce the operation of 
exterior lighting during daylight hours.  
Exterior Lighting Timeclock 
Installation 
Lighting timers turn exterior lighting on or off based on a preset schedule. 
Compared with manual operation, this can reduce the operation of exterior 
lighting during daylight hours. 
Appliances Refrigerator/Freezer, 
ENERGY STAR or 
better 
Energy‐efficient refrigerators/freezers incorporate features such as improved 
cabinet insulation, more efficient compressors and evaporator fans, defrost 
controls, mullion heaters, oversized condenser coils, and improved door seals.  
Further efficiency increases can be obtained by reducing the volume of 
refrigerated space, or adding multiple compartments to reduce losses from 
opening doors. 
Appliances Refrigerator/Freezer 
—  
Early Replacement  
Refrigerators/freezers currently on the market are significantly more efficient 
that older units, due to technology improvement and stricter appliance 
standards. This measure incents homeowners to replace an aging but still 
working unit with a new, higher‐efficiency one. 
Appliances Refrigerator/Freezer 
—  
Remove Second Unit 
Homeowners may have a second refrigerator or freezer that is not used to full 
capacity and that, because of its age, is extremely inefficient. This measure 
incents homeowners to recycle the second unit and thus also eliminates 
associated electricity use. 
Appliances Dishwasher, ENERGY 
STAR or better 
ENERGY STAR labeled dishwashers save by using both improved technology for 
the primary wash cycle, and by using less hot water. Construction includes 
more effective washing action, energy‐efficient motors, and other advanced 
technology such as sensors that determine the length of the wash cycle and 
the temperature of the water necessary to clean the dishes.  
Appliances Clothes Washer, 
ENERGY STAR or 
better 
ENERGY STAR labeled clothes washers use superior designs that require less 
water. Sensors match the hot water needs to the size and soil level of the load, 
preventing energy waste. Further energy and water savings can be achieved 
through advanced technologies such as inverter‐drive or combination washer‐
dryer units. 
Appliances Clothes Dryer – 
Electric, High 
Efficiency 
An energy‐efficient clothes dryer has a moisture‐sensing device to terminate 
the drying cycle rather than using a timer, and an energy‐efficient motor is 
used for spinning the dryer tub. Application of a heat pump cycle for extracting 
the moisture from clothes leads to additional energy savings. 
Appliances Range and Oven – 
Electric, High 
Efficiency 
These products have additional insulation in the oven compartment and 
tighter‐fitting oven door gaskets and hinges to save energy. Conventional 
ovens must first heat up about 35 pounds of steel and a large amount of air 
before they heat up the food. Tests indicate that only 6% of the energy output 
of a typical oven is actually absorbed by the food.  
Electronics Color TVs and Home 
Electronics, ENERGY 
STAR or better 
In the average home, electronic products consumed significant energy, even 
when they are turn off, to maintain features like clocks, remote control, and 
channel/station memory. ENERGY STAR labeled consumer electronics can 
drastically reduce consumption during standby mode, in addition to saving 
energy through advanced power management during normal use.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 986 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-8 www.gepllc.com

End‐Use 
Equipment/ 
Measure Description 
Electronics Personal Computers, 
ENERGY STAR or 
better 
Improved power management can significantly reduce the annual energy 
consumption of PCs and monitors in both standby and normal operation. 
ENERGY STAR and Climate Savers labeled products provide increasing level of 
energy efficiency. 
Electronics Reduce Standby 
Wattage 
Representing a growing portion of home electricity consumption, plug‐in 
electronics such as set‐top boxes, DVD players, gaming systems, digital video 
recorders, and even battery chargers for mobile phones and laptop computers 
are often designed to supply a set voltage. When the units are not in use, this 
voltage could be dropped significantly (~1 W) and thereby generate a 
significant energy savings, assumed for this analysis to be between 4‐5% on 
average. These savings are in excess of the measures already discussed for 
computers and televisions.  
Misc. Furnace Fans, 
Electronically 
Commutating Motor 
In homes heated by a furnace, there is still substantial energy use by the fan 
responsible for moving the hot air throughout the ductwork.  Application of an 
Electronically Commutating Motor (ECM) ensures that motor speed matches 
the heating requirements of the system and saves energy when compared to a 
continuously operating standard motor. 
Miscellaneous Pool Pump  High‐efficiency motors and two‐speed pumps provide improved energy 
efficiency for this load.  
Miscellaneous Pool Pump Timer A pool pump timer allows the pump to turn off automatically, eliminating the 
wasted energy associated with unnecessary pumping.   
Miscellaneous Trees for Shading Planting of shade trees, suitable to the local climate, can reduce the need for 
air conditioning and provide non‐energy benefits as well.  
Cooling / Space 
Heating / 
Interior Lighting 
Home Energy 
Management System 
A centralized home energy management system can be used to control and 
schedule cooling, space heating, lighting, and possibly appliances as well. Some 
designs also allow the homeowner to remotely control loads via the Internet. 
Cooling / Space 
Heating  
Solar Photovoltaic Adding a solar photovoltaic (PV) system to the home can meet a portion of the 
home’s electric load and in some cases nearly the entire load, depending on 
the PV system size, orientation, solar resource, and other factors. For this 
analysis, we assume a grid‐connected system and apply the electricity savings 
to the home’s cooling and space heating loads. 
Cooling / Space 
Heating / 
Interior Lighting 
Advanced New 
Construction Designs 
Advanced new construction designs use an integrated approach to the design 
of new buildings to account for the interaction of building systems. Typically, 
designs specify the building orientation, building shell, building mechanical 
systems, and controls strategies with the goal of optimizing building energy 
efficiency and comfort. Options that may be evaluated and incorporated 
include passive solar strategies, increased thermal mass, natural ventilation, 
daylighting strategies, and shading strategies, This measure was modeled for 
new construction only. 
Cooling / Space 
Heating / 
Interior Lighting 
ENERGY STAR Homes 

This measure was modeled for new construction only. 
Cooling / Space 
Heating / 
Interior Lighting 
Energy‐Efficient 
Manufactured 
Homes 
This measure was modeled for new construction only. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 987 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-9
An EnerNOC Company
Table C-2 Energy Efficiency Equipment Data — Single Family, Existing Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                  $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)134               $278 15 0.41          
Cooling Central AC SEER 15 (CEE Tier 2)184               $556 15 0.28          
Cooling Central AC SEER 16 (CEE Tier 3)226               $834 15 0.23          
Cooling Central AC Ductless Mini‐Split System 405               $4,399 20 0.14          
Cooling Room AC EER 9.8 ‐                  $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)62                  $104 10 0.33          
Cooling Room AC EER 11 73                  $282 10 0.15          
Cooling Room AC EER 11.5 99                  $626 10 0.09          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                  $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star) 492               $1,000 15 0.43          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2) 675               $2,318 15 0.26          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3) 829               $3,505 15 0.21          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 1,486            $5,655 20 0.45          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                  $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 516               $1,500 14 0.28          
Space Heating Electric Resistance Electric Resistance ‐                  $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                  $0 15 ‐            
Space Heating Supplemental Supplemental ‐                  $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                  $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 173               $41 15 5.79          
Water Heating Water Heater Geothermal Heat Pump 2,269            $6,586 15 0.47          
Water Heating Water Heater Solar 2,493            $5,653 15 0.60          
Interior Lighting* Screw‐in Incandescent  ‐                  $0 4 ‐            
Interior Lighting* Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting* Screw‐in CFL 38                  $2 6 14.44       
Interior Lighting* Screw‐in LED 40                  $80 12 0.90          
Interior Lighting* Linear Fluorescent T12 ‐                  $0 6 ‐            
Interior Lighting* Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting* Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting* Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting* Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting* Pin‐based Halogen ‐                  $0 4 ‐            
Interior Lighting* Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting* Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                  $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 22.43       
Exterior Lighting* Screw‐in LED 37                  $79 12 0.89          
Exterior Lighting* High Intensity/Flood Incandescent ‐                  $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                  $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)45                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 88                  $487 10 0.16          
Appliances Clothes Dryer Baseline ‐                  $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 98                  $48 13 2.39          
Appliances Dishwasher Baseline ‐                  $0 9 ‐            
Appliances Dishwasher Energy Star 41                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)53                  $1 9 31.05       
Appliances Refrigerator Baseline ‐                  $0 13 ‐            
Appliances Refrigerator Energy Star 108               $89 13 1.28          
Appliances Refrigerator Baseline (2014)144               $0 13 ‐            
Appliances Refrigerator Energy Star (2014)230               $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 988 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-10 www.gepllc.com

Table C-2 Energy Efficiency Equipment Data — Single Family, Existing Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                  $0 11 ‐            
Appliances Freezer Energy Star 114               $32 11 3.03          
Appliances Freezer Baseline (2014)152               $0 11 ‐            
Appliances Freezer Energy Star (2014)243               $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                  $0 13 ‐            
Appliances Second Refrigerator Energy Star 111               $89 13 1.31          
Appliances Second Refrigerator Baseline (2014)148               $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)237               $89 13 ‐            
Appliances Stove Baseline ‐                  $0 13 ‐            
Appliances Stove Convection Oven 9                    $2 13 7.00          
Appliances Stove Induction (High Efficiency) 46                  $1,432 13 0.05          
Appliances Microwave Baseline ‐                  $0 9 ‐            
Electronics Personal Computers Baseline ‐                  $0 5 ‐            
Electronics Personal Computers Energy Star 108               $1 5 35.63       
Electronics Personal Computers Climate Savers 154               $175 5 0.35          
Electronics TVs Baseline ‐                  $0 11 ‐            
Electronics TVs Energy Star 87                  $1 11 133.21     
Electronics Devices and Gadgets Devices and Gadgets ‐                  $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                  $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 138               $85 15 1.96          
Miscellaneous Pool Pump Two‐Speed Pump 551               $579 15 1.15          
Miscellaneous Furnace Fan Baseline ‐                  $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 127               $1 18 281.65     
Miscellaneous Miscellaneous Miscellaneous ‐                  $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 989 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-11
An EnerNOC Company
Table C-3 Energy Efficiency Equipment Data — Multi Family, Existing Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)67                  $93 15 0.62          
Cooling Central AC SEER 15 (CEE Tier 2)133                $185 15 0.61          
Cooling Central AC SEER 16 (CEE Tier 3)187                $278 15 0.57          
Cooling Central AC Ductless Mini‐Split System 245                $2,012 20 0.19          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)32                  $52 10 0.35          
Cooling Room AC EER 11 38                  $141 10 0.15          
Cooling Room AC EER 11.5 52                  $313 10 0.09          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)238                $1,246 15 0.17          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)467                $2,315 15 0.18          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)659                $3,277 15 0.18          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 862                $5,022 20 0.27          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 248                $1,500 14 0.14          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 107                $41 15 3.61          
Water Heating Water Heater Solar 1,539            $5,653 15 0.38          
Interior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting* Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting* Screw‐in CFL 38                  $2 6 10.47       
Interior Lighting* Screw‐in LED 40                  $80 12 0.65          
Interior Lighting* Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting* Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting* Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting* Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting* Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting* Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting* Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting* Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 32.52       
Exterior Lighting* Screw‐in LED 37                  $79 12 1.29          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)23                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 44                  $487 10 0.08          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 93                  $48 13 2.28          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 15                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)19                  $1 9 11.14       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 92                  $89 13 1.09          
Appliances Refrigerator Baseline (2014)123                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)196                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 990 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-12 www.gepllc.com

Table C-3 Energy Efficiency Equipment Data—Multi Family, Existing Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 108                $32 11 2.88          
Appliances Freezer Baseline (2014)145                $0 11 ‐            
Appliances Freezer Energy Star (2014)231                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 93                  $89 13 1.11          
Appliances Second Refrigerator Baseline (2014)124                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)199                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 4                    $2 13 2.99          
Appliances Stove Induction (High Efficiency) 20                  $1,432 13 0.02          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 86                  $1 5 29.28       
Electronics Personal Computers Climate Savers 123                $175 5 0.29          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 43                  $1 11 67.65       
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump ‐                   $85 15 ‐            
Miscellaneous Pool Pump Two‐Speed Pump ‐                   $579 15 ‐            
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 10                  $1 18 21.87       
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 991 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-13
An EnerNOC Company
Table C-4 Energy Efficiency Equipment Data — Mobile Home, Existing Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)80                  $278 15 0.24          
Cooling Central AC SEER 15 (CEE Tier 2)110                $556 15 0.17          
Cooling Central AC SEER 16 (CEE Tier 3)134                $834 15 0.14          
Cooling Central AC Ductless Mini‐Split System 241                $4,399 20 0.08          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)37                  $52 10 0.40          
Cooling Room AC EER 11 44                  $141 10 0.17          
Cooling Room AC EER 11.5 59                  $313 10 0.11          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)282                $1,246 15 0.20          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)387                $2,315 15 0.15          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)475                $3,277 15 0.13          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 852                $5,022 20 0.27          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 295                $1,500 14 0.16          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95)88                  $41 15 2.95          
Water Heating Water Heater Solar 1,271            $5,653 15 0.31          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 13.00       
Interior Lighting*Screw‐in LED 40                  $80 12 0.81          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.04          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.64          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.13          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.70          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 20.19       
Exterior Lighting* Screw‐in LED 37                  $79 12 0.80          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 6.66          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 3.63          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 8.23          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.74          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)46                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 89                  $487 10 0.16          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 99                  $48 13 2.43          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 41                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)54                  $1 9 31.57       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 110                $89 13 1.30          
Appliances Refrigerator Baseline (2014)146                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)234                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 992 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-14 www.gepllc.com

Table C-4 Energy Efficiency Equipment Data — Mobile Home, Existing Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 116                $32 11 3.08          
Appliances Freezer Baseline (2014)155                $0 11 ‐            
Appliances Freezer Energy Star (2014)248                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 113                $89 13 1.34          
Appliances Second Refrigerator Baseline (2014)150                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)241                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 8                    $2 13 6.30          
Appliances Stove Induction (High Efficiency) 41                  $1,432 13 0.04          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 101                $1 5 33.39       
Electronics Personal Computers Climate Savers 144                $175 5 0.33          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 87                  $1 11 133.21     
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 138                $85 15 1.96          
Miscellaneous Pool Pump Two‐Speed Pump 551                $579 15 1.15          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 127                $1 18 281.65     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 993 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-15
An EnerNOC Company
Table C-5 Energy Efficiency Equipment Data — Limited Income, Existing Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)76                  $185 15 0.35          
Cooling Central AC SEER 15 (CEE Tier 2)104                $370 15 0.24          
Cooling Central AC SEER 16 (CEE Tier 3)127                $556 15 0.19          
Cooling Central AC Ductless Mini‐Split System 229                $2,394 20 0.15          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)65                  $104 10 0.35          
Cooling Room AC EER 11 77                  $282 10 0.15          
Cooling Room AC EER 11.5 104                $626 10 0.09          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)192                $1,246 15 0.13          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)263                $2,315 15 0.10          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)323                $3,277 15 0.09          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 579                $5,022 20 0.18          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 201                $1,500 14 0.11          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 116                $41 15 3.94          
Water Heating Water Heater Solar 1,679            $5,653 15 0.41          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 13.85       
Interior Lighting*Screw‐in LED 40                  $80 12 0.86          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 32.52       
Exterior Lighting* Screw‐in LED 37                  $79 12 1.29          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)20                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 38                  $487 10 0.07          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 104                $48 13 2.56          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 12                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)15                  $1 9 9.07          
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 92                  $89 13 1.09          
Appliances Refrigerator Baseline (2014)123                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)196                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 994 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-16 www.gepllc.com

Table C-5 Energy Efficiency Equipment Data — Limited Income, Existing Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 108                $32 11 2.88          
Appliances Freezer Baseline (2014)145                $0 11 ‐            
Appliances Freezer Energy Star (2014)231                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 93                  $89 13 1.11          
Appliances Second Refrigerator Baseline (2014)124                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)199                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 5                    $2 13 3.59          
Appliances Stove Induction (High Efficiency) 24                  $1,432 13 0.02          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 89                  $1 5 30.10       
Electronics Personal Computers Climate Savers 127                $175 5 0.29          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 49                  $1 11 77.80       
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 57                  $85 15 0.83          
Miscellaneous Pool Pump Two‐Speed Pump 226                $579 15 0.49          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 54                  $1 18 123.18     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 995 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-17
An EnerNOC Company
Table C-6 Energy Efficiency Equipment Data —Single Family, New Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)180                $278 15 0.55          
Cooling Central AC SEER 15 (CEE Tier 2)240                $556 15 0.36          
Cooling Central AC SEER 16 (CEE Tier 3)290                $834 15 0.29          
Cooling Central AC Ductless Mini‐Split System 543                $4,399 20 0.19          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)76                  $104 10 0.41          
Cooling Room AC EER 11 90                  $282 10 0.18          
Cooling Room AC EER 11.5 122                $626 10 0.11          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)588                $1,000 15 0.51          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)783                $2,318 15 0.30          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)946                $3,505 15 0.24          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 1,775            $5,655 20 0.54          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 630                $1,500 14 0.35          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 219                $41 15 7.35          
Water Heating Water Heater Geothermal Heat Pump 2,878            $6,586 15 0.60          
Interior Lighting*Water Heater Solar 3,163            $5,653 15 0.77          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 14.05       
Interior Lighting*Screw‐in LED 40                  $80 12 0.87          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Exterior Lighting* Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 21.82       
Exterior Lighting* Screw‐in LED 37                  $79 12 0.87          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)58                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 112                $487 10 0.21          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 117                $48 13 2.86          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 47                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)62                  $1 9 36.25       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 102                $89 13 1.20          
Appliances Refrigerator Baseline (2014)135                $0 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 996 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-18 www.gepllc.com

Table C-6 Energy Efficiency Equipment Data —Single Family, New Vintage (cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Refrigerator Energy Star (2014)217                $89 13 ‐            
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 116                $32 11 3.08          
Appliances Freezer Baseline (2014)155                $0 11 ‐            
Appliances Freezer Energy Star (2014)248                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 116                $89 13 1.37          
Appliances Second Refrigerator Baseline (2014)154                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)247                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 11                  $2 13 8.51          
Appliances Stove Induction (High Efficiency) 56                  $1,432 13 0.06          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 111                $1 5 36.63       
Electronics Personal Computers Climate Savers 158                $175 5 0.36          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 96                  $1 11 148.53     
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 156                $85 15 2.22          
Miscellaneous Pool Pump Two‐Speed Pump 623                $579 15 1.30          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 155                $1 18 345.87     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 997 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-19
An EnerNOC Company
Table C-7 Energy Efficiency Equipment Data — Multi Family, New Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)85                  $93 15 0.78          
Cooling Central AC SEER 15 (CEE Tier 2)166                $185 15 0.76          
Cooling Central AC SEER 16 (CEE Tier 3)234                $278 15 0.71          
Cooling Central AC Ductless Mini‐Split System 308                $2,012 20 0.24          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)37                  $52 10 0.39          
Cooling Room AC EER 11 43                  $141 10 0.17          
Cooling Room AC EER 11.5 59                  $313 10 0.10          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)292                $1,246 15 0.21          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)571                $2,315 15 0.22          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)804                $3,277 15 0.21          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 1,058            $5,022 20 0.33          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 282                $1,500 14 0.15          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 124                $41 15 4.19          
Water Heating Water Heater Solar 1,786            $5,653 15 0.44          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 10.18       
Interior Lighting*Screw‐in LED 40                  $80 12 0.63          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 31.63       
Exterior Lighting* Screw‐in LED 37                  $79 12 1.26          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)26                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 51                  $487 10 0.09          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 105                $48 13 2.56          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 16                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)21                  $1 9 12.38       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 108                $89 13 1.28          
Appliances Refrigerator Baseline (2014)144                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)230                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 998 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-20 www.gepllc.com

Table C-7 Energy Efficiency Equipment Data — Multi Family, New Vintage (cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 115                $32 11 3.06          
Appliances Freezer Baseline (2014)154                $0 11 ‐            
Appliances Freezer Energy Star (2014)246                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 103                $89 13 1.21          
Appliances Second Refrigerator Baseline (2014)137                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)219                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 4                    $2 13 3.31          
Appliances Stove Induction (High Efficiency) 22                  $1,432 13 0.02          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 88                  $1 5 29.69       
Electronics Personal Computers Climate Savers 125                $175 5 0.29          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 45                  $1 11 71.54       
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump ‐                   $85 15 ‐            
Miscellaneous Pool Pump Two‐Speed Pump ‐                   $579 15 ‐            
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 11                  $1 18 24.36       
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 999 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-21
An EnerNOC Company
Table C-8 Energy Efficiency Equipment Data — Mobile Home, New Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)100                $278 15 0.30          
Cooling Central AC SEER 15 (CEE Tier 2)133                $556 15 0.20          
Cooling Central AC SEER 16 (CEE Tier 3)161                $834 15 0.16          
Cooling Central AC Ductless Mini‐Split System 301                $4,399 20 0.11          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)42                  $52 10 0.45          
Cooling Room AC EER 11 50                  $141 10 0.20          
Cooling Room AC EER 11.5 67                  $313 10 0.12          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)313                $1,246 15 0.22          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)417                $2,315 15 0.16          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)505                $3,277 15 0.13          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 946                $5,022 20 0.30          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 336                $1,500 14 0.18          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 102                $41 15 3.42          
Water Heating Water Heater Solar 1,474            $5,653 15 0.36          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 12.64       
Interior Lighting*Screw‐in LED 40                  $80 12 0.79          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.04          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.64          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.13          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.70          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 19.63       
Exterior Lighting* Screw‐in LED 37                  $79 12 0.78          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 6.66          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 3.63          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 8.23          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.74          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)54                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 104                $487 10 0.19          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 111                $48 13 2.73          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 46                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)60                  $1 9 35.11       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 129                $89 13 1.52          
Appliances Refrigerator Baseline (2014)172                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)275                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1000 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-22 www.gepllc.com

Table C-8 Energy Efficiency Equipment Data — Mobile Home, New Vintage (cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 124                $32 11 3.28          
Appliances Freezer Baseline (2014)165                $0 11 ‐            
Appliances Freezer Energy Star (2014)263                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 124                $89 13 1.47          
Appliances Second Refrigerator Baseline (2014)165                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)264                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 9                    $2 13 6.98          
Appliances Stove Induction (High Efficiency) 46                  $1,432 13 0.05          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 103                $1 5 33.86       
Electronics Personal Computers Climate Savers 146                $175 5 0.33          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 91                  $1 11 140.87     
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 154                $85 15 2.20          
Miscellaneous Pool Pump Two‐Speed Pump 617                $579 15 1.29          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 141                $1 18 313.76     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1001 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-23
An EnerNOC Company
Table C-9 Energy Efficiency Equipment Data — Limited Income, New Vintage

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost (/HH) 
Lifetime 
(yrs) BC Ratio
Cooling Central AC SEER 13 ‐                   $0 15 ‐            
Cooling Central AC SEER 14 (Energy Star)95                  $185 15 0.43          
Cooling Central AC SEER 15 (CEE Tier 2)126                $370 15 0.29          
Cooling Central AC SEER 16 (CEE Tier 3)152                $556 15 0.23          
Cooling Central AC Ductless Mini‐Split System 286                $2,394 20 0.18          
Cooling Room AC EER 9.8 ‐                   $0 10 ‐            
Cooling Room AC EER 10.8 (Energy Star)74                  $104 10 0.40          
Cooling Room AC EER 11 87                  $282 10 0.17          
Cooling Room AC EER 11.5 118                $626 10 0.11          
Combined Heating/Cooling Air Source Heat Pump SEER 13 ‐                   $0 15 ‐            
Combined Heating/Cooling Air Source Heat Pump SEER 14 (Energy Star)213                $1,246 15 0.15          
Combined Heating/Cooling Air Source Heat Pump SEER 15 (CEE Tier 2)284                $2,315 15 0.11          
Combined Heating/Cooling Air Source Heat Pump SEER 16 (CEE Tier 3)343                $3,277 15 0.09          
Combined Heating/Cooling Air Source Heat Pump Ductless Mini‐Split System 643                $5,022 20 0.20          
Combined Heating/Cooling Geothermal Heat Pump Standard ‐                   $0 14 ‐            
Combined Heating/Cooling Geothermal Heat Pump High Efficiency 228                $1,500 14 0.13          
Space Heating Electric Resistance Electric Resistance ‐                   $0 20 ‐            
Space Heating Electric Furnace 3400 BTU/KW ‐                   $0 15 ‐            
Space Heating Supplemental Supplemental ‐                   $0 5 ‐            
Water Heating Water Heater Baseline (EF=0.90)‐                   $0 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 135                $41 15 4.57          
Water Heating Water Heater Solar 1,949            $5,653 15 0.48          
Interior Lighting*Screw‐in Incandescent  ‐                   $0 4 ‐            
Interior Lighting*Screw‐in Infrared Halogen 14                  $4 5 ‐            
Interior Lighting*Screw‐in CFL 38                  $2 6 13.47       
Interior Lighting*Screw‐in LED 40                  $80 12 0.84          
Interior Lighting*Linear Fluorescent T12 ‐                   $0 6 ‐            
Interior Lighting*Linear Fluorescent T8 6                    ($1) 6 1.00          
Interior Lighting*Linear Fluorescent Super T8 6                    $7 6 1.16          
Interior Lighting*Linear Fluorescent T5 10                  $10 6 0.71          
Interior Lighting*Linear Fluorescent LED 18                  $55 10 0.14          
Interior Lighting*Pin‐based Halogen ‐                   $0 4 ‐            
Interior Lighting*Pin‐based CFL 13                  $4 6 1.00          
Interior Lighting*Pin‐based LED 14                  $17 10 0.77          
Exterior Lighting* Screw‐in Incandescent  ‐                   $0 4 ‐            
Exterior Lighting* Screw‐in Infrared Halogen 12                  $4 5 ‐            
Exterior Lighting* Screw‐in CFL 27                  $3 6 31.63       
Exterior Lighting* Screw‐in LED 37                  $79 12 1.26          
Exterior Lighting* High Intensity/Flood Incandescent ‐                   $0 4 ‐            
Exterior Lighting* High Intensity/Flood Infrared Halogen 34                  $4 4 ‐            
Exterior Lighting* High Intensity/Flood CFL 60                  $4 5 7.40          
Exterior Lighting* High Intensity/Flood Metal Halide 22                  $31 5 4.03          
Exterior Lighting* High Intensity/Flood High Pressure Sodium 22                  $23 5 9.14          
Exterior Lighting* High Intensity/Flood LED 66                  $79 10 0.82          
Appliances Clothes Washer Baseline ‐                   $0 10 ‐            
Appliances Clothes Washer Energy Star (MEF > 1.8)23                  $0 10 1.00          
Appliances Clothes Washer Horizontal Axis 44                  $487 10 0.08          
Appliances Clothes Dryer Baseline ‐                   $0 13 ‐            
Appliances Clothes Dryer Moisture Detection 117                $48 13 2.87          
Appliances Dishwasher Baseline ‐                   $0 9 ‐            
Appliances Dishwasher Energy Star 13                  $1 9 ‐            
Appliances Dishwasher Energy Star (2011)17                  $1 9 10.08       
Appliances Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Refrigerator Energy Star 108                $89 13 1.28          
Appliances Refrigerator Baseline (2014)144                $0 13 ‐            
Appliances Refrigerator Energy Star (2014)230                $89 13 ‐            
* Savings and costs are per unit, e.g., per lamp
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1002 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-24 www.gepllc.com

Table C-9 Energy Efficiency Equipment Data — Limited Income, New Vintage
(cont.)

End Use Technology Efficiency Definition
Savings 
(kWh/yr/HH)
 Incremental 
Cost ($/HH) 
Lifetime 
(yrs) BC Ratio
Appliances Freezer Baseline ‐                   $0 11 ‐            
Appliances Freezer Energy Star 115                $32 11 3.06          
Appliances Freezer Baseline (2014)154                $0 11 ‐            
Appliances Freezer Energy Star (2014)246                $32 11 ‐            
Appliances Second Refrigerator Baseline ‐                   $0 13 ‐            
Appliances Second Refrigerator Energy Star 103                $89 13 1.21          
Appliances Second Refrigerator Baseline (2014)137                $0 13 ‐            
Appliances Second Refrigerator Energy Star (2014)219                $89 13 ‐            
Appliances Stove Baseline ‐                   $0 13 ‐            
Appliances Stove Convection Oven 5                    $2 13 3.98          
Appliances Stove Induction (High Efficiency) 26                  $1,432 13 0.03          
Appliances Microwave Baseline ‐                   $0 9 ‐            
Electronics Personal Computers Baseline ‐                   $0 5 ‐            
Electronics Personal Computers Energy Star 90                  $1 5 30.52       
Electronics Personal Computers Climate Savers 129                $175 5 0.30          
Electronics TVs Baseline ‐                   $0 11 ‐            
Electronics TVs Energy Star 52                  $1 11 82.28       
Electronics Devices and Gadgets Devices and Gadgets ‐                   $0 5 ‐            
Miscellaneous Pool Pump Baseline Pump ‐                   $0 15 ‐            
Miscellaneous Pool Pump High Efficiency Pump 63                  $85 15 0.93          
Miscellaneous Pool Pump Two‐Speed Pump 254                $579 15 0.54          
Miscellaneous Furnace Fan Baseline ‐                   $0 18 ‐            
Miscellaneous Furnace Fan Furnace Fan with ECM 60                  $1 18 137.23     
Miscellaneous Miscellaneous Miscellaneous ‐                   $0 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1003 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-25
An EnerNOC Company
Table C-10 Energy-Efficiency Measure Data—Single Family, Existing Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Early Replacement Cooling 10% 0% 0% 8% $2,895 15 0.05
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 41% 100% $125 4 0.70
Room AC ‐ Removal of Second Unit Cooling 100% 0% 0% 25% $75 5 2.45
Attic Fan ‐ Installation Cooling 1% 0% 12% 23% $116 18 0.08
Attic Fan ‐ Photovoltaic ‐ Installation Cooling 1% 0% 13% 45% $350 19 0.06
Ceiling Fan ‐ Installation Cooling 11% 0% 51% 75% $160 15 0.81
Whole‐House Fan ‐ Installation Cooling 9% 0% 7% 19% $200 18 0.62
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 1.49
Insulation ‐ Ducting Cooling 3% 0% 15% 75% $500 18 0.78
Insulation ‐ Ducting Space Heating 4% 4% 15% 75% $500 18 0.78
Repair and Sealing ‐ Ducting Cooling 10% 0% 12% 50% $500 18 2.08
Repair and Sealing ‐ Ducting Space Heating 15% 15% 12% 50% $500 18 2.08
Thermostat ‐ Clock/Programmable Cooling 8% 0% 55% 56% $114 11 2.89
Thermostat ‐ Clock/Programmable Space Heating 9% 5% 55% 56% $114 11 2.89
Doors ‐ Storm and Thermal Cooling 1% 0% 38% 75% $320 12 0.25
Doors ‐ Storm and Thermal Space Heating 2% 2% 38% 75% $320 12 0.25
Insulation ‐ Infiltration Control Cooling 3% 0% 46% 90% $266 12 1.72
Insulation ‐ Infiltration Control Space Heating 10% 10% 46% 90% $266 12 1.72
Insulation ‐ Ceiling Cooling 3% 0% 68% 72% $594 20 1.11
Insulation ‐ Ceiling Space Heating 10% 5% 68% 72% $594 20 1.11
Insulation ‐ Radiant Barrier Cooling 5% 0% 5% 90% $923 12 0.41
Insulation ‐ Radiant Barrier Space Heating 2% 1% 5% 90% $923 12 0.41
Roofs ‐ High Reflectivity Cooling 6% 0% 5% 10% $1,550 15 0.05
Windows ‐ Reflective Film Cooling 7% 0% 5% 45% $267 10 0.21
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 83% 90% $7,500 25 0.38
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 83% 90% $7,500 25 0.38
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 24% 25% $750 15 0.10
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 80% $2,975 15 0.03
Exterior Lighting ‐ Photosensor Control Exterior Lighting 15% 0% 24% 45% $90 8 0.21
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 10% 45% $72 8 0.35
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 53% 90% $24 25 8.78
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 17% 38% $180 13 1.05
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 75% 80% $96 10 4.56
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 54% 75% $15 10 15.53
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 17% 75% $40 5 2.99
Water Heater ‐ Timer Water Heating 8% 4% 17% 40% $194 10 1.06
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 3.28
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 1.76
Refrigerator ‐ Early Replacement Appliances 15% 15% 0% 20% $1,203 13 0.08
Refrigerator ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.99
Freezer ‐ Early Replacement Appliances 15% 15% 0% 20% $484 11 0.18
Freezer ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.76
Home Energy Management System Cooling 10% 0% 20% 38% $300 20 2.46
Home Energy Management System Space Heating 10% 5% 20% 38% $300 20 2.46
Home Energy Management System Interior Lighting 10% 5% 20% 38% $300 20 2.46
Photovoltaics Cooling 50% 0% 0% 48% $17,000 15 0.10
Photovoltaics Space Heating 25% 25% 0% 48% $17,000 15 0.10
Pool ‐ Pump Timer Miscellaneous 60% 0% 59% 90% $160 15 4.92
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.43
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 25% $1,500 15 0.75
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $3,675 15 1.22
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $13,769 15 0.95
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1004 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-26 www.gepllc.com

Table C-11 Energy-Efficiency Measure Data — Multi Family, Existing Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Early Replacement Cooling 10% 0% 0% 8% $2,895 15 0.02
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 33% 100% $100 4 0.59
Room AC ‐ Removal of Second Unit Cooling 100% 0% 0% 25% $75 5 1.28
Ceiling Fan ‐ Installation Cooling 11% 0% 32% 75% $80 15 0.49
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $100 4 1.05
Insulation ‐ Ducting Cooling 3% 0% 13% 75% $375 18 1.16
Insulation ‐ Ducting Space Heating 4% 4% 13% 75% $375 18 1.16
Repair and Sealing ‐ Ducting Cooling 4% 0% 12% 50% $500 18 0.95
Repair and Sealing ‐ Ducting Space Heating 4% 4% 12% 50% $500 18 0.95
Thermostat ‐ Clock/Programmable Cooling 8% 0% 27% 68% $114 11 2.39
Thermostat ‐ Clock/Programmable Space Heating 6% 3% 27% 68% $114 11 2.39
Doors ‐ Storm and Thermal Cooling 1% 0% 17% 75% $320 12 0.35
Doors ‐ Storm and Thermal Space Heating 2% 2% 17% 75% $320 12 0.35
Insulation ‐ Infiltration Control Cooling 1% 0% 19% 90% $266 12 2.95
Insulation ‐ Infiltration Control Space Heating 13% 13% 19% 90% $266 12 2.95
Insulation ‐ Ceiling Cooling 13% 0% 27% 30% $215 20 5.67
Insulation ‐ Ceiling Space Heating 13% 13% 27% 30% $215 20 5.67
Insulation ‐ Radiant Barrier Cooling 4% 0% 5% 90% $923 12 0.52
Insulation ‐ Radiant Barrier Space Heating 4% 4% 5% 90% $923 12 0.52
Roofs ‐ High Reflectivity Cooling 13% 0% 3% 10% $1,550 15 0.03
Windows ‐ Reflective Film Cooling 7% 0% 5% 45% $167 10 0.10
Windows ‐ High Efficiency/Energy Star Cooling 13% 0% 70% 90% $2,500 25 0.56
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 70% 90% $2,500 25 0.56
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 6% 10% $256 15 0.14
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 50% $2,975 15 0.00
Exterior Lighting ‐ Photosensor Control Exterior Lighting 20% 0% 7% 45% $90 8 0.04
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 6% 45% $72 8 0.05
Water Heater ‐ Faucet Aerators Water Heating 5% 2% 43% 90% $24 25 6.63
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 6% 38% $180 13 0.65
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 71% 75% $96 10 2.84
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 54% 75% $15 10 9.66
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 17% 75% $40 5 1.86
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.66
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 2.04
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 0.58
Refrigerator ‐ Early Replacement Appliances 15% 15% 0% 20% $1,203 13 0.07
Refrigerator ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.36
Freezer ‐ Early Replacement Appliances 15% 15% 0% 20% $484 11 0.17
Freezer ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.57
Home Energy Management System Cooling 10% 0% 5% 13% $300 20 2.46
Home Energy Management System Space Heating 10% 5% 5% 13% $300 20 2.46
Home Energy Management System Interior Lighting 10% 5% 5% 13% $300 20 2.46
Photovoltaics Cooling 50% 0% 0% 12% $8,500 15 0.22
Photovoltaics Space Heating 25% 25% 0% 12% $8,500 15 0.22
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.13
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 10% $1,500 15 0.47
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,845 15 0.99
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $10,946 15 0.72
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1005 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-27
An EnerNOC Company
Table C-12 Energy-Efficiency Measure Data — Mobile Home, Existing Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Early Replacement Cooling 10% 0% 0% 8% $2,895 15 0.03
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 59% 100% $100 4 0.63
Room AC ‐ Removal of Second Unit Cooling 100% 0% 0% 25% $75 5 1.46
Ceiling Fan ‐ Installation Cooling 11% 0% 60% 75% $80 15 0.79
Whole‐House Fan ‐ Installation Cooling 9% 0% 5% 19% $150 18 0.41
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 1.02
Insulation ‐ Ducting Cooling 3% 0% 15% 75% $375 18 0.94
Insulation ‐ Ducting Space Heating 4% 4% 15% 75% $375 18 0.94
Repair and Sealing ‐ Ducting Cooling 10% 0% 12% 50% $500 18 2.08
Repair and Sealing ‐ Ducting Space Heating 15% 15% 12% 50% $500 18 2.08
Thermostat ‐ Clock/Programmable Cooling 8% 0% 51% 56% $114 11 2.78
Thermostat ‐ Clock/Programmable Space Heating 9% 5% 51% 56% $114 11 2.78
Doors ‐ Storm and Thermal Cooling 1% 0% 38% 75% $320 12 0.25
Doors ‐ Storm and Thermal Space Heating 2% 2% 38% 75% $320 12 0.25
Insulation ‐ Infiltration Control Cooling 3% 0% 46% 90% $266 12 1.80
Insulation ‐ Infiltration Control Space Heating 10% 10% 46% 90% $266 12 1.80
Insulation ‐ Ceiling Cooling 3% 0% 79% 81% $707 20 1.00
Insulation ‐ Ceiling Space Heating 10% 5% 79% 81% $707 20 1.00
Insulation ‐ Radiant Barrier Cooling 2% 0% 5% 90% $923 12 0.35
Insulation ‐ Radiant Barrier Space Heating 1% 1% 5% 90% $923 12 0.35
Roofs ‐ High Reflectivity Cooling 6% 0% 5% 10% $1,550 15 0.02
Windows ‐ Reflective Film Cooling 7% 0% 5% 45% $167 10 0.16
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 47% 90% $7,500 25 0.37
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 47% 90% $7,500 25 0.37
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 67% 72% $750 15 0.09
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 80% $2,975 15 0.03
Exterior Lighting ‐ Photosensor Control Exterior Lighting 15% 0% 23% 45% $90 8 0.19
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 10% 45% $72 8 0.32
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 79% 90% $24 25 4.47
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 17% 38% $180 13 0.53
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 92% 95% $96 10 2.32
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 54% 75% $15 10 7.91
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 17% 75% $40 5 1.52
Water Heater ‐ Timer Water Heating 8% 4% 17% 40% $194 10 0.54
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 1.67
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 1.65
Refrigerator ‐ Early Replacement Appliances 15% 15% 0% 20% $1,203 13 0.08
Refrigerator ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 4.06
Freezer ‐ Early Replacement Appliances 15% 15% 0% 20% $484 11 0.18
Freezer ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.82
Home Energy Management System Cooling 10% 0% 20% 38% $300 20 2.28
Home Energy Management System Space Heating 10% 5% 20% 38% $300 20 2.28
Home Energy Management System Interior Lighting 10% 5% 20% 38% $300 20 2.28
Photovoltaics Cooling 50% 0% 0% 48% $17,000 15 0.09
Photovoltaics Space Heating 25% 25% 0% 48% $17,000 15 0.09
Pool ‐ Pump Timer Miscellaneous 60% 0% 50% 90% $160 15 4.92
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.21
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 10% $1,500 15 0.38
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,616 15 0.88
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $11,135 15 0.62
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1006 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-28 www.gepllc.com

Table C-13 Energy-Efficiency Measure Data — Limited Income, Existing Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Early Replacement Cooling 10% 0% 0% 8% $2,895 15 0.03
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 25% 100% $100 4 0.61
Room AC ‐ Removal of Second Unit Cooling 100% 0% 0% 25% $75 5 2.56
Attic Fan ‐ Installation Cooling 1% 0% 3% 23% $116 18 0.05
Attic Fan ‐ Photovoltaic ‐ Installation Cooling 1% 0% 2% 11% $350 19 0.03
Ceiling Fan ‐ Installation Cooling 11% 0% 41% 75% $80 15 0.89
Whole‐House Fan ‐ Installation Cooling 9% 0% 5% 19% $150 18 0.46
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 0.82
Insulation ‐ Ducting Cooling 3% 0% 13% 75% $395 18 0.90
Insulation ‐ Ducting Space Heating 4% 4% 13% 75% $395 18 0.90
Repair and Sealing ‐ Ducting Cooling 10% 0% 12% 50% $500 18 2.07
Repair and Sealing ‐ Ducting Space Heating 15% 15% 12% 50% $500 18 2.07
Thermostat ‐ Clock/Programmable Cooling 8% 0% 27% 68% $114 11 2.63
Thermostat ‐ Clock/Programmable Space Heating 9% 5% 27% 68% $114 11 2.63
Doors ‐ Storm and Thermal Cooling 1% 0% 17% 75% $320 12 0.25
Doors ‐ Storm and Thermal Space Heating 2% 2% 17% 75% $320 12 0.25
Insulation ‐ Infiltration Control Cooling 3% 0% 19% 90% $266 12 1.78
Insulation ‐ Infiltration Control Space Heating 10% 10% 19% 90% $266 12 1.78
Insulation ‐ Ceiling Cooling 3% 0% 36% 41% $215 20 2.44
Insulation ‐ Ceiling Space Heating 10% 5% 36% 41% $215 20 2.44
Insulation ‐ Radiant Barrier Cooling 2% 0% 5% 90% $923 12 0.35
Insulation ‐ Radiant Barrier Space Heating 1% 1% 5% 90% $923 12 0.35
Roofs ‐ High Reflectivity Cooling 6% 0% 3% 10% $1,550 15 0.03
Windows ‐ Reflective Film Cooling 7% 0% 5% 45% $167 10 0.18
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 68% 90% $2,500 25 0.51
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 68% 90% $2,500 25 0.51
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 8% 10% $256 15 0.16
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 50% 10% 50% $2,975 15 0.01
Exterior Lighting ‐ Photosensor Control Exterior Lighting 15% 0% 8% 45% $90 8 0.06
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 6% 45% $72 8 0.10
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 46% 90% $24 25 5.95
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 6% 38% $180 13 0.71
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 73% 75% $96 10 3.09
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 54% 75% $15 10 10.53
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 17% 75% $40 5 2.03
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.72
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 2.23
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 0.77
Refrigerator ‐ Early Replacement Appliances 15% 15% 0% 20% $1,203 13 0.07
Refrigerator ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.36
Freezer ‐ Early Replacement Appliances 15% 15% 0% 20% $484 11 0.17
Freezer ‐ Remove Second Unit Appliances 100% 100% 0% 25% $75 5 3.57
Home Energy Management System Cooling 10% 0% 5% 13% $300 20 2.00
Home Energy Management System Space Heating 10% 5% 5% 13% $300 20 2.00
Home Energy Management System Interior Lighting 10% 5% 5% 13% $300 20 2.00
Photovoltaics Cooling 50% 0% 0% 48% $8,500 15 0.17
Photovoltaics Space Heating 25% 25% 0% 48% $8,500 15 0.17
Pool ‐ Pump Timer Miscellaneous 60% 0% 50% 90% $160 15 2.02
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.24
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 20% $1,500 15 0.51
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,970 15 1.03
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $10,798 15 0.69
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1007 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-29
An EnerNOC Company
Table C-14 Energy-Efficiency Measure Data — Single Family, New Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 41% 100% $125 4 0.78
Attic Fan ‐ Installation Cooling 1% 0% 13% 23% $97 18 0.15
Attic Fan ‐ Photovoltaic ‐ Installation Cooling 1% 0% 4% 11% $200 19 0.15
Ceiling Fan ‐ Installation Cooling 10% 0% 53% 75% $160 15 1.09
Whole‐House Fan ‐ Installation Cooling 9% 0% 4% 19% $200 18 0.92
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 1.69
Insulation ‐ Ducting Cooling 3% 0% 50% 75% $250 18 1.31
Insulation ‐ Ducting Space Heating 4% 4% 50% 75% $250 18 1.31
Thermostat ‐ Clock/Programmable Cooling 8% 0% 91% 95% $114 11 2.91
Thermostat ‐ Clock/Programmable Space Heating 8% 4% 91% 95% $114 11 2.91
Doors ‐ Storm and Thermal Cooling 1% 0% 13% 75% $180 12 0.45
Doors ‐ Storm and Thermal Space Heating 2% 2% 13% 75% $180 12 0.45
Insulation ‐ Ceiling Cooling 3% 0% 68% 71% $634 20 0.99
Insulation ‐ Ceiling Space Heating 8% 6% 68% 71% $634 20 0.99
Insulation ‐ Radiant Barrier Cooling 2% 0% 25% 90% $923 12 0.37
Insulation ‐ Radiant Barrier Space Heating 1% 1% 25% 90% $923 12 0.37
Insulation ‐ Foundation Cooling 3% 0% 20% 90% $358 20 1.35
Insulation ‐ Foundation Space Heating 6% 6% 20% 90% $358 20 1.35
Insulation ‐ Wall Cavity Cooling 2% 0% 20% 90% $236 20 1.15
Insulation ‐ Wall Cavity Space Heating 3% 3% 20% 90% $236 20 1.15
Insulation ‐ Wall Sheathing Cooling 1% 0% 64% 90% $300 20 0.89
Insulation ‐ Wall Sheathing Space Heating 3% 3% 64% 90% $300 20 0.89
Roofs ‐ High Reflectivity Cooling 5% 0% 5% 90% $517 15 0.17
Windows ‐ Reflective Film Cooling 7% 0% 2% 45% $267 10 0.31
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 100% 100% $2,200 25 0.62
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 100% 100% $2,200 25 0.62
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 24% 27% $500 15 0.16
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 80% $2,975 15 0.04
Exterior Lighting ‐ Photosensor Control Exterior Lighting 13% 0% 13% 45% $90 8 0.19
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 16% 45% $72 8 0.36
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 38% 90% $24 25 11.03
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 8% 41% $50 13 4.71
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 90% 95% $48 10 11.33
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $15 10 19.30
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 5% 75% $40 5 3.70
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 1.31
Water Heater ‐ Drainwater Heat Reocvery Water Heating 9% 5% 1% 90% $899 15 0.47
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 4.06
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 1.99
Home Energy Management System Cooling 10% 0% 20% 68% $250 20 3.16
Home Energy Management System Space Heating 10% 5%20% 68% $250 20 3.16
Home Energy Management System Interior Lighting 10% 5% 20% 68% $250 20 3.16
Photovoltaics Cooling 50% 0% 1% 48% $15,800 15 0.12
Photovoltaics Space Heating 25% 25% 1% 48% $15,800 15 0.12
Pool ‐ Pump Timer Miscellaneous 60% 0% 55% 90% $160 15 5.43
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.64
Advanced New Construction Designs Cooling 40% 0% 2% 45% $4,500 18 1.09
Advanced New Construction Designs Space Heating 40% 40% 2% 45% $4,500 18 1.09
Advanced New Construction Designs Interior Lighting 20% 20% 2% 45% $4,500 18 1.09
Energy Star Homes Cooling 20% 0% 12% 75% $5,000 18 0.75
Energy Star Homes Space Heating 20% 20% 12% 75% $5,000 18 0.75
Energy Star Homes Interior Lighting 20% 20% 12% 75% $5,000 18 0.75
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 25% $1,500 15 0.94
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $3,675 15 1.53
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $13,769 15 1.14
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1008 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-30 www.gepllc.com

Table C-15 Energy-Efficiency Measure Data — Multi Family, New Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 33% 100% $100 4 0.62
Ceiling Fan ‐ Installation Cooling 10% 0% 18% 75% $80 15 0.77
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $100 4 1.12
Insulation ‐ Ducting Cooling 2% 0% 50% 75% $200 18 1.18
Insulation ‐ Ducting Space Heating 2% 2% 50% 75% $200 18 1.18
Thermostat ‐ Clock/Programmable Cooling 8% 0% 77% 80% $114 11 2.29
Thermostat ‐ Clock/Programmable Space Heating 5% 3% 77% 80% $114 11 2.29
Doors ‐ Storm and Thermal Cooling 1% 0% 19% 75% $180 12 0.66
Doors ‐ Storm and Thermal Space Heating 2% 2% 19% 75% $180 12 0.66
Insulation ‐ Ceiling Cooling 12% 0% 27% 48% $152 20 10.12
Insulation ‐ Ceiling Space Heating 16% 16% 27% 48% $152 20 10.12
Insulation ‐ Radiant Barrier Cooling 2% 0% 5% 90% $923 12 0.50
Insulation ‐ Radiant Barrier Space Heating 3% 3% 5% 90% $923 12 0.50
Insulation ‐ Wall Cavity Cooling 2% 0% 4% 90% $63 20 6.14
Insulation ‐ Wall Cavity Space Heating 4% 4% 4% 90% $63 20 6.14
Insulation ‐ Wall Sheathing Cooling 1% 0% 55% 90% $210 20 1.59
Insulation ‐ Wall Sheathing Space Heating 3% 3% 55% 90% $210 20 1.59
Roofs ‐ High Reflectivity Cooling 8% 0% 0% 90% $517 15 0.10
Windows ‐ Reflective Film Cooling 7% 0% 2% 45% $167 10 0.17
Windows ‐ High Efficiency/Energy Star Cooling 13% 0% 100% 100% $2,200 25 0.63
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 100% 100% $2,200 25 0.63
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 6% 9% $256 15 0.14
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 0% 10% 50% $2,975 15 0.01
Exterior Lighting ‐ Photosensor Control Exterior Lighting 20% 0% 1% 45% $90 8 0.04
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 11% 45% $72 8 0.05
Water Heater ‐ Faucet Aerators Water Heating 5% 2% 11% 90% $24 25 7.63
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 41% $50 13 2.68
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 66% 75% $48 10 6.45
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $15 10 10.99
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 5% 75% $40 5 2.11
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.75
Water Heater ‐ Drainwater Heat Reocvery Water Heating 9% 5% 1% 90% $899 15 0.27
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 2.31
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 0.63
Home Energy Management System Cooling 10% 0% 5% 68% $250 20 3.19
Home Energy Management System Space Heating 10% 5% 5% 68% $250 20 3.19
Home Energy Management System Interior Lighting 10% 5% 5% 68% $250 20 3.19
Photovoltaics Cooling 50% 0% 0% 12% $7,900 15 0.26
Photovoltaics Space Heating 25% 25% 0% 12% $7,900 15 0.26
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.23
Advanced New Construction Designs Cooling 40% 0% 2% 45% $2,500 18 1.47
Advanced New Construction Designs Space Heating 40% 40% 2% 45% $2,500 18 1.47
Advanced New Construction Designs Interior Lighting 20% 20% 2% 45% $2,500 18 1.47
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 10% $1,500 15 0.53
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,845 15 1.13
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $10,946 15 0.84
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1009 of 1069
Residential Energy Efficiency Equipment and Measure Data
Global Energy Partners C-31
An EnerNOC Company
Table C-16 Energy-Efficiency Measure Data — Mobile Home, New Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 59% 100% $100 4 0.66
Ceiling Fan ‐ Installation Cooling 10% 0% 57% 75% $80 15 0.95
Whole‐House Fan ‐ Installation Cooling 9% 0% 4% 19% $150 18 0.53
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 1.09
Insulation ‐ Ducting Cooling 3% 0% 50% 75% $200 18 1.59
Insulation ‐ Ducting Space Heating 4% 4% 50% 75% $200 18 1.59
Thermostat ‐ Clock/Programmable Cooling 8% 0% 57% 75% $114 11 2.77
Thermostat ‐ Clock/Programmable Space Heating 8% 4% 57% 75% $114 11 2.77
Doors ‐ Storm and Thermal Cooling 1% 0% 13% 75% $180 12 0.49
Doors ‐ Storm and Thermal Space Heating 2% 2% 13% 75% $180 12 0.49
Insulation ‐ Ceiling Cooling 3% 0% 79% 81% $176 20 3.02
Insulation ‐ Ceiling Space Heating 8% 6% 79% 81% $176 20 3.02
Insulation ‐ Radiant Barrier Cooling 2% 0% 25% 90% $923 12 0.36
Insulation ‐ Radiant Barrier Space Heating 1% 1% 25% 90% $923 12 0.36
Insulation ‐ Wall Cavity Cooling 2% 0% 20% 90% $197 20 1.35
Insulation ‐ Wall Cavity Space Heating 3% 3% 20% 90% $197 20 1.35
Insulation ‐ Wall Sheathing Cooling 1% 0% 64% 90% $300 20 0.96
Insulation ‐ Wall Sheathing Space Heating 3% 3% 64% 90% $300 20 0.96
Roofs ‐ High Reflectivity Cooling 5% 0% 5% 90% $517 15 0.07
Windows ‐ Reflective Film Cooling 7% 0% 2% 45% $167 10 0.21
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 85% 90% $2,200 25 0.57
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 85% 90% $2,200 25 0.57
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 67% 72% $500 15 0.14
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 50% 10% 80% $2,975 15 0.03
Exterior Lighting ‐ Photosensor Control Exterior Lighting 13% 0% 13% 45% $90 8 0.17
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 16% 45% $72 8 0.32
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 57% 90% $24 25 5.14
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 8% 41% $50 13 2.20
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 92% 95% $48 10 5.28
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $15 10 9.00
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 5% 75% $40 5 1.72
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.61
Water Heater ‐ Drainwater Heat Reocvery Water Heating 9% 5% 1% 90% $899 15 0.22
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 1.89
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 1.79
Home Energy Management System Cooling 10% 0% 20% 68% $250 20 2.94
Home Energy Management System Space Heating 10% 5% 20% 68% $250 20 2.94
Home Energy Management System Interior Lighting 10% 5% 20% 68% $250 20 2.94
Photovoltaics Cooling 50% 0% 1% 48% $15,800 15 0.10
Photovoltaics Space Heating 25% 25% 1% 48% $15,800 15 0.10
Pool ‐ Pump Timer Miscellaneous 60% 0% 35% 90% $160 15 5.38
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.28
Advanced New Construction Designs Cooling 30% 0% 2% 45% $4,500 18 0.52
Advanced New Construction Designs Space Heating 30% 30% 2% 45% $4,500 18 0.52
Advanced New Construction Designs Interior Lighting 20% 20% 2% 45% $4,500 18 0.52
Energy Efficient Manufactured Homes Cooling 20% 0% 10% 75% $3,500 18 0.88
Energy Efficient Manufactured Homes Space Heating 20% 20% 10% 75% $3,500 18 0.88
Energy Efficient Manufactured Homes Interior Lighting 20% 20% 10% 75% $3,500 18 0.88
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 10% $1,500 15 0.44
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,616 15 1.00
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $11,738 15 0.69
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1010 of 1069
Residential Energy Efficiency Equipment and Measure Data

C-32 www.gepllc.com

Table C-17 Energy-Efficiency Measure Data — Limited Income, New Vintage
  Note: Costs are per household. 

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Central AC ‐ Maintenance and Tune‐Up Cooling 10% 0% 25% 100% $100 4 0.65
Attic Fan ‐ Installation Cooling 1% 0% 15% 23% $97 18 0.07
Attic Fan ‐ Photovoltaic ‐ Installation Cooling 1% 0% 5% 11% $200 19 0.07
Ceiling Fan ‐ Installation Cooling 10% 0% 33% 75% $80 15 1.03
Whole‐House Fan ‐ Installation Cooling 9% 0% 4% 19% $150 18 0.58
Air Source Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 25% 90% $125 4 0.87
Insulation ‐ Ducting Cooling 3% 0% 50% 75% $210 18 1.47
Insulation ‐ Ducting Space Heating 4% 4% 50% 75% $210 18 1.47
Thermostat ‐ Clock/Programmable Cooling 8% 0% 29% 30% $114 11 2.54
Thermostat ‐ Clock/Programmable Space Heating 8% 4% 29% 30% $114 11 2.54
Doors ‐ Storm and Thermal Cooling 1% 0% 19% 75% $180 12 0.46
Doors ‐ Storm and Thermal Space Heating 2% 2% 19% 75% $180 12 0.46
Insulation ‐ Ceiling Cooling 3% 0% 36% 48% $152 20 3.20
Insulation ‐ Ceiling Space Heating 8% 6% 36% 48% $152 20 3.20
Insulation ‐ Radiant Barrier Cooling 2% 0% 5% 90% $923 12 0.36
Insulation ‐ Radiant Barrier Space Heating 1% 1% 5% 90% $923 12 0.36
Insulation ‐ Foundation Cooling 3% 0% 4% 90% $358 20 1.37
Insulation ‐ Foundation Space Heating 6% 6% 4% 90% $358 20 1.37
Insulation ‐ Wall Cavity Cooling 2% 0% 4% 90% $63 20 3.46
Insulation ‐ Wall Cavity Space Heating 3% 3% 4% 90% $63 20 3.46
Insulation ‐ Wall Sheathing Cooling 1% 0% 59% 90% $210 20 1.19
Insulation ‐ Wall Sheathing Space Heating 3% 3% 59% 90% $210 20 1.19
Roofs ‐ High Reflectivity Cooling 5% 0% 0% 90% $517 15 0.08
Windows ‐ Reflective Film Cooling 7% 0% 2% 45% $167 10 0.23
Windows ‐ High Efficiency/Energy Star Cooling 12% 0% 78% 90% $2,200 25 0.55
Windows ‐ High Efficiency/Energy Star Space Heating 7% 5% 78% 90% $2,200 25 0.55
Interior Lighting ‐ Occupancy Sensor Interior Lighting 9% 5% 8% 9% $256 15 0.17
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 50% 50% 10% 50% $2,975 15 0.01
Exterior Lighting ‐ Photosensor Control Exterior Lighting 13% 0% 0% 45% $90 8 0.06
Exterior Lighting ‐ Timeclock Installation Exterior Lighting 20% 0% 11% 45% $72 8 0.10
Water Heater ‐ Faucet Aerators Water Heating 4% 2% 11% 90% $24 25 6.84
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 41% $50 13 2.92
Water Heater ‐ Low Flow Showerheads Water Heating 17% 9% 21% 75% $48 10 7.03
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $15 10 11.97
Water Heater ‐ Thermostat Setback Water Heating 9% 5% 5% 75% $40 5 2.29
Water Heater ‐ Timer Water Heating 8% 4% 5% 40% $194 10 0.81
Water Heater ‐ Drainwater Heat Reocvery Water Heating 9% 5% 1% 90% $899 15 0.29
Water Heater ‐ Hot Water Saver Water Heating 9% 4% 5% 50% $35 5 2.52
Electronics ‐ Reduce Standby Wattage Electronics 5% 5% 5% 90% $20 8 0.83
Home Energy Management System Cooling 10% 0% 5% 68% $250 20 2.50
Home Energy Management System Space Heating 10% 5%5% 68% $250 20 2.50
Home Energy Management System Interior Lighting 10% 5% 5% 68% $250 20 2.50
Photovoltaics Cooling 50% 0% 0% 48% $7,900 15 0.20
Photovoltaics Space Heating 25% 25% 0% 48% $7,900 15 0.20
Pool ‐ Pump Timer Miscellaneous 60% 0% 35% 90% $160 15 2.21
Trees for Shading Cooling 1% 0% 10% 68% $40 20 0.30
Advanced New Construction Designs Cooling 30% 0% 2% 45% $2,500 18 1.25
Advanced New Construction Designs Space Heating 30% 30% 2% 45% $2,500 18 1.25
Advanced New Construction Designs Interior Lighting 20% 20% 2% 45% $2,500 18 1.25
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 20% $1,500 15 0.58
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $2,970 15 1.18
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 45% $10,798 15 0.81
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1011 of 1069

Global Energy Partners D-1
An EnerNOC Company

APPENDIX D
COMMERCIAL ENERGY EFFICIENCY EQUIPMENT AND MEASURE DATA
This appendix presents detailed information for all commercial and industrial energy efficiency
equipment and measures that were evaluated in LoadMAP. Several sets of tables are provided.
Table D-1 provides brief descriptions for all equipment and measures that were assessed for
potenital.
Tables D-2 through D-9 list the detailed unit-level data for the equipment measures for each of
the C&I segments — small/medium commercial, large commercial, extra-large commercial, and
extra-large industial — and for existing and new construction, respectively. Savings are in
kWh/yr/sq.ft., and incremental costs are in $/sq.ft. The B/C ratio is zero if the measure
represents the baseline technology or if the technology is not available in the first year of the
forecast (2012). The B/C ratio is calculated within LoadMAP for each year of the forecast and is
available once the technology or measure becomes available.
Tables D-10 through D-17 list the detailed unit-level data for the non-equipment energy
efficiency measures for each of the segments and for existing and new construction,
respectively. Because these measures can produce energy-use savings for multiple end-use loads
(e.g., insulation affects heating and cooling energy use) savings are expressed as a percentage
of the end-use loads. Base saturation indicates the percentage of buildings in which the measure
is already installed. Applicability/Feasibility is the product of two factors that account for whether
the measure is applicable to the building. Cost is expressed in $/sq.ft. The detailed measure-level
tables present the results of the benefit/cost (B/C) analysis for the first year of the forecast. The
B/C ratio is zero if the measure represents the baseline technology or if the measure is not
available in the first year of the forecast (2012). The B/C ratio is calculated within LoadMAP for
each year of the forecast and is available once the technology or measure becomes available.
Note that Tables D-2 through D-17 present information for Washington. For Idaho, savings and
B/C ratios may be slightly different due to weather-related usage, differences in the states’
market profiles, and different retail electricity prices. Although Idaho-specific values are not
presented here, they are available within the LoadMAP files.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1012 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-2 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling Central Cooling Systems Commercial buildings are often cooled with a central chiller plant that 
creates chilled water for distribution throughout the facility. Chillers can 
be air source or water source, which include heat rejection via a 
condenser loop and cooling tower. Because of the wide variety of 
system types and sizes, savings and cost values for efficiency 
improvements in chiller systems represent an average over air‐ and 
water‐cooled systems, as well as screw, reciprocating, and centrifugal 
technologies. Under this simplified approach, each central system is 
characterized by an aggregate efficiency value (inclusive of chiller, 
pumps, motors and condenser loop equipment), in kW/ton with a 
further efficiency upgrade through the application of variable 
refrigerant flow technology.  
Cooling Chilled Water Variable Flow 
System 
The chilled water variable flow system is essentially a single chilled 
water loop with variable volume and speed. A single set of pumps 
operated by a VSD eliminates the need for separate distribution pumps 
and makes the chilled water flow throughout the entire system be 
variable. The use of adjustable flow limiting valves is designed to 
optimize water flow. Such valves provide flow limiting, shut‐off and 
adjustment functions, automatically compensating for changes in 
system pressure to maximize energy efficiency. 
Cooling Packaged Cooling Systems / 
Rooftop Units (RTUs) and 
Heat Pumps   
Packaged cooling systems are simple to install and maintain, and are 
commonly used in small and medium‐sized commercial buildings.  
Applications range from a single supply system with air intake filters, 
supply fan, and cooling coil, or can become more complex with the 
addition of a return air duct, return air fan, and various controls to 
optimize performance. For packaged RTUs, varying Energy Efficiency 
Ratios (EER) were considered, as well as ductless or “mini‐split” systems 
with variable refrigerant flow. For heat pumps, units with increasing EER 
and COP levels were evaluated, as well as a ductless mini‐split system.  
Cooling Packaged Terminal Air 
Conditioners (PTAC) 
Window (or wall) mounted room air conditioners (and heat pumps) are 
designed to cool (or heat) a single room or space.  This type of unit 
incorporates a complete air‐cooled refrigeration and air‐handling 
system in an individual package.  Conditioned air is discharged in 
response to thermostatic control to meet room requirements.  Each 
unit has a self‐contained, air‐cooled direct expansion (DX) cooling 
system, a heat pump or other fuel‐based heating system and associated 
controls. The energy savings increase with each incremental increase in 
efficiency, measured in terms of EER level.   
Space Heating Convert to Gas This fuel‐switching measure is the replacement of an electric furnace 
with a gas furnace. This measure eliminates all prior electricity 
consumption and demand due to electric space heating. In this study, it 
is assumed this measure can be implemented only in buildings within 
500 feet of a gas main. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1013 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-3
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling, Space 
Heating, 
Interior 
Lighting 
Energy Management 
System 
An energy management system (EMS) allows managers/owners to 
monitor and control the major energy‐consuming systems within a 
commercial building.  At the minimum, the EMS can be used to monitor 
and record energy consumption of the different end‐uses in a building, 
and can control operation schedules of the HVAC and lighting systems.  
The monitoring function helps building managers/owners to identify 
systems that are operating inefficiently so that actions can be taken to 
correct the problem.  The EMS can also provide preventive maintenance 
scheduling that will reduce the cost of operations and maintenance in 
the long run.  The control functionality of the EMS allows the building 
manager/owner to operate building systems from one central location.  
The operation schedules set via the EMS help to prevent building 
systems from operating during unwanted or unoccupied periods. This 
analysis assumes that this measure is limited to buildings with a central 
HVAC system. 
Cooling, Space 
Heating 
Economizer Economizers allow outside air (when it is cool and dry enough) to be 
brought into the building space to meet cooling loads instead of using 
mechanically cooled interior air.  A dual enthalpy economizer consists of 
indoor and outdoor temperature and humidity sensors, dampers, 
motors, and motor controls.  Economizers are most applicable to 
temperate climates and savings will be smaller in extremely hot or 
humid areas. 
Cooling VSD on Water Pumps The part‐load efficiency of chilled water loop pumps can be improved 
substantially by varying the speed of the motor drive according to the 
building demand for cooling.  There is also a reduction in piping losses 
associated with this measure that has a major impact on the energy use 
for a building.  However, pump speeds can generally only be reduced to 
a minimum specified rate, because chillers and the control valves may 
require a minimum flow rate to operate.  There are two major types of 
variable speed drives:  mechanical and electronic.  An additional benefit 
of variable‐speed drives is the ability to start and stop the motor 
gradually, thus extending the life of the motor and associated 
machinery.  This analysis assumes that electronic variable speed drives 
are installed. 
Cooling Turbocor Compressor Turbocor compressors use oil‐free magnetic bearings to reduce friction 
losses and couples that with a two‐stage centrifugal compressor to 
reduce central chiller energy consumption. 
Cooling High‐Efficiency Cooling 
Tower Fans 
High efficiency cooling tower fans utilize variable frequency drives in the 
cooling tower design. VFDs improve fan performance by adjusting fan 
speed and rotation as conditions change. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1014 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-4 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling Condenser Water 
Temperature Reset 
Chilled water reset controls save energy by improving chiller 
performance through increasing the supply chilled water temperature, 
which allows increased suction pressure during low load periods.  
Raising the chilled water temperature also reduces chilled water piping 
losses.  However, the primary savings from the chilled water reset 
measure results from chiller efficiency improvement.  This is due partly 
to the smaller temperature difference between chilled water and 
ambient air, and partly due to the sensitivity of chiller performance to 
suction temperature. 
Cooling Maintenance  Filters, coils, and fins require regular cleaning and maintenance for the 
heat pump or roof top unit to function effectively and efficiently 
throughout its years of service. Neglecting necessary maintenance leads 
to a steady decline in performance while energy use increases.  
Maintenance can increase the efficiency of poorly performing 
equipment by as much as 10%. 
Cooling Evaporative Precooler Evaporative precooling can improve the performance of air conditioning 
systems, most commonly RTUs. These systems typically use indirect 
evaporative cooling as a first stage to pre‐cool outside air. If the 
evaporative system cannot meet the full cooling load, the air steam is 
further cooled with conventional refrigerative air conditioning 
technology.    
Cooling Roof‐ High Reflectivity 
(Cool Roof) 
The color and material of a building structure surface will determine the 
amount of solar radiation absorbed by that surface and subsequently 
transferred into a building. This is called solar absorptance. By using a 
material or painting the roof with a light color (and a lower solar 
absorptance), the roof will absorb less solar radiation and consequently 
reduce the cooling load.  
Cooling, Space 
Heating 
Green Roofs A green roof covers a section or the entire building roof with a 
waterproof membrane and vegetative material. Like cool roofs, green 
roofs can reduce solar absorptance and they can also provide insulation. 
They also provide non‐energy benefits by absorbing rainwater and thus 
reducing storm water run‐off, providing wildlife habitat, and reducing 
so‐called urban heat island effects. 
Cooling, Space 
Heating, 
Ventilation 
HVAC Retrocommissioning Over time, the performance of complex mechanical systems providing 
heating and cooling to existing commercial spaces degrades as a result 
of inappropriate changes to or overrides of controls, deteriorating 
equipment, clogged filters, changing demands and schedules, and 
pressure imbalances. Retrocommissioning is a comprehensive analysis 
of an entire system in which an engineer assesses shortcomings in 
system performance, and then optimizes through a process of tune‐up, 
maintenance, and reprogramming of control or automation software. 
Energy efficiency programs throughout the country promote 
retrocommissioning as a means of greatly reducing energy consumption 
in existing buildings. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1015 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-5
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling, Space 
Heating, 
Ventilation, 
Interior 
Lighting 
Comprehensive 
Retrocommissioning 
Comprehensive retrocommissioning covers not only HVAC and lighting, 
but other existing building systems as well. For example, it can improve 
efficiency of non‐HVAC motors, vertical transport systems, and 
domestic hot water systems.  
Cooling, Space 
Heating, 
Ventilation, 
Interior 
Lighting/Exteri
or Lighting 
HVAC Commissioning  

Lighting Commissioning  

Comprehensive 
Commissioning 
For new construction and major renovations, commissioning ensures 
that building systems are properly designed, specified, and installed to 
meet the design intent and provide high‐efficiency performance. As the 
names suggests, HVAC Commissioning and Lighting Commissioning 
focus only on HVAC and lighting equipment and controls. 
Comprehensive commissioning addresses these systems but usually 
begins earlier in the design process, and may also address domestic hot 
water, non‐HVAC fans, vertical transport, telecommunications, fire 
protection, and other building systems. 
Cooling, Space 
Heating, 
Interior 
Lighting 
Advanced New 
Construction Designs 
Advanced new construction designs use an integrated approach to the 
design of new buildings to account for the interaction of building 
systems. Typically, architects and engineers work closely to specify the 
building orientation, building shell, building mechanical systems, and 
controls strategies with the goal of optimizing building energy efficiency 
and comfort. Options that may be evaluated and incorporated include 
passive solar strategies, increased thermal mass, daylighting strategies, 
and shading strategies, This measure was modeled for new construction 
only. 
Cooling, Space 
Heating 
Programmable Thermostat A programmable thermostat can be added to most heating/cooling 
systems.  They are typically used during winter to lower temperatures 
at night and in summer to increase temperatures during the afternoon.  
There are two‐setting models, and well as models that allow separate 
programming for each day of the week.  The energy savings from this 
type of thermostat are identical to those of a "setback" strategy with 
standard thermostats, but the convenience of a programmable 
thermostat makes it a much more attractive option.  In this analysis, the 
baseline is assumed to have no thermostat setback. 
Cooling, Space 
Heating 
Duct Repair and Sealing An ideal duct system would be free of leaks.  Leakage in unsealed ducts 
varies considerably because of the differences in fabricating machinery 
used, the methods for assembly, installation workmanship, and age of 
the ductwork.  Air leaks from the system to the outdoors result in a 
direct loss proportional to the amount of leakage and the difference in 
enthalpy between the outdoor air and the conditioned air.  To seal 
ducts, a wide variety of sealing methods and products exist.  Each has a 
relatively short shelf life, and no documented research has identified 
the aging characteristics of sealant applications.  This analysis assumes 
that the baseline air loss from ducts has doubled, and conducting repair 
and sealing of the ducts will restore leakage from ducts to the original 
baseline level. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1016 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-6 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Cooling, Space 
Heating 
Duct Insulation Air distribution ducts can be insulated to reduce heating or cooling 
losses.  Best results can be achieved by covering the entire surface area 
with insulation.  Insulation material inhibits the transfer of heat through 
the air‐supply duct.  Several types of ducts and duct insulation are 
available, including flexible duct, pre‐insulated duct, duct board, duct 
wrap, tacked, or glued rigid insulation, and waterproof hard shell 
materials for exterior ducts.   
Cooling, Space 
Heating 
Insulation – Radiant Barrier Radiant barriers inhibit heat transfer by thermal radiation. When a 
radiant barrier is installed beneath the roofing material much of the 
heat radiated from a hot roof is reflected back to the roof limiting the 
amount of heat emitted downwards.  
Cooling, Space 
Heating 
High‐Efficiency Windows High‐efficiency windows, such as those labeled under the ENERGY STAR 
Program, are designed to reduce a building's energy bill while increasing 
comfort for the occupants at the same time.  High‐efficiency windows 
have reducing properties that reduce the amount of heat transfer 
through the glazing surface.  For example, some windows have a low‐E 
coating, which is a thin film of metallic oxide coating on the glass 
surface that allows passage of short‐wave solar energy through glass 
and prevents long‐wave energy from escaping.  Another example is 
double‐pane glass that reduces conductive and convective heat 
transfer.  There are also double‐pane glasses that are gas‐filled (usually 
argon) to further increase the insulating properties of the window. 
Cooling, Space 
Heating 
Ceiling and Wall Cavity  
Insulation 
Thermal insulation is material or combinations of materials that are 
used to inhibit the flow of heat energy by conductive, convective, and 
radiative transfer modes.  Thus, thermal insulation can conserve energy 
by reducing the heat loss or gain of a building.  The type of building 
construction defines insulating possibilities.  Typical insulating materials 
include:  loose‐fill (blown) cellulose; loose‐fill (blown) fiberglass; and 
rigid polystyrene. 
Ventilation Cooking – Exhaust Hoods 
with Sensor Controls 
Improved exhaust hoods involve installing variable‐speed controls on 
commercial kitchen hoods. These controls provide ventilation based on 
actual cooking loads. When grills, broilers, stoves, fryers or other 
kitchen appliances are not being used, the controls automatically sense 
the reduced load and decrease the fan speed accordingly. This results in 
lower energy consumption because the system is only running as 
needed rather than at 100% capacity at all times. 
Ventilation Variable Air Volume A variable air volume ventilation system modulates the air flow rate as 
needed based on the interior conditions of the building to reduce fan 
load, improve dehumidification, and reduce energy usage. 
Ventilation Fans – Energy Efficient 
Motors 
High‐efficiency motors are essentially interchangeable with standard 
motors, but differences in construction make them more efficient.  
Energy‐efficient motors achieve their improved efficiency by reducing 
the losses that occur in the conversion of electrical energy to 
mechanical energy.  This analysis assumes that the efficiency of supply 
fans is increased by 5% due to installing energy‐efficient motors. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1017 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-7
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Ventilation Fans – Variable Speed 
Control (VSD) 
The part‐load efficiency of ventilation fans can be improved 
substantially by varying the speed of the motor drive.  There are two 
major types of variable speed controls:  mechanical and electronic.  An 
additional benefit of variable‐speed controls is the ability to start and 
stop the motor gradually, thus extending the life of the motor and 
associated machinery. This analysis assumes that electronic variable 
speed controls are installed. 
Water Heating High‐Efficiency Water 
Heater Systems 
Efficient electric water heaters are characterized by a high recovery or 
thermal efficiency (percentage of delivered electric energy which is 
transferred to the water) and low standby losses (the ratio of heat lost 
per hour to the content of the stored water). Included in the savings 
associated with high‐efficiency electric water heaters are timers that 
allow temperature setpoints to change with hot water demand 
patterns. For example, the heating element could be shut off 
throughout the night, increasing the overall energy factor of the unit. In 
addition, tank and pipe insulation reduces standby losses and therefore 
reduces the demands on the water heater. This analysis considers 
conventional electric water heaters with efficiency greater than 96%, as 
well as geothermal heat pump water heaters for effective efficiency 
greater than one. Solar water heating was evaluated as well. 
Water Heating Convert to Gas This fuel‐switching measure is the replacement of an electric water 
heater with a gas‐fired water heater. This measure will eliminate all 
prior electricity consumption and demand due to electric water heating. 
In this study, it is assumed that this measure can be implemented only 
in buildings within 500 feet of a gas main. 
Water Heating Heat Pump Water Heater Heat pump water heaters use heat pump technology to extract heat 
from the ambient surroundings and transfer it to a hot water tank. 
These devices are available as an alternative to conventional tank water 
heaters of 55 gallons or larger.   
Water Heating Faucet Aerators/Low Flow 
Nozzles 
A faucet aerator or low flow nozzle spreads the stream from a faucet 
helping to reduce water usage. The amount of water passing through 
the aerator is measured in gallons per minute (GPM) and the lower the 
GPM the more water the aerator conserves.  
Water Heating Pipe Insulation Insulating hot water pipes decreases the amount of energy lost during 
distribution of hot water throughout the building. Insulating pipes will 
result in quicker delivery of hot water and allows lowering the water 
heating set point. There are several different types of insulation, the 
most common being polyethylene and neoprene.       
Water Heating High‐Efficiency Circulation 
Pump 
A high efficiency circulation pump uses an electronically commutated 
motor (ECM) to improve motor efficiency over a larger range of partial 
loads. In addition, an ECM allows for improved low RPM performance 
with greater torque and smaller pump dimensions. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1018 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-8 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Water Heating Tank Blanket/Insulation Insulation levels on domestic hot water heaters can be increased by 
installing a fiberglass blanket on the outside of the tank. This increase in 
insulation reduces standby losses and thus saves energy.  Water heater 
insulation is available either by the blanket or by square foot of 
fiberglass insulation with R‐values ranging from 5 to 14.   
Water Heating Thermostat Setback Installing a setback thermostat on the water heater can lead to 
significant energy savings during periods when there is no one in the 
building.   
Water Heating Hot Water Saver A hot water saver is a plumbing device that attaches to the showerhead 
and that pauses the flow of water until the water is hot enough for use. 
The water is re‐started by the flip of a switch. 
Interior 
Lighting, 
Exterior 
Lighting 
Lamp Replacement 
(Interior Screw‐in, HID, and 
Linear Fluorescent 
 Exterior Screw‐in, HID, and 
Linear Fluorescent) 
Commercial lighting differs from the residential sector in that efficiency 
changes typically require more than the simple purchase and quick 
installation of a screw‐in compact fluorescent lamp. Restrictions 
regarding ballasts, fixtures, and circuitry limit the potential for direct 
substitution of one lamp type for another. However, such replacements 
do exist. For example, screw‐in incandescent lamps can readily be 
replaced with CFLs or LEDs. Also, during the buildout for a leased office 
space, the management could decide to replace all T12 lamps and 
magnetic ballasts with T8/electronic ballast configurations. This type of 
decision‐making is modeled on a stock turnover basis because of the 
time between opportunities for upgrades. 
Interior 
Lighting, 
Exterior 
Lighting 
Lighting 
Retrocommissioning 
Lighting retrocommissioning projects in existing commercial buildings 
do not require an event such as a tenant turnover, a major renovation, 
or an update to electrical circuits to drive its adoption. Rather, a 
decision‐maker can decide at any time to perform a comprehensive 
audit of a facility's lighting systems, followed by an upgrade of 
equipment (lamps, ballasts, fixtures, reflectors), controls (occupancy 
sensors, daylighting controls, and central automation).  
Interior 
Lighting  
Delamping and Install 
Reflectors 
While sometimes included in lighting retrofit projects, delamping is 
often performed as a separate energy efficiency measure in which a 
lighting engineer analyzes the lighting provided by current systems 
compared to the requirements of building occupants. This often leads 
to the removal of unnecessary lamps corresponding to an overall 
reduction in energy usage. .In addition, installing a reflector in each 
fixture can improve light distribution from the remaining lamps.   
Interior 
Lighting, 
Exterior 
Lighting 
Lighting Time Clocks and 
Timers 
While outdoor lighting is typically required only at night, in many cases 
lighting remains on during daylight hours. A simple timer can set a 
diurnal schedule for outdoor lighting and thus reduce the operating 
hours by as much as 50%. 
Interior 
Lighting 
Central Lighting Controls Central lighting control systems provide building‐wide control of interior 
lighting to ensure that lights are properly scheduled based on expected 
building occupancy. Individual zones or circuits can be controlled. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1019 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-9
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Interior 
Lighting 
Photocell Controlled T8 
Dimming Ballasts 
Photocells, in concert with dimming ballasts, can detect when adequate 
daylighting is available and dim or turn off lights to reduce electricity 
consumption. Usually one photocell is used to control a group of 
fixtures, a zone, or a circuit.  
Interior 
Lighting 
Bi‐Level Fixture with 
Occupancy  Sensor 
Bi‐level fixtures with occupancy sensors detect when a space is 
unoccupied and reduce light output to a lower level. These devices  
Interior 
Lighting 
High Bay Fixtures Fluorescent fixtures designed for high‐bay applications have several 
advantages over similar HID fixtures: lower energy consumption, lower 
lumen depreciation rates, better dimming options, faster start‐up and 
restrike, better color rendition, more pupil lumens, and reduced glare.  
Interior 
Lighting 
Occupancy Sensor The installation of occupancy sensors allows lights to be turned off 
during periods when a space is unoccupied, virtually eliminating the 
wasted energy due to lights being left on. There are several types of 
occupancy sensors in the market.  
Interior 
Lighting 
LED Exit Lighting The lamps inside exit signs represent a significant energy end‐use, since 
they usually operate 24 hours per day.  Many old exit signs use 
incandescent lamps, which consume approximately 40 watts per sign.  
The incandescent lamps can be replaced with LED lamps that are 
specially designed for this specific purpose.  In comparison, the LED 
lamps consume approximately 2‐5 watts. 
Interior 
Lighting 
Task Lighting In commercial facilities, individual work areas can use task lighting 
instead of brightly lighting the entire area.  Significant energy savings 
can be realized by focusing light directly where it is needed and 
lowering the general lighting level.  An example of task lighting is the 
common desk lamp.  A 25W desk lamp can be installed in place of a 
typical lamp in a fixture. 
Interior 
Lighting, 
Cooling 
Hotel Guestroom Controls Hotel guestrooms can be fitted with occupancy controls that turn off 
energy‐using equipment when the guest is not using the room.  The 
occupancy controls comes in several forms, but this analysis assumes 
the simplest kind, which is a simple switch near the room’s entry where 
the guest can deposit their room key or card. If the key or card is 
present, then lights, TV, and air conditioning can receive power and 
operate. When the guest leaves and takes the key, all equipment shuts 
off. 
Exterior 
Lighting 
Daylighting Controls Daylighting controls use a photosensor to detect ambient light and turn 
off exterior lights accordingly.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1020 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-10 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Exterior 
Lighting 
Photovoltaic Lighting Outdoor photovoltaic (PV) lighting systems use PV panels (or modules), 
which convert sunlight to electricity.  The electricity is stored in 
batteries for use at night.  They can be cost effective relative to 
installing power cables and/or step down transformers for relatively 
small lighting loads. The "nightly run time" listings on most "off‐the‐
shelf" products are based on specific sunlight conditions. Systems 
located in places that receive less sunlight than the system is designed 
for will operate for fewer hours per night than expected. Nightly run 
times may also vary depending on how clear the sky is on any given day. 
Shading of the PV panel by landscape features (vegetation, buildings, 
etc.) will also have a large impact on battery charging and performance.  
Open areas with no shading, such as parking lots, are ideal places where 
PV lighting systems can be used. 
Exterior 
Lighting 
Cold Cathode Lighting Cold cathode lighting does not use an external heat source to provide 
thermionic emission of electrons. Cold cathode lighting is typically used 
for exterior signage or where temperatures are likely to drop below 
freezing. 
Exterior 
Lighting 
Induction Lamps Induction lamps use a contactless bulb and rely on electromagnetic 
fields to transfer power. This allows for the lamp to utilize more 
efficient materials that would otherwise react with metal electrodes. In 
addition, the lack of an electrode significantly extends lamp life while 
reducing lumen depreciation. 
Office 
Equipment 
Desktop and Laptop 
Computing Equipment 
ENERGY STAR labeled office equipment saves energy by powering down 
and "going to sleep" when not in use.  ENERGY STAR labeled computers 
automatically power down to 15 watts or less when not in use and may 
actually last longer than conventional products because they spend a 
large portion of time in a low‐power sleep mode.  ENERGY STAR labeled 
computers also generate less heat than conventional models. The 
ClimateSavers Initiative, made up of leading computer processor 
manufacturers, has stated a goal of reducing power consumption in 
active mode by 50% by integrating innovative power management into 
the chip design process. 
Office 
Equipment 
Monitors ENERGY STAR labeled office equipment saves energy by powering down 
and "going to sleep" when not in use.  ENERGY STAR labeled monitors 
automatically power down to 15 watts or less when not in use. 
Office 
Equipment 
Servers In addition to the "sleep" mode a reductions and the efficient 
processors being designed by members of the ClimateSavers Initiative, 
servers have additional energy‐saving opportunities through 
"virtualization" and other architecture solutions that involve optimal 
matching of computation tasks to hardware requirements 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1021 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-11
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Office 
Equipment 
Printers/Copiers/ Fax/ POS 
Terminals 
ENERGY STAR labeled office equipment saves energy by powering down 
and "going to sleep" when not in use.  ENERGY STAR labeled copiers are 
equipped with a feature that allows them to automatically turn off after 
a period of inactivity, reducing a copier's annual electricity costs by over 
60%.  High‐speed copiers that include a duplexing unit that is set to 
automatically make double‐sided copies can reduce paper costs and 
help to save trees. 
Office 
Equipment 
ENERGY STAR Power 
Supply 
Power supplies with an efficient ac‐dc or ac‐ac conversion process can 
obtain the ENERGY STAR label. These devices can be used to power 
computers, phones, and other office equipment.  
Refrigeration Walk‐in Refrigeration 
Systems 
Standard compressors typically operate at approximately 65% 
efficiency. High‐efficiency models are available that can improve 
compressor efficiency by 15%. 
Refrigeration Glass Door and Solid Door 
Refrigeration Units (Reach‐
in /Open Display 
Case/Vending Machine) 

Door Gasket Replacement 

High Efficiency Case 
Lighting 
In addition to walk‐in, "cold‐storage" refrigeration, a significant amount 
of energy in the commercial sector can be attributed to "reach‐in" units. 
These stand‐alone appliances can range from a residential‐style 
refrigerator/freezer unit in an office kitchen or the breakroom of a retail 
store to the refrigerated display cases in some grocery or convenience 
stores. As in the case of residential units, these refrigerators can be 
designed to perform at higher efficiency through a combination of 
compressor equipment upgrades, default temperature settings, and 
defrost patterns.  
Other measures for these units are replacing aging door gaskets that no 
longer adequately seal the case, and replacing inefficient display lights 
with CFL or LED systems to reduce internal heat gains in the cases.  
Refrigeration Open Display Case Glass doors can be used to enclose multi‐deck display cases for 
refrigerated items in supermarkets.  In addition, more efficient units are 
designed to perform at higher efficiency through a combination of 
compressor equipment upgrades, default temperature settings, and 
defrost patterns. 
Refrigeration Anti‐Sweat Heater/ Auto 
Door Closer Controls 
Anti‐sweat heaters are used in virtually all low‐temperature display 
cases and many medium‐temperature cases to control humidity and 
prevent the condensation of water vapor on the sides and doors and on 
the products contained in the cases.  Typically, these heaters stay on all 
the time, even though they only need to be on about half the time. 
Anti‐sweat heater controls can come in the form of humidity sensors or 
time clocks. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1022 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-12 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Refrigeration Floating Head Pressure 
Controls 
Floating head pressure control allows the pressure in the condenser to 
"float" with ambient temperatures. This method reduces refrigeration 
compression ratios, improves system efficiency and extends the 
compressor life. The greatest savings with a floating head pressure 
approach occurs when the ambient temperatures are low, such as in 
the winter season.  Floating head pressure control is most practical for 
new installations. However, retrofits installation can be completed with 
some existing refrigeration systems. Installing floating head pressure 
control increases the capacity of the compressor when temperatures 
are low, which may lead to short cycling. 
Refrigeration Bare Suction Lines Insulating bare suction lines reduces heat  
Refrigeration Night Covers Night covers can be used on open refrigeration cases when a facility is 
closed or few customers are in the store.  
Refrigeration Strip Curtain Strip curtains at the entrances to large walk‐in coolers or freezers, such 
as those used in supermarkets, reduce air transfer between the 
refrigerated space and the surrounding space.  
Refrigeration Icemakers In certain building types (restaurant, hotel), the production of ice is a 
significant usage of electricity. By optimizing the timing of ice 
production and the type of output to the specific application, icemakers 
are assumed to deliver electricity savings. 
Refrigeration Vending Machine ‐ 
Controller 
Cold beverage vending machines usually operate 24 hours a day 
regardless of whether the surrounding area is occupied or not.  The 
result is that the vending machine consumes energy unnecessarily, 
because it will operate all night to keep the beverage cold even when 
there would be no customer until the next morning.  A vending machine 
controller can reduce energy consumption without compromising the 
temperature of the vended product. The controller uses an infrared 
sensor to monitor the surrounding area’s occupancy and will power 
down the vending machine when the area is unoccupied.  It will also 
monitor the room’s temperature and will re ‐power the machine at one 
to three hour intervals independent of occupancy to ensure that the 
product stays cold.   
Food Service Kitchen Equipment Commercial cooking and food preparation equipment represent a 
significant contribution to energy consumption in restaurants and other 
food service applications. By replacing old units with efficient ones, this 
energy consumption can be greatly reduced. These measures include 
fryers, commercial ovens, dishwashers, hot food containers and 
miscellaneous other food preparation equipment. Savings range 
between 15 and 65%, depending on the specific unit being replaced. 
Cooling, Space 
Heating, 
Interior 
Lighting, Food 
Preparation, 
Refrigeration 
Custom Measures Custom measures were included in the CPA analysis to serve as a “catch 
all” for measures for which costs and savings are not easily quantified 
and that could be part of a program such as Avista’s existing Site‐
Specific incentive program. Costs and energy savings were assumed 
such that the measures passed the economic screen.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1023 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-13
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Miscellaneous Non‐HVAC motor Because the Small/Medium Commercial and Large Commercial 
segments include some industrial customers, the CPA analysis included 
equipment upgrades for non‐HVAC motors. This equipment measure 
also incorporates improvements for vertical transport. Premium 
efficiency motors reduce the amount of lost energy going into heat 
rather than power.  Since less heat is generated, less energy is needed 
to cool the motor with a fan.  Therefore, the initial cost of energy 
efficient motors is generally higher than for standard motors. However 
their life‐cycle costs can make them far more economical because of 
savings they generate in operating expense. 
Premium efficiency motors can provide savings of 0.5% to 3% over 
standard motors.  The savings results from the fact that energy efficient 
motors run cooler than their standard counterparts, resulting in an 
increase in the life of the motor insulation and bearing.  In general, an 
efficient motor is a more reliable motor because there are fewer 
winding failures, longer periods between needed maintenance, and 
fewer forced outages.  For example, using copper instead of aluminum 
in the windings, and increasing conductor cross‐sectional area, lowers a 
motor’s I2R losses. 
Miscellaneous Pumps – Variable Speed 
Control 
The part‐load efficiency of chilled and hot water loop pumps can be 
improved substantially by varying the speed of the motor drive 
according to the building demand for heating or cooling. There is also a 
reduction in piping losses associated with this measure that has a major 
impact on the heating loads and energy use for a building. However, 
pump speeds can generally only be reduced to a minimum specified 
rate, because chillers, boilers, and the control valves may require a 
minimum flow rate to operate. There are two major types of variable 
speed controls:  mechanical and electronic.  An additional benefit of 
variable‐speed drives is the ability to start and stop the motor gradually, 
thus extending the life of the motor and associated machinery. This 
analysis assumes that electronic variable speed controls are installed. 
Miscellaneous Laundry – High Efficiency  
Clothes Washer 
High efficiency clothes washers use designs that require less water.  
These machines use sensors to match the hot water needs to the load, 
preventing energy waste. There are two designs:  top‐loading and front‐
loading. Further energy and water savings can be achieved through 
advanced technologies such as inverter‐drive or combination washer‐
dryer units. 
Miscellaneous ENERGY STAR Water Cooler An ENERGY STAR water cooler has more insulation and improved 
chilling mechanisms, resulting in about half the energy use of a standard 
cooler. 
Miscellaneous Industrial Process 
Improvements  
Because the Avista C&I sector segmentation was based on Avista’s rate 
classes, the commercial building segments include a small percentage 
or industrial business types. This measure was included to account for 
energy efficiency potential that could be achieved through various 
process improvements at these customers.  
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1024 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-14 www.gepllc.com

Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Machine Drive. Motors, Premium 
Efficiency 
Premium efficiency motors reduce the amount of lost energy going into 
heat rather than power.  Since less heat is generated, less energy is 
needed to cool the motor with a fan.  Therefore, the initial cost of 
energy efficient motors is generally higher than for standard motors.  
However their life‐cycle costs can make them far more economical 
because of savings they generate in operating expense. 
Premium efficiency motors can provide savings of 0.5% to 3% over 
standard motors.  The savings results from the fact that energy efficient 
motors run cooler than their standard counterparts, resulting in an 
increase in the life of the motor insulation and bearing.  In general, an 
efficient motor is a more reliable motor because there are fewer 
winding failures, longer periods between needed maintenance, and 
fewer forced outages.  For example, using copper instead of aluminum 
in the windings, and increasing conductor cross‐sectional area, lowers a 
motor’s I2R losses. 
This analysis assumes 75% loading factor (for peak efficiency) for 1800 
rpm motor.  Hours of operation vary depending on horsepower size. In 
addition, improved drives and controls are assumed to be implemented 
along with the motors, resulting in savings as high as 10% of annual 
energy consumption 
Machine Drive Motors – Variable 
Frequency Drive 
In addition to energy savings, VFDs increase motor and system life and 
provide a greater degree of control over the motor system. Especially 
for motor systems handling fluids, VFDs can efficiently respond to 
changing operating conditions.  
Machine Drive Magnetic Adjustable 
Speed Drive 
To allow for adjustable speed operation, this technology uses magnetic 
induction to couple a drive to its load. Varying the magnetic slip within 
the coupling controls the speed of the output shaft.  Magnetic drives 
perform best at the upper end of the speed range due to the energy 
consumed by the slip. Unlike traditional ASDs, magnetically coupled 
ASDs create no power distortion on the electrical system. However, 
magnetically coupled ASD efficiency is best when power needs are 
greatest. VFDs may show greater efficiency when the average load 
speed is below 90% of the motor speed, however this occurs when 
power demands are reduced. 
Machine Drive Compressed Air – System 
Controls, Optimization and 
Improvements, 
Maintenance 
Controls for compressed air systems can shift load from two partially 
loaded compressors to one compressor in order to maximize 
compression efficiency and may also involve the addition of VFDs. 
Improvements include installing high‐efficiency motors. Maintenance 
includes fixing air leaks and replacing air filters. 
Machine Drive Fan Systems – Controls, 
Optimization and 
Maintenance 
Certain practices require a consistent flow rate, such as indoor air 
quality and clean room ventilation. To achieve this, fan flow controls 
can be used to maintain precise volume flow control ensuring a 
constant air delivery even on fluctuating pressure conditions. This is 
done through programmable circuitry to electronically control fan 
motor speed. Motors can be configured to accept a signal from a 
controller that would vary the flow rate in direct proportion to the 
signal. 
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1025 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-15
An EnerNOC Company
Table D-1 Commercial and Industrial Energy-Efficiency Equipment/Measure Descriptions
End‐Use 
Energy Efficiency 
Measure Description 
Machine Drive Pumping Systems – 
Controls, Optimization and 
Maintenance 
Pumping systems optimization includes installing VFDs, correctly 
resizing the motors, and installing timers and automated on‐off 
controls. Maintenance includes repairing diaphragms and fixing piping 
leaks. 
Process Process 
Cooling/Refrigeration 
Because of the customized nature of industrial cooling and refrigeration 
applications, a variety of opportunities are summarized as a general 
improvement in cooling and cold storage equipment. Costs and savings 
were developed using average values for this group of measures from 
the Sixth Plan industrial supply curve workbooks. 
Process Process Heating Because of the customized nature of industrial heating applications, a 
variety of opportunities are summarized as a general improvement in 
process heating equipment, such as arc furnaces. Costs and savings 
were developed using average values for this group of measures from 
the Sixth Plan industrial supply curve workbooks. 
Process Electrochemical Process Because of the customized nature of industrial electrochemical 
applications, a variety of opportunities are summarized as a general 
improvement in equipment and processes. Costs and savings were 
developed using average values for this group of measures from the 
Sixth Plan industrial supply curve workbooks. 
Process Refrigeration – System 
Controls, Maintenance, 
and Optimization 
Because refrigeration equipment performance degrades over time and 
control settings are frequently overridden, these measures account for 
savings that can be achieved through system maintenance and controls 
optimization. 

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1026 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-16 www.gepllc.com

Table D-2 Energy Efficiency Equipment Data — Small/Medium Comm., Existing Vintage

Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 1.5 kw/ton, COP 2.3 ‐               $0.00 20 ‐            
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.29             $0.39 20 ‐            
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.35             $0.50 20 0.51          
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.73             $0.62 20 1.90          
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.77             $0.74 20 1.39          
Cooling Central Chiller Variable Refrigerant Flow 1.01             $11.57 20 0.07          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.22             $0.18 16 ‐            
Cooling RTU EER 11.2 0.43             $0.35 16 ‐            
Cooling RTU EER 12.0 0.57             $0.58 16 0.49          
Cooling RTU Ductless VRF 0.69             $5.12 16 0.05          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.09             $0.08 14 0.86          
Cooling PTAC EER 10.8 0.21             $0.16 14 1.00          
Cooling PTAC EER 11 0.25             $0.43 14 0.43          
Cooling PTAC EER 11.5 0.33             $0.96 14 0.27          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.57             $0.39 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.90             $1.18 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 1.20             $1.57 15 0.98          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.31             $1.96 15 0.68          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.46             $11.50 20 0.10          
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.30             $1.22 15 1.07          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.23             $0.09 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.94             $0.03 7 16.50       
Interior Lighting Interior Screw‐in LED 1.04             $1.18 12 0.84          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.30             ($0.07) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.30             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.91             $0.25 6 1.73          
Interior Lighting Linear Fluorescent T5 0.95             $0.43 6 1.06          
Interior Lighting Linear Fluorescent LED 0.99             $3.74 15 0.33          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.14             $0.05 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.60             $0.02 7 17.60       
Exterior Lighting Exterior Screw‐in Metal Halides 0.60             $0.05 4 3.16          
Exterior Lighting Exterior Screw‐in LED 0.66             $0.64 12 0.90          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.22             ($0.13) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.24             $0.55 9 0.37          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.01             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.04             $0.02 6 1.12          
Exterior Lighting Linear Fluorescent T5 0.04             $0.03 6 0.69          
Exterior Lighting Linear Fluorescent LED 0.05             $0.24 15 0.22          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.10             $0.02 15 5.23          
Water Heating Water Heater Geothermal Heat Pump 1.33             $3.53 15 0.43          
Water Heating Water Heater Solar 1.46             $3.03 15 0.55          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.03             $0.04 12 0.80          
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1027 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-17
An EnerNOC Company
Table D-2 Energy Efficiency Equipment Data — Small/Med. Comm., Existing Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Oven Efficient 0.39             $0.36 12 1.02          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.02             $0.05 12 0.36          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.40             $0.16 12 2.29          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.00             $0.03 12 0.07          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient ‐               $0.09 18 ‐            
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.16             $0.00 18 56.08       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.19             $0.02 18 9.87          
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.00             $0.00 18 0.24          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.11             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.20             $0.00 10 46.48       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.05             $0.00 12 12.76       
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.19             $0.00 4 23.04       
Office Equipment Desktop Computer Climate Savers 0.27             $0.36 4 0.23          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 7.34          
Office Equipment Laptop Computer Climate Savers 0.03             $0.12 4 0.08          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.12             $0.01 3 2.14          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.22             $0.00 4 19.68       
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.09             $0.04 6 0.98          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.03             $0.00 4 2.96          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.05             $0.06 15 0.95          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.06             $0.06 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.07             $0.11 15 0.72          
Miscellaneous Non‐HVAC Motor Premium (2015)0.08             $0.11 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1028 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-18 www.gepllc.com

Table D-3 Energy Efficiency Equipment Data — Large Commercial, Existing Vintage

Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 1.5 kw/ton, COP 2.3 ‐               $0.00 20 ‐            
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.30             $0.26 20 ‐            
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.36             $0.33 20 0.83          
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.75             $0.41 20 3.11          
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.79             $0.49 20 2.28          
Cooling Central Chiller Variable Refrigerant Flow 1.04             $7.63 20 0.11          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.22             $0.13 16 ‐            
Cooling RTU EER 11.2 0.45             $0.25 16 ‐            
Cooling RTU EER 12.0 0.59             $0.41 16 0.75          
Cooling RTU Ductless VRF 0.72             $3.67 16 0.07          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.09             $0.09 14 0.86          
Cooling PTAC EER 10.8 0.21             $0.17 14 1.00          
Cooling PTAC EER 11 0.25             $0.46 14 0.43          
Cooling PTAC EER 11.5 0.34             $1.03 14 0.27          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.46             $0.18 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.73             $0.55 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 0.97             $0.73 15 1.85          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.07             $0.91 15 1.28          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.19             $5.35 20 0.19          
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.03             $1.22 15 0.86          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.19             $0.08 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.78             $0.03 7 14.13       
Interior Lighting Interior Screw‐in LED 0.87             $1.11 12 0.72          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.31             ($0.08) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.30             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.89             $0.25 6 1.66          
Interior Lighting Linear Fluorescent T5 0.92             $0.42 6 1.02          
Interior Lighting Linear Fluorescent LED 0.97             $3.67 15 0.32          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.08             $0.01 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.34             $0.01 7 34.02       
Exterior Lighting Exterior Screw‐in Metal Halides 0.34             $0.02 4 6.10          
Exterior Lighting Exterior Screw‐in LED 0.38             $0.19 12 1.73          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.19             ($0.11) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.20             $0.45 9 0.37          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.01             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.04             $0.02 6 1.18          
Exterior Lighting Linear Fluorescent T5 0.04             $0.03 6 0.72          
Exterior Lighting Linear Fluorescent LED 0.05             $0.24 15 0.23          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.12             $0.02 15 5.71          
Water Heating Water Heater Geothermal Heat Pump 1.54             $3.53 15 0.46          
Water Heating Water Heater Solar 1.69             $3.03 15 0.60          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.07             $0.02 12 3.52          
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1029 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-19
An EnerNOC Company
Table D-3 Energy Efficiency Equipment Data — Large Commercial, Existing Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Oven Efficient 0.75             $0.46 12 1.43          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.07             $0.10 12 0.58          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.35             $0.30 12 0.99          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.01             $0.03 12 0.24          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient 0.15             $1.26 18 0.13          
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.13             $0.01 18 24.96       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.30             $0.08 18 4.39          
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.00             $0.04 18 0.16          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.15             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.23             $0.00 10 20.70       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.11             $0.02 12 5.62          
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.35             $0.00 4 47.46       
Office Equipment Desktop Computer Climate Savers 0.50             $0.32 4 0.46          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 15.12       
Office Equipment Laptop Computer Climate Savers 0.04             $0.06 4 0.17          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.13             $0.01 3 4.41          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.19             $0.01 4 9.14          
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.08             $0.02 6 2.02          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.01             $0.00 4 2.94          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.06             $0.06 15 0.92          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.06             $0.06 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.08             $0.13 15 0.69          
Miscellaneous Non‐HVAC Motor Premium (2015)0.09             $0.13 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1030 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-20 www.gepllc.com

Table D-4 Energy Efficiency Equipment Data — Extra Large Commercial, Existing Vintage

Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 0.75 kw/ton, COP 4.7 ‐               $0.00 20 ‐            
Cooling Central Chiller 0.60 kw/ton, COP 5.9 0.43             $0.09 20 ‐            
Cooling Central Chiller 0.58 kw/ton, COP 6.1 0.49             $0.18 20 0.66          
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 0.57             $0.25 20 0.91          
Cooling Central Chiller 0.51 kw/ton, COP 6.9 0.69             $0.44 20 0.78          
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 0.72             $0.53 20 0.69          
Cooling Central Chiller 0.48 kw/ton, COP 7.3 0.77             $0.62 20 0.68          
Cooling Central Chiller Variable Refrigerant Flow 1.00             $10.92 20 0.05          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.20             $0.24 16 ‐            
Cooling RTU EER 11.2 0.41             $0.45 16 ‐            
Cooling RTU EER 12.0 0.53             $0.75 16 0.37          
Cooling RTU Ductless VRF 0.65             $6.64 16 0.03          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.08             $0.06 14 1.09          
Cooling PTAC EER 10.8 0.19             $0.12 14 1.28          
Cooling PTAC EER 11 0.22             $0.32 14 0.55          
Cooling PTAC EER 11.5 0.30             $0.71 14 0.34          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.50             $0.24 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.79             $0.73 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 1.06             $0.97 15 1.34          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.16             $1.21 15 0.93          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.29             $7.10 20 0.14          
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.21             $1.22 15 1.01          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.30             $0.14 4 ‐            
Interior Lighting Interior Screw‐in CFL 1.25             $0.06 7 13.22       
Interior Lighting Interior Screw‐in LED 1.38             $1.90 12 0.67          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.13             ($0.05) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.20             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.59             $0.21 6 1.31          
Interior Lighting Linear Fluorescent T5 0.61             $0.35 6 0.80          
Interior Lighting Linear Fluorescent LED 0.64             $3.08 15 0.25          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.02             $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.10             $0.00 7 37.00       
Exterior Lighting Exterior Screw‐in Metal Halides 0.10             $0.00 4 6.64          
Exterior Lighting Exterior Screw‐in LED 0.11             $0.05 12 1.89          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.26             ($0.16) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.28             $0.64 9 0.37          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.00             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.01             $0.00 6 1.12          
Exterior Lighting Linear Fluorescent T5 0.01             $0.01 6 0.69          
Exterior Lighting Linear Fluorescent LED 0.01             $0.06 15 0.22          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.19             $0.02 15 9.79          
Water Heating Water Heater Geothermal Heat Pump 2.47             $3.53 15 0.80          
Water Heating Water Heater Solar 2.72             $3.03 15 1.02          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1031 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-21
An EnerNOC Company
Table D-4 Energy Efficiency Equipment Data — Extra Large Commercial, Existing Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Fryer Efficient 0.03             $0.00 12 6.02          
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Food Preparation Oven Efficient 0.85             $0.38 12 2.11          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.03             $0.04 12 0.57          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.17             $0.22 12 0.73          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.00             $0.03 12 0.15          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient 0.06             $0.05 18 1.42          
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.04             $0.00 18 78.11       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.27             $0.02 18 12.81       
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.01             $0.03 18 0.34          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.16             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.24             $0.00 10 68.21       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.05             $0.00 12 17.60       
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.25             $0.00 4 32.37       
Office Equipment Desktop Computer Climate Savers 0.35             $0.33 4 0.32          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 10.31       
Office Equipment Laptop Computer Climate Savers 0.04             $0.10 4 0.12          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.06             $0.00 3 3.01          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.11             $0.01 4 6.80          
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.02             $0.01 6 1.38          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.00             $0.00 4 2.01          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.03             $0.03 15 1.02          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.04             $0.03 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.05             $0.07 15 0.76          
Miscellaneous Non‐HVAC Motor Premium (2015)0.05             $0.07 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1032 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-22 www.gepllc.com

Table D-5 Energy Efficiency Equipment Data — Extra Large Industrial, Existing Vintage

  Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 0.75 kw/ton, COP 4.7 ‐               $0.00 20 ‐            
Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.61             $0.33 20 ‐            
Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.82             $0.66 20 0.68          
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.15             $0.93 20 0.94          
Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.58             $1.59 20 0.80          
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.68             $1.92 20 0.71          
Cooling Central Chiller 0.48 kw/ton, COP 7.3 2.90             $2.25 20 0.70          
Cooling Central Chiller Variable Refrigerant Flow 3.74             $39.62 20 0.06          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.56             $0.39 16 ‐            
Cooling RTU EER 11.2 1.12             $0.73 16 ‐            
Cooling RTU EER 12.0 1.47             $1.22 16 0.62          
Cooling RTU Ductless VRF 1.79             $10.83 16 0.06          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.20             $0.06 14 2.79          
Cooling PTAC EER 10.8 0.47             $0.11 14 3.27          
Cooling PTAC EER 11 0.55             $0.31 14 1.41          
Cooling PTAC EER 11.5 0.75             $0.69 14 0.87          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 1.07             $0.92 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 1.69             $2.75 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 2.25             $3.66 15 0.75          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 2.47             $4.58 15 0.52          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 2.74             $26.86 20 0.08          
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 7.66             $1.22 15 6.38          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.09             $0.04 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.38             $0.02 7 14.80       
Interior Lighting Interior Screw‐in LED 0.42             $0.52 12 0.75          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.46             ($0.14) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.10             ($0.01) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.31             $0.08 6 1.73          
Interior Lighting Linear Fluorescent T5 0.32             $0.14 6 1.06          
Interior Lighting Linear Fluorescent LED 0.33             $1.21 15 0.33          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.01             $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.02             $0.00 7 15.02       
Exterior Lighting Exterior Screw‐in Metal Halides 0.02             $0.00 4 2.69          
Exterior Lighting Exterior Screw‐in LED 0.03             $0.03 12 0.77          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.07             ($0.04) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.08             $0.18 9 0.37          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.00             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.00             $0.00 6 1.16          
Exterior Lighting Linear Fluorescent T5 0.00             $0.00 6 0.71          
Exterior Lighting Linear Fluorescent LED 0.00             $0.01 15 0.22          
Process Process Cooling/Refrigera Standard ‐               $0.00 10 ‐            
Process Process Cooling/Refrigera Efficient 18.88           $5.59 10 2.49          
Process Process Heating Standard ‐               $0.00 10 ‐            
Process Process Heating Efficient 6.18             $0.57 10 7.97          
Process Electrochemical Process Standard ‐               $0.00 10 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1033 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-23
An EnerNOC Company
Table D-5 Energy Efficiency Equipment Data — Extra Large Industrial, Existing Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Process Electrochemical Process Efficient 13.16           $2.64 10 3.67          
Machine Drive Less than 5 HP Standard ‐               $0.00 10 ‐            
Machine Drive Less than 5 HP High Efficiency 0.05             $0.02 10 2.08          
Machine Drive Less than 5 HP Standard (2015)0.07             $0.00 10 ‐            
Machine Drive Less than 5 HP Premium 0.07             $0.03 10 1.66          
Machine Drive Less than 5 HP High Efficiency (2015)0.11             $0.02 10 ‐            
Machine Drive Less than 5 HP Premium (2015)0.14             $0.03 10 ‐            
Machine Drive 5‐24 HP Standard ‐               $0.00 10 ‐            
Machine Drive 5‐24 HP High 0.11             $0.02 10 5.09          
Machine Drive 5‐24 HP Premium 0.18             $0.03 10 4.07          
Machine Drive 25‐99 HP Standard ‐               $0.00 10 ‐            
Machine Drive 25‐99 HP High 0.31             $0.02 10 13.72       
Machine Drive 25‐99 HP Premium 0.49             $0.03 10 10.97       
Machine Drive 100‐249 HP Standard ‐               $0.00 10 ‐            
Machine Drive 100‐249 HP High 0.12             $0.02 10 5.17          
Machine Drive 100‐249 HP Premium 0.15             $0.03 10 3.44          
Machine Drive 250‐499 HP Standard ‐               $0.00 10 ‐            
Machine Drive 250‐499 HP High 0.35             $0.02 10 15.66       
Machine Drive 250‐499 HP Premium 0.47             $0.03 10 10.44       
Machine Drive 500 and more HP Standard ‐               $0.00 10 ‐            
Machine Drive 500 and more HP High 0.59             $0.02 10 26.28       
Machine Drive 500 and more HP Premium 0.78             $0.03 10 17.52       
Miscellaneous Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1034 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-24 www.gepllc.com

Table D-6 Energy Efficiency Equipment Data — Small/Medium Commercial, New Vintage

  Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 1.5 kw/ton, COP 2.3 ‐               $0.00 20 ‐            
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.29             $0.39 20 ‐            
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.35             $0.50 20 0.51          
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.73             $0.62 20 1.90          
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.77             $0.74 20 1.39          
Cooling Central Chiller Variable Refrigerant Flow 1.01             $11.57 20 0.07          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.22             $0.18 16 ‐            
Cooling RTU EER 11.2 0.43             $0.35 16 ‐            
Cooling RTU EER 12.0 0.57             $0.58 16 0.49          
Cooling RTU Ductless VRF 0.69             $5.12 16 0.05          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.09             $0.08 14 0.86          
Cooling PTAC EER 10.8 0.21             $0.16 14 1.00          
Cooling PTAC EER 11 0.25             $0.43 14 0.43          
Cooling PTAC EER 11.5 0.33             $0.96 14 0.27          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.57             $0.39 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.90             $1.18 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 1.20             $1.57 15 0.98          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.31             $1.96 15 0.68          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.46             $11.50 20 0.10          
Combined Heating/Cooling Heat Pump Geothermal Heat Pump 1.75             $20.69 20 ‐            
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.64             $1.22 15 1.35          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.20             $0.09 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.85             $0.03 7 14.85       
Interior Lighting Interior Screw‐in LED 0.93             $1.18 12 0.76          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.27             ($0.07) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.27             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.82             $0.25 6 1.56          
Interior Lighting Linear Fluorescent T5 0.85             $0.43 6 0.95          
Interior Lighting Linear Fluorescent LED 0.89             $3.74 15 0.30          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.13             $0.05 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.54             $0.02 7 15.84       
Exterior Lighting Exterior Screw‐in Metal Halides 0.54             $0.05 4 2.84          
Exterior Lighting Exterior Screw‐in LED 0.60             $0.64 12 0.81          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.20             ($0.13) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.22             $0.55 9 0.33          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.01             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.04             $0.02 6 1.01          
Exterior Lighting Linear Fluorescent T5 0.04             $0.03 6 0.62          
Exterior Lighting Linear Fluorescent LED 0.04             $0.24 15 0.20          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.10             $0.02 15 5.23          
Water Heating Water Heater Geothermal Heat Pump 1.33             $3.53 15 0.43          
Water Heating Water Heater Solar 1.46             $3.03 15 0.55          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.03             $0.04 12 0.80          
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1035 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-25
An EnerNOC Company
Table D-6 Energy Efficiency Equipment Data — Small/Medium Commercial, New Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Food Preparation Oven Efficient 0.39             $0.36 12 1.02          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.02             $0.05 12 0.36          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.40             $0.16 12 2.29          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.00             $0.03 12 0.07          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient ‐               $0.09 18 ‐            
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.16             $0.00 18 56.08       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.19             $0.02 18 9.87          
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.00             $0.00 18 0.24          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.11             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.20             $0.00 10 46.48       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.05             $0.00 12 12.76       
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.19             $0.00 4 23.04       
Office Equipment Desktop Computer Climate Savers 0.27             $0.36 4 0.23          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 7.34          
Office Equipment Laptop Computer Climate Savers 0.03             $0.12 4 0.08          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.12             $0.01 3 2.14          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.22             $0.00 4 19.68       
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.09             $0.04 6 0.98          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.03             $0.00 4 2.96          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.05             $0.06 15 0.95          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.06             $0.06 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.07             $0.11 15 0.72          
Miscellaneous Non‐HVAC Motor Premium (2015)0.08             $0.11 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1036 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-26 www.gepllc.com

Table D-7 Energy Efficiency Equipment Data — Large Commercial, New Vintage

Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 1.5 kw/ton, COP 2.3 ‐               $0.00 20 ‐            
Cooling Central Chiller 1.3 kw/ton, COP 2.7 0.32             $0.24 20 ‐            
Cooling Central Chiller 1.26 kw/ton, COP 2.8 0.39             $0.31 20 0.97          
Cooling Central Chiller 1.0 kw/ton, COP 3.5 0.80             $0.38 20 3.62          
Cooling Central Chiller 0.97 kw/ton, COP 3.6 0.85             $0.45 20 2.66          
Cooling Central Chiller Variable Refrigerant Flow 1.12             $7.06 20 0.12          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.22             $0.13 16 ‐            
Cooling RTU EER 11.2 0.45             $0.25 16 ‐            
Cooling RTU EER 12.0 0.59             $0.41 16 0.75          
Cooling RTU Ductless VRF 0.72             $3.67 16 0.07          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.09             $0.09 14 0.86          
Cooling PTAC EER 10.8 0.21             $0.17 14 1.00          
Cooling PTAC EER 11 0.25             $0.46 14 0.43          
Cooling PTAC EER 11.5 0.34             $1.03 14 0.27          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.46             $0.18 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.73             $0.55 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 0.97             $0.73 15 1.85          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.07             $0.91 15 1.28          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.19             $5.35 20 0.19          
Combined Heating/Cooling Heat Pump Geothermal Heat Pump 1.42             $9.62 20 ‐            
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.30             $1.22 15 1.09          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.17             $0.08 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.71             $0.03 7 12.72       
Interior Lighting Interior Screw‐in LED 0.78             $1.11 12 0.65          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.28             ($0.08) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.27             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.80             $0.25 6 1.49          
Interior Lighting Linear Fluorescent T5 0.83             $0.42 6 0.92          
Interior Lighting Linear Fluorescent LED 0.87             $3.67 15 0.29          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.07             $0.01 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.31             $0.01 7 30.62       
Exterior Lighting Exterior Screw‐in Metal Halides 0.31             $0.02 4 5.49          
Exterior Lighting Exterior Screw‐in LED 0.34             $0.19 12 1.56          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.17             ($0.11) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.18             $0.45 9 0.34          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.01             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.04             $0.02 6 1.06          
Exterior Lighting Linear Fluorescent T5 0.04             $0.03 6 0.65          
Exterior Lighting Linear Fluorescent LED 0.04             $0.24 15 0.20          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.12             $0.02 15 5.71          
Water Heating Water Heater Geothermal Heat Pump 1.54             $3.53 15 0.46          
Water Heating Water Heater Solar 1.69             $3.03 15 0.60          
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.07             $0.02 12 3.52          
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1037 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-27
An EnerNOC Company
Table D-7 Energy Efficiency Equipment Data — Large Commercial, New Vintage (Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Food Preparation Oven Efficient 0.75             $0.46 12 1.43          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.07             $0.10 12 0.58          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.35             $0.30 12 0.99          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.01             $0.03 12 0.24          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient 0.15             $1.26 18 0.13          
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.13             $0.01 18 24.96       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.30             $0.08 18 4.39          
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.00             $0.04 18 0.16          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.15             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.23             $0.00 10 20.70       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.11             $0.02 12 5.62          
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.35             $0.00 4 47.46       
Office Equipment Desktop Computer Climate Savers 0.50             $0.32 4 0.46          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 15.12       
Office Equipment Laptop Computer Climate Savers 0.04             $0.06 4 0.17          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.13             $0.01 3 4.41          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.19             $0.01 4 9.14          
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.08             $0.02 6 2.02          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.01             $0.00 4 2.94          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.06             $0.06 15 0.92          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.06             $0.06 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.08             $0.13 15 0.69          
Miscellaneous Non‐HVAC Motor Premium (2015)0.09             $0.13 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1038 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-28 www.gepllc.com

Table D-8 Energy Efficiency Equipment Data — Extra Large Commercial, New Vintage

  Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 0.75 kw/ton, COP 4.7 ‐               $0.00 20 ‐            
Cooling Central Chiller 0.60 kw/ton, COP 5.9 0.43             $0.09 20 ‐            
Cooling Central Chiller 0.58 kw/ton, COP 6.1 0.49             $0.18 20 0.66          
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 0.57             $0.25 20 0.91          
Cooling Central Chiller 0.51 kw/ton, COP 6.9 0.69             $0.44 20 0.78          
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 0.72             $0.53 20 0.69          
Cooling Central Chiller 0.48 kw/ton, COP 7.3 0.77             $0.62 20 0.68          
Cooling Central Chiller Variable Refrigerant Flow 1.00             $10.92 20 0.05          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.20             $0.24 16 ‐            
Cooling RTU EER 11.2 0.41             $0.44 16 ‐            
Cooling RTU EER 12.0 0.53             $0.73 16 0.37          
Cooling RTU Ductless VRF 0.65             $6.51 16 0.04          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.08             $0.06 14 1.09          
Cooling PTAC EER 10.8 0.19             $0.12 14 1.28          
Cooling PTAC EER 11 0.22             $0.32 14 0.55          
Cooling PTAC EER 11.5 0.30             $0.71 14 0.34          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 0.50             $0.24 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 0.79             $0.73 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 1.06             $0.97 15 1.34          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 1.16             $1.21 15 0.93          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 1.29             $7.10 20 0.14          
Combined Heating/Cooling Heat Pump Geothermal Heat Pump 1.55             $12.77 20 ‐            
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 1.52             $1.22 15 1.27          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.27             $0.14 4 ‐            
Interior Lighting Interior Screw‐in CFL 1.13             $0.06 7 11.90       
Interior Lighting Interior Screw‐in LED 1.24             $1.90 12 0.61          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.11             ($0.05) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.18             ($0.03) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.53             $0.21 6 1.18          
Interior Lighting Linear Fluorescent T5 0.55             $0.35 6 0.72          
Interior Lighting Linear Fluorescent LED 0.58             $3.08 15 0.23          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.02             $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.09             $0.00 7 33.30       
Exterior Lighting Exterior Screw‐in Metal Halides 0.09             $0.00 4 5.97          
Exterior Lighting Exterior Screw‐in LED 0.10             $0.05 12 1.70          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.24             ($0.16) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.25             $0.64 9 0.33          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.00             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.01             $0.00 6 1.01          
Exterior Lighting Linear Fluorescent T5 0.01             $0.01 6 0.62          
Exterior Lighting Linear Fluorescent LED 0.01             $0.06 15 0.19          
Water Heating Water Heater Baseline (EF=0.90)‐               $0.00 15 ‐            
Water Heating Water Heater High Efficiency (EF=0.95) 0.19             $0.02 15 9.79          
Water Heating Water Heater Geothermal Heat Pump 2.47             $3.53 15 0.80          
Water Heating Water Heater Solar 2.72             $3.03 15 1.02          
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1039 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-29
An EnerNOC Company
Table D-9 Energy Efficiency Equipment Data — Extra Large Commercial, New Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Food Preparation Fryer Standard ‐               $0.00 12 ‐            
Food Preparation Fryer Efficient 0.03             $0.00 12 6.02          
Food Preparation Oven Standard ‐               $0.00 12 ‐            
Food Preparation Oven Efficient 0.85             $0.38 12 2.11          
Food Preparation Dishwasher Standard ‐               $0.00 12 ‐            
Food Preparation Dishwasher Efficient 0.03             $0.04 12 0.57          
Food Preparation Hot Food Container Standard ‐               $0.00 12 ‐            
Food Preparation Hot Food Container Efficient 0.17             $0.22 12 0.73          
Food Preparation Food Prep Standard ‐               $0.00 12 ‐            
Food Preparation Food Prep Efficient 0.00             $0.03 12 0.15          
Refrigeration Walk in Refrigeration Standard ‐               $0.00 18 ‐            
Refrigeration Walk in Refrigeration Efficient 0.06             $0.05 18 1.42          
Refrigeration Glass Door Display Standard ‐               $0.00 18 ‐            
Refrigeration Glass Door Display Efficient 0.04             $0.00 18 78.11       
Refrigeration Solid Door Refrigerator Standard ‐               $0.00 18 ‐            
Refrigeration Solid Door Refrigerator Efficient 0.27             $0.02 18 13.75       
Refrigeration Open Display Case Standard ‐               $0.00 18 ‐            
Refrigeration Open Display Case Efficient 0.01             $0.03 18 0.34          
Refrigeration Vending Machine Base ‐               $0.00 10 ‐            
Refrigeration Vending Machine Base (2012)0.13             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency 0.16             $0.00 10 ‐            
Refrigeration Vending Machine High Efficiency (2012)0.24             $0.00 10 68.21       
Refrigeration Icemaker Standard ‐               $0.00 12 ‐            
Refrigeration Icemaker Efficient 0.05             $0.00 12 17.60       
Office Equipment Desktop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Desktop Computer Energy Star 0.25             $0.00 4 32.37       
Office Equipment Desktop Computer Climate Savers 0.35             $0.33 4 0.32          
Office Equipment Laptop Computer Baseline ‐               $0.00 4 ‐            
Office Equipment Laptop Computer Energy Star 0.02             $0.00 4 10.31       
Office Equipment Laptop Computer Climate Savers 0.04             $0.10 4 0.12          
Office Equipment Server Standard ‐               $0.00 3 ‐            
Office Equipment Server Energy Star 0.06             $0.00 3 3.01          
Office Equipment Monitor Standard ‐               $0.00 4 ‐            
Office Equipment Monitor Energy Star 0.11             $0.01 4 6.80          
Office Equipment Printer/copier/fax Standard ‐               $0.00 6 ‐            
Office Equipment Printer/copier/fax Energy Star 0.02             $0.01 6 1.38          
Office Equipment POS Terminal Standard ‐               $0.00 4 ‐            
Office Equipment POS Terminal Energy Star 0.00             $0.00 4 2.01          
Miscellaneous Non‐HVAC Motor Standard ‐               $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor Standard (2015)0.01             $0.00 15 ‐            
Miscellaneous Non‐HVAC Motor High Efficiency 0.03             $0.03 15 1.02          
Miscellaneous Non‐HVAC Motor High Efficiency (2015)0.04             $0.03 15 ‐            
Miscellaneous Non‐HVAC Motor Premium 0.05             $0.07 15 0.76          
Miscellaneous Non‐HVAC Motor Premium (2015)0.05             $0.07 15 ‐            
Miscellaneous Other Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Miscellaneous Other Miscellaneous Miscellaneous (2013)0.00             $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1040 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-30 www.gepllc.com

Table D-9 Energy Efficiency Equipment Data — Extra Large Industrial, New Vintage

  Note: Costs and savings are per sq. ft.
End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Cooling Central Chiller 0.75 kw/ton, COP 4.7 ‐               $0.00 20 ‐            
Cooling Central Chiller 0.60 kw/ton, COP 5.9 1.61             $0.33 20 ‐            
Cooling Central Chiller 0.58 kw/ton, COP 6.1 1.82             $0.66 20 0.68          
Cooling Central Chiller 0.55 kw/Ton, COP 6.4 2.15             $0.93 20 0.94          
Cooling Central Chiller 0.51 kw/ton, COP 6.9 2.58             $1.59 20 0.80          
Cooling Central Chiller 0.50 kw/Ton, COP 7.0 2.68             $1.92 20 0.71          
Cooling Central Chiller 0.48 kw/ton, COP 7.3 2.90             $2.25 20 0.70          
Cooling Central Chiller Variable Refrigerant Flow 3.74             $39.62 20 0.06          
Cooling RTU EER 9.2 ‐               $0.00 16 ‐            
Cooling RTU EER 10.1 0.56             $0.39 16 ‐            
Cooling RTU EER 11.2 1.12             $0.74 16 ‐            
Cooling RTU EER 12.0 1.47             $1.23 16 0.62          
Cooling RTU Ductless VRF 1.79             $10.88 16 0.06          
Cooling PTAC EER 9.8 ‐               $0.00 14 ‐            
Cooling PTAC EER 10.2 0.20             $0.06 14 2.79          
Cooling PTAC EER 10.8 0.47             $0.11 14 3.27          
Cooling PTAC EER 11 0.55             $0.31 14 1.41          
Cooling PTAC EER 11.5 0.75             $0.69 14 0.87          
Combined Heating/Cooling Heat Pump EER 9.3, COP 3.1 ‐               $0.00 15 ‐            
Combined Heating/Cooling Heat Pump EER 10.3, COP 3.2 1.07             $0.92 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.0, COP 3.3 1.69             $2.75 15 ‐            
Combined Heating/Cooling Heat Pump EER 11.7, COP 3.4 2.25             $3.66 15 0.75          
Combined Heating/Cooling Heat Pump EER 12, COP 3.4 2.47             $4.58 15 0.52          
Combined Heating/Cooling Heat Pump Ductless Mini‐Split System 2.74             $26.86 20 0.08          
Combined Heating/Cooling Heat Pump Geothermal Heat Pump 3.29             $48.32 20 ‐            
Space Heating Electric Resistance Standard ‐               $0.00 25 ‐            
Space Heating Furnace Standard ‐               $0.00 18 ‐            
Ventilation Ventilation Constant Volume ‐               $0.00 15 ‐            
Ventilation Ventilation Variable Air Volume 9.66             $1.22 15 8.05          
Interior Lighting Interior Screw‐in Incandescents ‐               $0.00 4 ‐            
Interior Lighting Interior Screw‐in Infrared Halogen 0.08             $0.04 4 ‐            
Interior Lighting Interior Screw‐in CFL 0.34             $0.02 7 13.32       
Interior Lighting Interior Screw‐in LED 0.38             $0.52 12 0.68          
Interior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Interior Lighting HID High Pressure Sodium 0.41             ($0.14) 9 1.00          
Interior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Interior Lighting Linear Fluorescent T8 0.09             ($0.01) 6 1.00          
Interior Lighting Linear Fluorescent Super T8 0.28             $0.08 6 1.56          
Interior Lighting Linear Fluorescent T5 0.29             $0.14 6 0.96          
Interior Lighting Linear Fluorescent LED 0.30             $1.21 15 0.30          
Exterior Lighting Exterior Screw‐in Incandescent ‐               $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in Infrared Halogen 0.01             $0.00 4 ‐            
Exterior Lighting Exterior Screw‐in CFL 0.02             $0.00 7 13.52       
Exterior Lighting Exterior Screw‐in Metal Halides 0.02             $0.00 4 2.42          
Exterior Lighting Exterior Screw‐in LED 0.02             $0.03 12 0.69          
Exterior Lighting HID Metal Halides ‐               $0.00 6 ‐            
Exterior Lighting HID High Pressure Sodium 0.07             ($0.04) 9 1.00          
Exterior Lighting HID Low Pressure Sodium 0.07             $0.18 9 0.33          
Exterior Lighting Linear Fluorescent T12 ‐               $0.00 6 ‐            
Exterior Lighting Linear Fluorescent T8 0.00             ($0.00) 6 1.00          
Exterior Lighting Linear Fluorescent Super T8 0.00             $0.00 6 1.05          
Exterior Lighting Linear Fluorescent T5 0.00             $0.00 6 0.64          
Exterior Lighting Linear Fluorescent LED 0.00             $0.01 15 0.20          
Process Process Cooling/Refrigera Standard ‐               $0.00 10 ‐            
Process Process Cooling/Refrigera Efficient 18.88           $5.59 10 2.49          
Process Process Heating Standard ‐               $0.00 10 ‐            
Process Process Heating Efficient 6.18             $0.57 10 7.97          
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1041 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-31
An EnerNOC Company
Table D-9 Energy Efficiency Equipment Data — Extra Large Industrial, New Vintage
(Cont.)
  Note: Costs and savings are per sq. ft. 

End Use Technology Efficiency Definition
Savings 
(kWh/yr)
 Incremental 
Cost 
Lifetime 
(yrs) BC Ratio
Process Electrochemical Process Standard ‐               $0.00 10 ‐            
Process Electrochemical Process Efficient 13.16           $2.64 10 3.67          
Machine Drive Less than 5 HP Standard ‐               $0.00 10 ‐            
Machine Drive Less than 5 HP High Efficiency 0.05             $0.02 10 2.08          
Machine Drive Less than 5 HP Standard (2015)0.07             $0.00 10 ‐            
Machine Drive Less than 5 HP Premium 0.07             $0.03 10 1.66          
Machine Drive Less than 5 HP High Efficiency (2015)0.11             $0.02 10 ‐            
Machine Drive Less than 5 HP Premium (2015)0.14             $0.03 10 ‐            
Machine Drive 5‐24 HP Standard ‐               $0.00 10 ‐            
Machine Drive 5‐24 HP High 0.11             $0.02 10 5.09          
Machine Drive 5‐24 HP Premium 0.18             $0.03 10 4.07          
Machine Drive 25‐99 HP Standard ‐               $0.00 10 ‐            
Machine Drive 25‐99 HP High 0.31             $0.02 10 13.72       
Machine Drive 25‐99 HP Premium 0.49             $0.03 10 10.97       
Machine Drive 100‐249 HP Standard ‐               $0.00 10 ‐            
Machine Drive 100‐249 HP High 0.12             $0.02 10 5.17          
Machine Drive 100‐249 HP Premium 0.15             $0.03 10 3.44          
Machine Drive 250‐499 HP Standard ‐               $0.00 10 ‐            
Machine Drive 250‐499 HP High 0.35             $0.02 10 15.66       
Machine Drive 250‐499 HP Premium 0.47             $0.03 10 10.44       
Machine Drive 500 and more HP Standard ‐               $0.00 10 ‐            
Machine Drive 500 and more HP High 0.59             $0.02 10 26.28       
Machine Drive 500 and more HP Premium 0.78             $0.03 10 17.52       
Miscellaneous Miscellaneous Miscellaneous ‐               $0.00 5 ‐            
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1042 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-32 www.gepllc.com

Table D-10 Energy Efficiency Measure Data — Small/Med. Comm., Existing Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 14% 90% $0.08 4 0.75
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.20
Chiller ‐ Chilled Water Reset Cooling 14% 0% 0% 0% $0.86 4 0.08
Chiller ‐ Chilled Water Variable‐Flow System Cooling 5% 0% 0% 0% $0.86 10 0.07
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 0% $0.90 20 0.70
Chiller ‐ VSD Cooling 27% 0% 0% 0% $1.17 20 0.48
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 0% 0% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 10% 0% 0% 0% $0.87 14 0.18
Cooling ‐ Economizer Installation Cooling 6% 0% 45% 49% $0.15 15 0.71
Heat Pump ‐ Maintenance Combined Heating/Cooling 7% 7% 10% 95% $0.03 4 5.00
Insulation ‐ Ducting Cooling 6% 0% 9% 50% $0.41 20 0.71
Insulation ‐ Ducting Space Heating 3% 1% 9% 50% $0.41 20 0.71
Repair and Sealing ‐ Ducting Cooling 2% 0% 5% 25% $0.38 15 0.45
Repair and Sealing ‐ Ducting Space Heating 2% 1% 5% 25% $0.38 15 0.45
Energy Management System Cooling 6% 0% 24% 75% $0.35 14 0.72
Energy Management System Space Heating 5% 3% 24% 75% $0.35 14 0.72
Energy Management System Interior Lighting 2% 1% 24% 75% $0.35 14 0.72
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 25% 13% 1% 15% $0.04 10 7.36
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.38
Fans ‐ Variable Speed Control Ventilation 15% 5% 8% 90% $0.20 10 0.89
Retrocommissioning ‐ HVAC Cooling 9% 0% 15% 90% $0.60 4 0.50
Retrocommissioning ‐ HVAC Space Heating 9% 6% 15% 90% $0.60 4 0.50
Retrocommissioning ‐ HVAC Ventilation 9% 6% 15% 90% $0.60 4 0.50
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 0% 34% $0.44 10 1.01
Thermostat ‐ Clock/Programmable Cooling 5% 0% 34% 50% $0.13 11 1.12
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 34% 50% $0.13 11 1.12
Insulation ‐ Ceiling Cooling 2% 0% 10% 18% $0.64 20 0.70
Insulation ‐ Ceiling Space Heating 17% 4% 10% 18% $0.64 20 0.70
Insulation ‐ Radiant Barrier Cooling 3% 0% 7% 13% $0.26 20 0.81
Insulation ‐ Radiant Barrier Space Heating 5% 2% 7% 13% $0.26 20 0.81
Roofs ‐ High Reflectivity Cooling 15% 0% 2% 95% $0.18 15 1.47
Windows ‐ High Efficiency Cooling 5% 0% 61% 75% $0.44 20 0.63
Windows ‐ High Efficiency Space Heating 3% 2% 61% 75% $0.44 20 0.63
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 81% 90% $0.65 8 0.34
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 1% 45% $0.50 8 0.90
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 2% 50% $0.11 8 1.36
Interior Fluorescent ‐ Delamp and Install Reflectors Interior Lighting 20% 10% 18% 25% $0.50 11 0.97
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.50 8 0.36
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.70 11 1.73
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 7% 45% $0.20 8 1.11
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.26
Interior Screw‐in ‐ Task Lighting Interior Lighting 7% 4% 25% 75% $0.24 5 0.09
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 9% 56% $0.20 8 0.56
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 8% 90% $0.01 9 4.28
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 46% 50% $0.28 15 0.37
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 0% $0.11 10 0.64
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 40% 50% $0.02 10 5.87
Water Heater ‐ Thermostat Setback Water Heating 4% 2% 5% 75% $0.11 10 0.47
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 0% $0.02 5 1.56
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 0% 75% $0.20 16 1.10
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 18% 38% $0.35 16 1.25
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.10
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.21
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 1.02
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.00
Retrocommissioning ‐ Comprehensive Cooling 12% 0% 40% 90% $0.70 4 0.71
Retrocommissioning ‐ Comprehensive Space Heating 12% 9% 40% 90% $0.70 4 0.71
Retrocommissioning ‐ Comprehensive Interior Lighting 12% 9% 40% 90% $0.70 4 0.71
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 61.20
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.09
LED Exit Lighting Interior Lighting 2% 2% 9% 86% $0.00 10 12.75
Retrocommissioning ‐ Lighting Interior Lighting 9% 6% 5% 90% $0.10 5 1.59
Retrocommissioning ‐ Lighting Exterior Lighting 9% 6% 5% 90% $0.10 5 1.59
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.00
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.37
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 8.10
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 36.95
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 0% 0% $0.14 8 0.33
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.95
Industrial Process Improvements Miscellaneous 10% 8% 0% 23% $0.52 10 1.16
Custom Measures Cooling 10% 0% 10% 45% $1.50 15 0.59
Custom Measures Space Heating 10% 8% 10% 45% $1.50 15 0.59
Custom Measures Interior Lighting 10% 6% 10% 45% $1.50 15 0.59
Custom Measures Food Preparation 10% 7% 10% 45% $1.50 15 0.59
Custom Measures Refrigeration 10% 5% 10% 45% $1.50 15 0.59
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 19% $0.80 15 0.69
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $4.00 15 0.54
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 47% $8.04 15 1.08
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1043 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-33
An EnerNOC Company
Table D-11 Energy Efficiency Measure Data — Large Commercial, Existing Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 27% 90% $0.06 4 1.30
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.21
Chiller ‐ Chilled Water Reset Cooling 19% 0% 15% 75% $0.18 4 0.50
Chiller ‐ Chilled Water Variable‐Flow System Cooling 5% 0% 30% 34% $0.18 10 0.31
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 66% $0.90 20 0.64
Chiller ‐ VSD Cooling 32% 0% 15% 66% $1.17 20 0.52
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 15% 41% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 9% 0% 5% 75% $0.18 14 0.76
Cooling ‐ Economizer Installation Cooling 11% 0% 44% 49% $0.15 15 1.29
Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 10% 95% $0.06 4 3.04
Insulation ‐ Ducting Cooling 3% 0% 8% 50% $0.41 20 0.52
Insulation ‐ Ducting Space Heating 3% 1% 8% 50% $0.41 20 0.52
Repair and Sealing ‐ Ducting Cooling 2% 0% 5% 25% $0.38 15 0.43
Repair and Sealing ‐ Ducting Space Heating 2% 1% 5% 25% $0.38 15 0.43
Energy Management System Cooling 23% 0% 37% 90% $0.35 14 2.63
Energy Management System Space Heating 18% 12% 37% 90% $0.35 14 2.63
Energy Management System Interior Lighting 9% 6% 37% 90% $0.35 14 2.63
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 13% 7% 1% 11% $0.04 10 2.97
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.11
Fans ‐ Variable Speed Control Ventilation 15% 5% 2% 90% $0.20 10 0.71
Retrocommissioning ‐ HVAC Cooling 12% 0% 15% 90% $0.30 4 0.72
Retrocommissioning ‐ HVAC Space Heating 12% 9% 15% 90% $0.30 4 0.72
Retrocommissioning ‐ HVAC Ventilation 9% 6% 15% 90% $0.30 4 0.72
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 0% 34% $0.13 10 1.05
Thermostat ‐ Clock/Programmable Cooling 5% 0% 33% 50% $0.13 11 1.02
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 33% 50% $0.13 11 1.02
Insulation ‐ Ceiling Cooling 1% 0% 9% 30% $0.85 20 0.45
Insulation ‐ Ceiling Space Heating 12% 3% 9% 30% $0.85 20 0.45
Insulation ‐ Radiant Barrier Cooling 2% 0% 7% 13% $0.26 20 0.64
Insulation ‐ Radiant Barrier Space Heating 5% 2% 7% 13% $0.26 20 0.64
Roofs ‐ High Reflectivity Cooling 5% 0% 2% 75% $0.08 15 1.08
Windows ‐ High Efficiency Cooling 12% 0% 72% 75% $0.88 20 0.74
Windows ‐ High Efficiency Space Heating 11% 8% 72% 75% $0.88 20 0.74
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 86% 90% $0.65 8 0.34
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 1% 45% $0.45 8 0.96
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 2% 13% $0.29 8 0.42
Interior Fluorescent ‐ Delamp and Install Reflectors Interior Lighting 30% 15% 17% 38% $0.50 11 1.40
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.40 8 0.43
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.63 11 1.85
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 13% 45% $0.20 8 1.10
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.21
Interior Screw‐in ‐ Task Lighting Interior Lighting 10% 5% 10% 75% $0.24 5 0.13
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 9% 56% $0.20 8 0.55
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 3% 90% $0.03 9 1.62
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 0% $0.28 15 0.42
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 23% $0.11 10 0.70
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $0.04 10 3.28
Water Heater ‐ Thermostat Setback Water Heating 4% 2% 0% 0% $0.11 10 0.52
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 3% $0.04 5 0.88
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 0% 75% $0.20 16 0.58
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 38% 45% $0.35 16 0.95
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.65
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.37
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 0.65
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.96
Retrocommissioning ‐ Comprehensive Cooling 12% 0% 40% 90% $0.35 4 1.06
Retrocommissioning ‐ Comprehensive Space Heating 12% 9% 40% 90% $0.35 4 1.06
Retrocommissioning ‐ Comprehensive Interior Lighting 12% 9% 40% 90% $0.35 4 1.06
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 68.11
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.11
LED Exit Lighting Interior Lighting 2% 2% 9% 86% $0.00 10 12.29
Retrocommissioning ‐ Lighting Interior Lighting 9% 6% 5% 90% $0.05 5 3.07
Retrocommissioning ‐ Lighting Exterior Lighting 9% 6% 5% 90% $0.05 5 3.07
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.52
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.14
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 6.50
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 33.94
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 1% 2% $0.14 8 0.32
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.78
Industrial Process Improvements Miscellaneous 10% 8% 0% 5% $0.52 10 1.18
Custom Measures Cooling 10% 0% 10% 45% $0.90 15 0.99
Custom Measures Space Heating 10% 8% 10% 45% $0.90 15 0.99
Custom Measures Interior Lighting 10% 8% 10% 45% $0.90 15 0.99
Custom Measures Food Preparation 10% 8% 10% 45% $0.90 15 0.99
Custom Measures Refrigeration 10% 8% 10% 45% $0.90 15 0.99
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 28% $0.80 15 0.77
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 0% $4.00 15 0.59
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $6.00 15 1.04
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1044 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-34 www.gepllc.com

Table D-12 Energy Efficiency Measure Data — Extra Large Comm., Existing Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 47% 90% $0.06 4 1.15
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.19
Chiller ‐ Chilled Water Reset Cooling 15% 0% 30% 75% $0.09 4 0.79
Chiller ‐ Chilled Water Variable‐Flow System Cooling 8% 0% 30% 34% $0.09 10 1.00
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 75% $0.90 20 0.66
Chiller ‐ VSD Cooling 28% 0% 3% 75% $1.17 20 0.47
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 25% 37% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 9% 0% 0% 75% $0.09 14 1.49
Cooling ‐ Economizer Installation Cooling 11% 0% 73% 81% $0.15 15 1.20
Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 5% 95% $0.06 4 2.91
Insulation ‐ Ducting Cooling 8% 0% 2% 50% $0.41 20 0.77
Insulation ‐ Ducting Space Heating 3% 1% 2% 50% $0.41 20 0.77
Repair and Sealing ‐ Ducting Cooling 5% 0% 5% 25% $0.38 15 0.65
Repair and Sealing ‐ Ducting Space Heating 5% 3% 5% 25% $0.38 15 0.65
Energy Management System Cooling 12% 0% 80% 90% $0.35 14 1.21
Energy Management System Space Heating 9% 6% 80% 90% $0.35 14 1.21
Energy Management System Interior Lighting 5% 3% 80% 90% $0.35 14 1.21
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 13% 7% 1% 8% $0.04 10 3.46
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.30
Fans ‐ Variable Speed Control Ventilation 15% 5% 2% 90% $0.20 10 0.83
Retrocommissioning ‐ HVAC Cooling 12% 0% 15% 90% $0.20 4 1.00
Retrocommissioning ‐ HVAC Space Heating 12% 9% 15% 90% $0.20 4 1.00
Retrocommissioning ‐ HVAC Ventilation 9% 6% 15% 90% $0.20 4 1.00
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 1% 34% $0.44 10 1.01
Thermostat ‐ Clock/Programmable Cooling 3% 0% 25% 50% $0.13 11 0.69
Thermostat ‐ Clock/Programmable Space Heating 3% 1% 25% 50% $0.13 11 0.69
Insulation ‐ Ceiling Cooling 1% 0% 2% 9% $0.85 20 0.48
Insulation ‐ Ceiling Space Heating 12% 3% 2% 9% $0.85 20 0.48
Insulation ‐ Radiant Barrier Cooling 1% 0% 2% 13% $0.26 20 0.57
Insulation ‐ Radiant Barrier Space Heating 4% 2% 2% 13% $0.26 20 0.57
Roofs ‐ High Reflectivity Cooling 10% 0% 0% 95% $0.18 15 0.90
Windows ‐ High Efficiency Cooling 6% 0% 95% 100% $2.10 20 0.37
Windows ‐ High Efficiency Space Heating 2% 2% 95% 100% $2.10 20 0.37
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 78% 90% $0.65 8 0.26
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 3% 45% $0.40 8 0.72
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 2% 10% $0.29 8 0.45
Interior Fluorescent ‐ Delamp and Install Reflectors Interior Lighting 30% 15% 3% 25% $0.50 11 0.93
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.20 8 0.57
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.56 11 1.38
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 42% 45% $0.20 8 0.84
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.23
Interior Screw‐in ‐ Task Lighting Interior Lighting 10% 5% 5% 75% $0.24 5 0.18
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 12% 56% $0.20 8 0.42
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 2% 90% $0.03 9 2.66
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 0% $0.28 15 0.70
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 23% $0.11 10 1.19
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $0.04 10 5.48
Water Heater ‐ Thermostat Setback Water Heating 4% 0% 0% 0% $0.11 10 0.72
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 0% $0.04 5 1.45
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 10% 75% $0.20 16 0.02
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 10% 38% $0.35 16 0.34
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.13
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.28
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 0.29
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.18
Retrocommissioning ‐ Comprehensive Cooling 12% 0% 40% 90% $0.25 4 1.21
Retrocommissioning ‐ Comprehensive Space Heating 12% 9% 40% 90% $0.25 4 1.21
Retrocommissioning ‐ Comprehensive Interior Lighting 12% 9% 40% 90% $0.25 4 1.21
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 39.11
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.12
LED Exit Lighting Interior Lighting 2% 2% 9% 86% $0.00 10 18.34
Retrocommissioning ‐ Lighting Interior Lighting 9% 6% 5% 90% $0.05 5 2.54
Retrocommissioning ‐ Lighting Exterior Lighting 9% 6% 5% 90% $0.05 5 2.54
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.04
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.61
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 6.95
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 20.31
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 0% 0% $0.14 8 0.47
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.07
Industrial Process Improvements Miscellaneous 10% 8% 0% 0% $0.52 10 1.11
Custom Measures Cooling 10% 0% 10% 45% $0.67 15 1.09
Custom Measures Space Heating 10% 8% 10% 45% $0.67 15 1.09
Custom Measures Interior Lighting 10% 8% 10% 45% $0.67 15 1.09
Custom Measures Food Preparation 10% 8% 10% 45% $0.67 15 1.09
Custom Measures Refrigeration 10% 8% 10% 45% $0.67 15 1.09
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 41% $0.80 15 1.28
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 0% $4.00 15 1.00
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $4.00 15 1.66
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1045 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-35
An EnerNOC Company
Table D-13 Energy Efficiency Measure Data — Extra Large Industrial, Existing Vintage
  Note: Costs are per sq. ft.

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Refrigeration ‐ System Controls Process 11% 8% 5% 34% $0.40 10 18.09
Refrigeration ‐ System Maintenance Process 3% 2% 5% 34% $0.00 10 2,067.93
Refrigeration ‐ System Optimization Process 15% 11% 5% 34% $0.80 10 12.92
Motors ‐ Variable Frequency Drive Machine Drive 13% 9% 25% 38% $0.10 10 3.38
Motors ‐ Magnetic Adjustable Speed Drives Machine Drive 13% 9% 25% 38% $0.10 10 3.38
Compressed Air ‐ System Controls Machine Drive 9% 7% 5% 34% $0.40 10 0.59
Compressed Air ‐ System Optimization and Improvements Machine Drive 13% 9% 5% 34% $0.80 10 0.42
Compressed Air ‐ System Maintenance Machine Drive 3% 2% 5% 34% $0.20 10 0.34
Compressed Air ‐ Compressor Replacement Machine Drive 5% 4% 5% 34% $0.20 10 0.68
Fan System ‐ Controls Machine Drive 4% 3% 10% 38% $0.35 10 0.11
Fan System ‐ Controls Machine Drive 4% 3%10%38% $0.35 10 0.11
Fan System ‐ Optimization Machine Drive 6% 5% 10% 38% $0.70 10 0.08
Fan System ‐ Optimization Machine Drive 6% 5% 10% 38% $0.70 10 0.08
Fan System ‐ Maintenance Machine Drive 1% 1% 10% 38% $0.15 10 0.07
Fan System ‐ Maintenance Machine Drive 1% 1% 10% 38% $0.15 10 0.07
Pumping System ‐ Controls Machine Drive 5% 4% 5% 34% $0.38 12 0.43
Pumping System ‐ Optimization Machine Drive 13% 9% 5% 34% $0.75 12 0.54
Pumping System ‐ Maintenance Machine Drive 2% 1% 5% 34% $0.19 10 0.27
RTU ‐ Maintenance Cooling 14% 0% 22% 90% $0.06 4 3.18
Chiller ‐ Chilled Water Reset Cooling 14% 0% 30% 75% $0.09 4 2.69
Chiller ‐ Chilled Water Variable‐Flow System Cooling 5% 0% 30% 34% $0.20 10 1.05
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 67% $0.90 20 2.48
Chiller ‐ VSD Cooling 26% 0% 15% 67% $1.17 20 1.68
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 25% 50% $0.04 10 0.03
Chiller ‐ Condenser Water Temprature Reset Cooling 10% 0% 0% 75% $0.20 14 2.72
Cooling ‐ Economizer Installation Cooling 6% 0% 29% 34% $0.15 15 2.02
Heat Pump ‐ Maintenance Combined Heating/Cooling 7% 7% 2% 95% $0.03 4 8.67
Insulation ‐ Ducting Space Heating 6% 6% 12% 50% $0.41 20 1.01
Insulation ‐ Ducting Cooling 3% 0% 12% 50% $0.41 20 1.01
Repair and Sealing ‐ Ducting Cooling 2% 0% 5% 25% $0.38 15 0.63
Repair and Sealing ‐ Ducting Space Heating 2% 1% 5% 25% $0.38 15 0.63
Energy Management System Cooling 6% 0% 11% 90% $0.35 14 1.09
Energy Management System Space Heating 5% 3% 11% 90% $0.35 14 1.09
Energy Management System Interior Lighting 2% 1% 11% 90% $0.35 14 1.09
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 2% 90% $0.14 10 2.94
Fans ‐ Variable Speed Control Ventilation 15% 5% 3% 90% $0.20 10 5.29
Retrocommissioning ‐ HVAC Cooling 12% 0% 1% 70% $0.25 4 1.54
Retrocommissioning ‐ HVAC Space Heating 12% 9% 1% 70% $0.25 4 1.54
Retrocommissioning ‐ HVAC Ventilation 9% 6% 1% 70% $0.25 4 1.54
Pumps ‐ Variable Speed Control Machine Drive 5% 4% 0% 34% $0.44 10 0.31
Thermostat ‐ Clock/Programmable Cooling 5% 0% 59% 70% $0.13 11 2.11
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 59% 70% $0.13 11 2.11
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 84% 90% $0.65 8 0.17
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 2% 27% $0.08 8 0.46
Interior Fluorescent ‐ Delamp and Install Reflectors Interior Lighting 20% 10% 17% 38% $0.50 11 0.31
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 38% $0.20 11 1.95
LED Exit Lighting Interior Lighting 2% 2% 9% 86% $0.00 10 4.00
Retrocommissioning ‐ Lighting Interior Lighting 9% 6% 9% 70% $0.05 5 1.44
Retrocommissioning ‐ Lighting Exterior Lighting 9% 6% 9% 70% $0.05 5 1.44
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 15% 45% $0.20 8 0.55
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.07
Interior Screw‐in ‐ Task Lighting Interior Lighting 7% 4% 10% 75% $0.24 5 0.03
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 2% 56% $0.20 8 0.27
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 0.46
Custom Measures Cooling 10% 0% 10% 45% $1.60 15 1.63
Custom Measures Space Heating 10% 8% 10% 45% $1.60 15 1.63
Custom Measures Interior Lighting 10% 8% 10% 45% $1.60 15 1.63
Custom Measures Machine Drive 10% 8% 10% 45% $1.60 15 1.63
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $4.00 15 2.67
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1046 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-36 www.gepllc.com

Table D-14 Energy Efficiency Measure Data — Small/Medium Comm., New Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 14% 90% $0.08 4 0.82
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.18
Chiller ‐ Chilled Water Reset Cooling 11% 0% 0% 0% $0.86 4 0.06
Chiller ‐ Chilled Water Variable‐Flow System Cooling 4% 0% 0% 0% $0.86 10 0.05
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 0% $0.90 20 0.63
Chiller ‐ VSD Cooling 26% 0% 0% 0% $1.17 20 0.42
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 0% 0% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 8% 0% 0% 0% $0.87 14 0.13
Cooling ‐ Economizer Installation Cooling 6% 0% 45% 49% $0.15 15 0.65
Heat Pump ‐ Maintenance Combined Heating/Cooling 7% 7% 10% 95% $0.03 4 4.32
Insulation ‐ Ducting Cooling 5% 0% 9% 50% $0.41 20 0.64
Insulation ‐ Ducting Space Heating 3% 1% 9% 50% $0.41 20 0.64
Energy Management System Cooling 5% 0% 24% 75% $0.35 14 0.55
Energy Management System Space Heating 2% 1% 24% 75% $0.35 14 0.55
Energy Management System Interior Lighting 2% 1% 24% 75% $0.35 14 0.55
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 25% 13% 1% 15% $0.04 10 7.04
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.32
Fans ‐ Variable Speed Control Ventilation 15% 5% 8% 90% $0.20 10 0.85
Commissioning ‐ HVAC Cooling 5% 0% 40% 75% $0.90 25 0.33
Commissioning ‐ HVAC Space Heating 5% 4% 40% 75% $0.90 25 0.33
Commissioning ‐ HVAC Ventilation 5% 4% 40% 75% $0.90 25 0.33
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 5% 34% $0.44 10 1.01
Thermostat ‐ Clock/Programmable Cooling 5% 0% 34% 50% $0.13 11 1.06
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 34% 50% $0.13 11 1.06
Insulation ‐ Ceiling Cooling 1% 0% 10% 81% $0.16 20 1.60
Insulation ‐ Ceiling Space Heating 15% 4% 10% 81% $0.16 20 1.60
Insulation ‐ Radiant Barrier Cooling 2% 0% 7% 13% $0.26 20 0.76
Insulation ‐ Radiant Barrier Space Heating 6% 2% 7% 13% $0.26 20 0.76
Roofs ‐ High Reflectivity Cooling 7% 0% 5% 95% $0.09 15 1.25
Windows ‐ High Efficiency Cooling 5% 0% 61% 75% $0.35 20 0.69
Windows ‐ High Efficiency Space Heating 3% 2% 61% 75% $0.35 20 0.69
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 81% 90% $0.65 8 0.31
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 1% 45% $0.38 8 1.07
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 10% 75% $0.09 8 1.50
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.50 8 0.32
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.70 11 1.56
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 7% 45% $0.20 8 1.00
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.24
Interior Screw‐in ‐ Task Lighting Interior Lighting 7% 4% 25% 75% $0.24 5 0.08
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 9% 56% $0.20 8 0.50
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 8% 90% $0.01 9 4.22
Water Heater ‐ Pipe Insulation Water Heating 4% 2% 46% 50% $0.28 15 0.24
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 0% $0.11 10 0.63
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 40% 50% $0.02 10 5.80
Water Heater ‐ Thermostat Setback Water Heating 4% 0% 10% 75% $0.11 10 0.38
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 0% $0.02 5 1.53
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 0% 75% $0.20 16 1.09
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 18% 38% $0.35 16 1.24
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.09
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.20
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 1.02
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.00
Commissioning ‐ Comprehensive Cooling 10% 0% 40% 75% $1.25 25 0.83
Commissioning ‐ Comprehensive Space Heating 10% 7% 40% 75% $1.25 25 0.83
Commissioning ‐ Comprehensive Interior Lighting 10% 7% 40% 75% $1.25 25 0.83
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 61.07
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.08
LED Exit Lighting Interior Lighting 2% 2% 85% 86% $0.00 10 11.83
Commissioning ‐ Lighting Interior Lighting 5% 4% 30% 75% $0.20 25 1.54
Commissioning ‐ Lighting Exterior Lighting 5% 4% 30% 75% $0.20 25 1.54
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.00
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.23
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 7.30
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 36.95
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 0% 0% $0.14 8 0.30
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.95
Advanced New Construction Designs Cooling 40% 0% 5% 75% $2.00 35 2.01
Advanced New Construction Designs Space Heating 40% 30% 5% 75% $2.00 35 2.01
Advanced New Construction Designs Interior Lighting 25% 19% 5% 75% $2.00 35 2.01
Insulation ‐ Wall Cavity Cooling 1% 0% 10% 68% $0.34 20 0.72
Insulation ‐ Wall Cavity Space Heating 10% 2% 10% 68% $0.34 20 0.72
Roofs ‐ Green Cooling 7% 0% 2% 11% $1.00 30 0.26
Roofs ‐ Green Space Heating 4% 3% 2% 11% $1.00 30 0.26
Industrial Process Improvements Miscellaneous 10% 8% 0% 23% $0.52 10 1.16
Custom Measures Cooling 8% 0% 10% 45% $1.50 15 0.45
Custom Measures Space Heating 8% 6% 10% 45% $1.50 15 0.45
Custom Measures Interior Lighting 8% 6% 10% 45% $1.50 15 0.45
Custom Measures Food Preparation 8% 6% 10% 45% $1.50 15 0.45
Custom Measures Refrigeration 8% 6% 10% 45% $1.50 15 0.45
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 19% $0.80 15 0.68
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 50% $4.00 15 0.53
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 47% $8.04 15 1.01
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1047 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-37
An EnerNOC Company
Table D-15 Energy Efficiency Measure Data — Large Commercial, New Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 27% 90% $0.06 4 1.13
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.19
Chiller ‐ Chilled Water Reset Cooling 18% 0% 30% 75% $0.18 4 0.42
Chiller ‐ Chilled Water Variable‐Flow System Cooling 5% 0% 30% 34% $0.18 10 0.28
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 66% $0.90 20 0.61
Chiller ‐ VSD Cooling 32% 0% 15% 66% $1.17 20 0.50
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 15% 41% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 8% 0% 25% 75% $0.18 14 0.63
Cooling ‐ Economizer Installation Cooling 11% 0% 44% 49% $0.15 15 1.19
Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 10% 95% $0.06 4 2.72
Insulation ‐ Ducting Cooling 4% 0% 8% 50% $0.41 20 0.56
Insulation ‐ Ducting Space Heating 3% 1% 8% 50% $0.41 20 0.56
Energy Management System Cooling 21% 0% 48% 90% $0.35 14 2.10
Energy Management System Space Heating 8% 5% 48% 90% $0.35 14 2.10
Energy Management System Interior Lighting 9% 6% 48% 90% $0.35 14 2.10
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 13% 7% 1% 11% $0.04 10 2.84
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.07
Fans ‐ Variable Speed Control Ventilation 15% 5% 2% 90% $0.20 10 0.68
Commissioning ‐ HVAC Cooling 5% 0% 50% 75% $0.85 25 0.30
Commissioning ‐ HVAC Space Heating 5% 4% 50% 75% $0.85 25 0.30
Commissioning ‐ HVAC Ventilation 5% 4% 50% 75% $0.85 25 0.30
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 5% 34% $0.13 10 1.05
Thermostat ‐ Clock/Programmable Cooling 5% 0% 33% 50% $0.13 11 0.97
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 33% 50% $0.13 11 0.97
Insulation ‐ Ceiling Cooling 1% 0% 75% 81% $0.35 20 0.60
Insulation ‐ Ceiling Space Heating 10% 3% 75% 81% $0.35 20 0.60
Insulation ‐ Radiant Barrier Cooling 1% 0% 7% 13% $0.26 20 0.56
Insulation ‐ Radiant Barrier Space Heating 5% 2% 7% 13% $0.26 20 0.56
Roofs ‐ High Reflectivity Cooling 4% 0% 5% 95% $0.05 15 1.28
Windows ‐ High Efficiency Cooling 12% 0% 72% 75% $0.88 20 0.72
Windows ‐ High Efficiency Space Heating 11% 8% 72% 75% $0.88 20 0.72
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 86% 90% $0.65 8 0.30
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 1% 45% $0.34 8 1.14
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 10% 19% $0.19 8 0.57
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.40 8 0.39
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.63 11 1.66
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 13% 45% $0.20 8 0.99
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.19
Interior Screw‐in ‐ Task Lighting Interior Lighting 10% 5% 10% 75% $0.24 5 0.11
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 9% 56% $0.20 8 0.49
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 3% 90% $0.03 9 1.60
Water Heater ‐ Pipe Insulation Water Heating 4% 2% 0% 0% $0.28 15 0.27
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 23% $0.11 10 0.69
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $0.04 10 3.23
Water Heater ‐ Thermostat Setback Water Heating 4% 0% 0% 0% $0.11 10 0.44
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 3% $0.04 5 0.87
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 0% 75% $0.20 16 0.58
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 38% 45% $0.35 16 0.94
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.63
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.35
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 0.65
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.94
Commissioning ‐ Comprehensive Cooling 10% 0% 40% 75% $1.00 25 0.96
Commissioning ‐ Comprehensive Space Heating 10% 7% 40% 75% $1.00 25 0.96
Commissioning ‐ Comprehensive Interior Lighting 10% 7% 40% 75% $1.00 25 0.96
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 67.83
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.09
LED Exit Lighting Interior Lighting 2% 2% 85% 86% $0.00 10 11.13
Commissioning ‐ Lighting Interior Lighting 5% 4% 60% 75% $0.15 25 1.99
Commissioning ‐ Lighting Exterior Lighting 5% 4% 60% 75% $0.15 25 1.99
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.52
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.03
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 5.86
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 33.94
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 1% 2% $0.14 8 0.29
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.78
Advanced New Construction Designs Cooling 40% 0% 5% 75% $2.00 35 1.84
Advanced New Construction Designs Space Heating 40% 30% 5% 75% $2.00 35 1.84
Advanced New Construction Designs Interior Lighting 25% 19% 5% 75% $2.00 35 1.84
Insulation ‐ Wall Cavity Cooling 1% 0% 9% 68% $0.78 20 0.43
Insulation ‐ Wall Cavity Space Heating 10% 2% 9% 68% $0.78 20 0.43
Roofs ‐ Green Cooling 4% 0% 2% 13% $1.00 15 0.08
Roofs ‐ Green Space Heating 2% 2% 2% 13% $1.00 15 0.08
Industrial Process Improvements Miscellaneous 10% 8% 0% 5% $0.52 10 1.18
Custom Measures Cooling 8% 0% 10% 45% $0.90 15 0.73
Custom Measures Space Heating 8% 6% 10% 45% $0.90 15 0.73
Custom Measures Interior Lighting 8% 6% 10% 45% $0.90 15 0.73
Custom Measures Food Preparation 8% 6% 10% 45% $0.90 15 0.73
Custom Measures Refrigeration 8% 6% 10% 45% $0.90 15 0.73
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 28% $0.80 15 0.76
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 0% $4.00 15 0.58
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $6.00 15 0.98
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1048 of 1069
Commercial Energy Efficiency Equipment and Measure Data

D-38 www.gepllc.com

Table D-16 Energy Efficiency Measure Data — Extra Large Commercial, New Vintage

  Note: Costs are per sq. ft.
Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
RTU ‐ Maintenance Cooling 14% 0% 47% 90% $0.06 4 1.02
RTU ‐ Evaporative Precooler Cooling 10% 0% 0% 0% $0.88 15 0.17
Chiller ‐ Chilled Water Reset Cooling 12% 0% 60% 75% $0.09 4 0.61
Chiller ‐ Chilled Water Variable‐Flow System Cooling 8% 0% 30% 34% $0.09 10 0.95
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 75% $0.90 20 0.64
Chiller ‐ VSD Cooling 28% 0% 3% 75% $1.17 20 0.45
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 25% 37% $0.04 10 0.01
Chiller ‐ Condenser Water Temprature Reset Cooling 8% 0% 25% 75% $0.09 14 1.28
Cooling ‐ Economizer Installation Cooling 11% 0% 73% 81% $0.15 15 1.14
Heat Pump ‐ Maintenance Combined Heating/Cooling 10% 10% 5% 95% $0.06 4 2.61
Insulation ‐ Ducting Cooling 7% 0% 2% 50% $0.41 20 0.71
Insulation ‐ Ducting Space Heating 3% 1% 2% 50% $0.41 20 0.71
Energy Management System Cooling 11% 0% 80% 90% $0.35 14 0.94
Energy Management System Space Heating 4% 2% 80% 90% $0.35 14 0.94
Energy Management System Interior Lighting 5% 3% 80% 90% $0.35 14 0.94
Cooking ‐ Exhaust Hoods with Sensor Control Ventilation 13% 7% 1% 8% $0.04 10 3.31
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 11% 90% $0.05 10 1.24
Fans ‐ Variable Speed Control Ventilation 15% 5% 2% 90% $0.20 10 0.80
Commissioning ‐ HVAC Cooling 5% 0% 50% 75% $0.70 25 0.42
Commissioning ‐ HVAC Space Heating 5% 4% 50% 75% $0.70 25 0.42
Commissioning ‐ HVAC Ventilation 5% 4% 50% 75% $0.70 25 0.42
Pumps ‐ Variable Speed Control Miscellaneous 1% 0% 1% 34% $0.44 10 1.01
Thermostat ‐ Clock/Programmable Cooling 3% 0% 25% 50% $0.13 11 0.67
Thermostat ‐ Clock/Programmable Space Heating 3% 1% 25% 50% $0.13 11 0.67
Insulation ‐ Ceiling Cooling 1% 0% 2% 81% $0.35 20 0.68
Insulation ‐ Ceiling Space Heating 10% 3% 2% 81% $0.35 20 0.68
Insulation ‐ Radiant Barrier Cooling 1% 0% 2% 13% $0.26 20 0.47
Insulation ‐ Radiant Barrier Space Heating 2% 1% 2% 13% $0.26 20 0.47
Roofs ‐ High Reflectivity Cooling 10% 0% 5% 95% $0.18 15 0.85
Windows ‐ High Efficiency Cooling 6% 0% 95% 100% $1.69 20 0.38
Windows ‐ High Efficiency Space Heating 2% 2% 95% 100% $1.69 20 0.38
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 78% 90% $0.65 8 0.23
Interior Lighting ‐ Photocell Controlled T8 Dimming Ballasts Interior Lighting 25% 13% 3% 45% $0.30 8 0.86
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 10% 15% $0.19 8 0.61
Interior Fluorescent ‐ Bi‐Level Fixture w/Occupancy Sensor Interior Lighting 10% 5% 10% 23% $0.20 8 0.52
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 23% $0.56 11 1.24
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 42% 45% $0.20 8 0.76
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.20
Interior Screw‐in ‐ Task Lighting Interior Lighting 10% 5% 25% 75% $0.24 5 0.16
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 12% 56% $0.20 8 0.38
Water Heater ‐ Faucet Aerators/Low Flow Nozzles Water Heating 4% 1% 2% 90% $0.03 9 2.63
Water Heater ‐ Pipe Insulation Water Heating 6% 3% 0% 0% $0.28 15 0.69
Water Heater ‐ High Efficiency Circulation Pump Water Heating 5% 4% 0% 23% $0.11 10 1.18
Water Heater ‐ Tank Blanket/Insulation Water Heating 9% 5% 0% 0% $0.04 10 5.43
Water Heater ‐ Thermostat Setback Water Heating 4% 0% 0% 0% $0.11 10 0.71
Water Heater ‐ Hot Water Saver Water Heating 5% 1% 0% 0% $0.04 5 1.43
Refrigeration ‐ Anti‐Sweat Heater/Auto Door Closer Refrigeration 5% 3% 10% 75% $0.20 16 0.02
Refrigeration ‐ Floating Head Pressure Refrigeration 7% 4% 10% 38% $0.35 16 0.32
Refrigeration ‐ Door Gasket Replacement Refrigeration 4% 2% 5% 75% $0.10 8 0.12
Insulation ‐ Bare Suction Lines Refrigeration 3% 2% 5% 75% $0.10 8 0.26
Refrigeration ‐ Night Covers Refrigeration 6% 3% 5% 75% $0.05 8 0.27
Refrigeration ‐ Strip Curtain Refrigeration 4% 2% 5% 56% $0.02 8 0.17
Commissioning ‐ Comprehensive Cooling 10% 0% 40% 75% $0.80 25 1.05
Commissioning ‐ Comprehensive Space Heating 10% 7% 40% 75% $0.80 25 1.05
Commissioning ‐ Comprehensive Interior Lighting 10% 7% 40% 75% $0.80 25 1.05
Office Equipment ‐ Energy Star Power Supply Office Equipment 1% 1% 10% 95% $0.00 7 38.86
Vending Machine ‐ Controller Refrigeration 15% 11% 2% 10% $0.27 10 1.10
LED Exit Lighting Interior Lighting 2% 2% 85% 86% $0.00 10 16.52
Commissioning ‐ Lighting Interior Lighting 5% 4% 60% 75% $0.10 25 2.47
Commissioning ‐ Lighting Exterior Lighting 5% 4% 60% 75% $0.10 25 2.47
Refrigeration ‐ High Efficiency Case Lighting Refrigeration 4% 2% 5% 75% $0.20 8 0.04
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 1.45
Exterior Lighting ‐ Induction Lamps Exterior Lighting 3% 3% 5% 56% $0.00 5 6.26
Laundry ‐ High Efficiency Clothes Washer Miscellaneous 0% 0% 5% 10% $0.00 10 20.31
Interior Lighting ‐ Hotel Guestroom Controls Interior Lighting 10% 5% 0% 0% $0.14 8 0.42
Miscellaneous ‐ Energy Star Water Cooler Miscellaneous 0% 0% 5% 95% $0.00 8 1.07
Advanced New Construction Designs Cooling 40% 0% 5% 75% $2.00 35 1.67
Advanced New Construction Designs Space Heating 40% 30% 5% 75% $2.00 35 1.67
Advanced New Construction Designs Interior Lighting 25% 19% 5% 75% $2.00 35 1.67
Insulation ‐ Wall Cavity Cooling 1% 0% 2% 68% $0.09 20 1.73
Insulation ‐ Wall Cavity Space Heating 10% 2% 2% 68% $0.09 20 1.73
Roofs ‐ Green Cooling 10% 0% 2% 13% $1.00 15 0.20
Roofs ‐ Green Space Heating 5% 3% 2% 13% $1.00 15 0.20
Industrial Process Improvements Miscellaneous 10% 8% 0% 0% $0.52 10 1.11
Custom Measures Cooling 8% 0% 10% 45% $0.67 15 0.81
Custom Measures Space Heating 8% 6% 10% 45% $0.67 15 0.81
Custom Measures Interior Lighting 8% 6% 10% 45% $0.67 15 0.81
Custom Measures Food Preparation 8% 6% 10% 45% $0.67 15 0.81
Custom Measures Refrigeration 8% 6% 10% 45% $0.67 15 0.81
Water Heater ‐ Heat Pump Water Heating 30% 15% 0% 41% $0.80 15 1.27
Water Heater ‐ Convert to Gas Water Heating 100% 100% 0% 0% $4.00 15 1.00
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $4.00 15 1.57
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1049 of 1069
Commercial Energy Efficiency Equipment and Measure Data
Global Energy Partners D-39
An EnerNOC Company
Table D-17 Energy Efficiency Measure Data — Extra Large Industrial, New Vintage
  Note: Costs are per sq. ft.

Measure Enduse
Energy 
Savings
Demand 
Savings
Base 
Saturation
Appl./
Feas. Cost Lifetime BC Ratio
Refrigeration ‐ System Controls Process 11% 8% 5% 34% $0.40 10 18.09
Refrigeration ‐ System Maintenance Process 3% 2% 5% 34% $0.00 10 2,067.93
Refrigeration ‐ System Optimization Process 15% 11% 5% 34% $0.80 10 12.92
Motors ‐ Variable Frequency Drive Machine Drive 13% 9% 25% 38% $0.10 10 3.38
Motors ‐ Magnetic Adjustable Speed Drives Machine Drive 13% 9% 25% 38% $0.10 10 3.38
Compressed Air ‐ System Controls Machine Drive 9% 7% 5% 34% $0.40 10 0.59
Compressed Air ‐ System Optimization and Improvements Machine Drive 13% 9% 5% 34% $0.80 10 0.42
Compressed Air ‐ System Maintenance Machine Drive 3% 2% 5% 34% $0.20 10 0.34
Compressed Air ‐ Compressor Replacement Machine Drive 5% 4% 5% 34% $0.20 10 0.68
Fan System ‐ Controls Machine Drive 4% 3% 10% 38% $0.35 10 0.11
Fan System ‐ Controls Machine Drive 4% 3%10%38% $0.35 10 0.11
Fan System ‐ Optimization Machine Drive 6% 5% 10% 38% $0.70 10 0.08
Fan System ‐ Optimization Machine Drive 6% 5% 10% 38% $0.70 10 0.08
Fan System ‐ Maintenance Machine Drive 1% 1% 10% 38% $0.15 10 0.07
Fan System ‐ Maintenance Machine Drive 1% 1% 10% 38% $0.15 10 0.07
Pumping System ‐ Controls Machine Drive 5% 4% 5% 34% $0.38 12 0.42
Pumping System ‐ Optimization Machine Drive 13% 9% 5% 34% $0.75 12 0.54
Pumping System ‐ Maintenance Machine Drive 2% 1% 5% 34% $0.19 10 0.27
RTU ‐ Maintenance Cooling 14% 0% 22% 90% $0.06 4 2.82
Chiller ‐ Chilled Water Reset Cooling 14% 0% 60% 75% $0.09 4 2.53
Chiller ‐ Chilled Water Variable‐Flow System Cooling 4% 0% 30% 34% $0.20 10 0.80
Chiller ‐ Turbocor Compressor Cooling 30% 0% 0% 67% $0.90 20 2.40
Chiller ‐ VSD Cooling 27% 0% 25% 67% $1.17 20 1.63
Chiller ‐ High Efficiency Cooling Tower Fans Cooling 0% 0% 25% 50% $0.04 10 0.04
Chiller ‐ Condenser Water Temprature Reset Cooling 10% 0% 5% 75% $0.20 14 2.60
Cooling ‐ Economizer Installation Cooling 6% 0% 29% 34% $0.15 15 1.92
Heat Pump ‐ Maintenance Combined Heating/Cooling 7% 7% 2% 95% $0.03 4 7.76
Insulation ‐ Ducting Space Heating 5% 5% 12% 50% $0.41 20 0.95
Insulation ‐ Ducting Cooling 3% 0% 12% 50% $0.41 20 0.95
Energy Management System Cooling 5% 0% 11% 90% $0.35 14 0.88
Energy Management System Space Heating 2% 1% 11% 90% $0.35 14 0.88
Energy Management System Interior Lighting 2% 1% 11% 90% $0.35 14 0.88
Fans ‐ Energy Efficient Motors Ventilation 5% 5% 2% 90% $0.14 10 2.81
Fans ‐ Variable Speed Control Ventilation 15% 5% 3% 90% $0.34 10 2.97
Commissioning ‐ HVAC Cooling 5% 0% 60% 75% $0.70 25 0.92
Commissioning ‐ HVAC Space Heating 5% 4% 60% 75% $0.70 25 0.92
Commissioning ‐ HVAC Ventilation 5% 4% 60% 75% $0.70 25 0.92
Pumps ‐ Variable Speed Control Machine Drive 5% 4% 0% 34% $0.44 10 0.31
Thermostat ‐ Clock/Programmable Cooling 5% 0% 59% 70% $0.13 11 2.02
Thermostat ‐ Clock/Programmable Space Heating 5% 1% 59% 70% $0.13 11 2.02
Interior Lighting ‐ Central Lighting Controls Interior Lighting 10% 5% 84% 90% $0.65 8 0.15
Exterior Lighting ‐ Daylighting Controls Exterior Lighting 30% 0% 10% 40% $0.08 8 0.42
Interior Fluorescent ‐ High Bay Fixtures Interior Lighting 50% 25% 10% 38% $0.20 11 1.76
LED Exit Lighting Interior Lighting 2% 2% 85% 86% $0.00 10 3.72
Commissioning ‐ Lighting Interior Lighting 5% 4% 60% 75% $0.10 25 1.41
Commissioning ‐ Lighting Exterior Lighting 5% 4% 60% 75% $0.10 25 1.41
Interior Lighting ‐ Occupancy Sensors Interior Lighting 10% 5% 15% 45% $0.20 8 0.50
Exterior Lighting ‐ Photovoltaic Installation Exterior Lighting 75% 75% 5% 13% $0.92 5 0.06
Interior Screw‐in ‐ Task Lighting Interior Lighting 7% 4% 10% 75% $0.24 5 0.03
Interior Lighting ‐ Time Clocks and Timers Interior Lighting 5% 3% 2% 56% $0.20 8 0.25
Exterior Lighting ‐ Cold Cathode Lighting Exterior Lighting 1% 1% 5% 25% $0.00 5 0.41
Advanced New Construction Designs Cooling 40% 0% 5% 75% $2.00 35 2.67
Advanced New Construction Designs Space Heating 40% 30% 5% 75% $2.00 35 2.67
Advanced New Construction Designs Interior Lighting 25% 19% 5% 75% $2.00 35 2.67
Custom Measures Cooling 8% 0% 10% 45% $1.60 15 1.28
Custom Measures Space Heating 8% 6% 10% 45% $1.60 15 1.28
Custom Measures Interior Lighting 8% 6% 10% 45% $1.60 15 1.28
Custom Measures Machine Drive 8% 6% 10% 45% $1.60 15 1.28
Furnace ‐ Convert to Gas Space Heating 100% 100% 0% 0% $4.00 15 2.51
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1050 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1051 of 1069

Global Energy Partners E-1
An EnerNOC Company
APPENDIX E
REFERENCES
American Home Appliance Manufacturers, “Today’s Energy Standards for Refrigerators Reflect
Consensus by Advocates, Industry to Increase Appliance Efficiency,” September 27, 2010 press
release, http://www.aham.org/ht/a/GetDocumentAction/i/50432.
Appliance Standards Awareness Project; http://www.standardsasap.org.
Avista Corporation, 2009 Electric Integrated Resource Plan, August 31, 2009.
Avista Corporation, System Load Research Project report, March 2010, prepared by KEMA.
California Public Utilities Commission, Database for Energy Efficient Resources (DEER), 2009,
http://www.deeresources.com.
Dun and Bradstreet Data, ZapData, http://www.dnb.com and http://www.zapdata.com.
California Energy Commission, Residential Appliance Saturation Survey (RASS), 2010,
http://www.energy.ca.gov/appliances/rass/.
California Energy Commission, Commercial End-Use Survey (CEUS), 2006,
http://www.energy.ca.gov/ceus/.
Electric Power Research Institute, Assessment of Achievable Potential from Energy Efficiency and
Demand Response Programs in the U.S. EPRI National Potential Study, 2009.
ELEEK Lamping Guide; http://www.eleekinc.com.
Energy Information Administration, Annual Energy Outlook 2011-ER, December 2010,
http://www.eia.doe.gov/forecasts/aeo/early_introduction.cfm#key.
Energy Information Administration, EIA Technology Forecast Updates – Residential and
Commercial Building Technologies – Reference Case, Second Edition (Revised), Navigant
Consulting, September 2007.
Energy Information Administration, EIA Technology Forecast Updates – Residential and
Commercial Building Technologies – Reference Case, Navigant Consulting, September 2008.
Energy Information Administration, Annual Electric Power Industry Report, EIA Form 861.
Energy Independence and Security Act of 2007. Pub. L. 110-140. 19 December 2007. Stat.
121.1492.
Environmental Protection Agency and U.S. Department of Energy, ENERGY STAR Program,
http://www.energystar.gov.
Federal Energy Regulatory Commission, A National Assessment of Demand Response Potential,
June 2009, http://www.ferc.gov/industries/electric/indus-act/demand-response/dr-potential.asp.
Forsyth, G., et al., Assessing Heating Assistance Programs in Spokane County, January 2010.
Forsyth, G., Estimation and Analysis of At-risk Households (presentation), Eastern Washington
University, undated.
Global Energy Partners, Building Energy Simulation Tool (BEST).
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1052 of 1069
References

E-2 www.gepllc.com

Global Energy Partners, Energy Market Profiles Database.
Global Energy Partners, Database of Energy Efficiency Measures (DEEM).
Global Energy Partners, EnergyShapeTM Database.
Grainger Catalog Volume 398, 2007–2008.
Inland Power & Light Customer Energy Efficiency Study Executive Summary Report, Robinson
Research, January 2009.
Mills, E., Building Commissioning, A Golden Opportunity for Reducing Energy Costs and
Greenhouse Gas Emissions, Lawrence Berkeley National Laboratory, July 21, 2009,
http://cx.lbl.gov/documents/2009-assessment/LBNL-Cx-Cost-Benefit.pdf.
National Action Plan for Energy Efficiency, National Action Plan for Energy Efficiency Vision for
2025: Developing a Framework for Change, 2007, www.epa.gov/eeactionplan.
Northwest Energy Efficiency Alliance, 2009 Northwest Commercial Building Stock
Assessment (10-211), http://neea.org/research/reportdetail.aspx?ID=546.
Northwest Energy Efficiency Alliance, Single-Family Residential Existing Construction Stock
Assessment, Market Research Report, E07-179 (10/2007),
http://neea.org/research/reportdetail.aspx?ID=194.
Northwest Power and Conservation Council, Sixth Power Plan Conservation Supply Curve
Workbooks, 2010, http://www.nwcouncil.org/energy/powerplan/6/supplycurves/default.htm.
Robinson Research, Inland Power & Light Customer Energy Efficiency Study Executive Summary
Report, January 2009.
RS Means, Building Construction Cost Data, 2011.
RS Means, Facilities Maintenance and Repair Cost Data, 2011.
RS Means, Green Buildings Project Planning & Cost Estimating Third Edition, 2011.
RS Means, Mechanical Construction Costs, 2011.
Spokane County, https://edis.commerce.state.nc.us/docs/countyProfile/WA/53063.pdf

U. S. Census Bureau, American Community Survey, http://www.census.gov/acs/www/.
U. S. Census Bureau, 2007 Economic Census, http://www.census.gov/econ/census07/.
U. S. Census Bureau, Population Estimates, http://www.census.gov/popest/cities/SUB-EST2009-
4.htm.
U. S. Census Bureau, Quick Facts, http://quickfacts.census.gov/qfd/download_data.html
U. S. Census Bureau, http://www.census.gov/eos/www/naics/.
U.S. Department of Energy’s Appliances and Commercial Equipment Standards Program:
http://www1.eere.energy.gov/buildings/appliance_standards/index.html.
U.S. Department of Energy Building Technologies Program, Multi Year Program Plan – Building
Regulatory Programs - Energy Efficiency and Renewable Energy, October 2010.
U.S Department of Health and Human Services, LIHEAP Clearinghouse,
http://liheap.ncat.org/profiles/povertytables/FY2010/popstate.htm.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1053 of 1069
References
Global Energy Partners E-3
An EnerNOC Company
U.S. Green Building Council, LEED New Construction & Major Renovation, 2008.
Washington Office of Financial Management, Long-term Forecast of Washington Personal
Income, http://www.ofm.wa.gov/economy/longterm/2009/lt09ch4.pdf and
http://www.ofm.wa.gov/economy/hhinc/.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1054 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1055 of 1069

Global Energy Partners E-1
An EnerNOC Company

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1056 of 1069
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1057 of 1069

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1058 of 1069

Global Energy Partners
An EnerNOC Company 500 Ygnacio Valley Road, Suite 450
Walnut Creek, CA 94596
P: 925.482.2000
F: 925.284.3147 E: [e-mail]
ABOUT GLOBAL
Global Energy Partners is a premier provider of energy and environmental engineering and technical services to utilities, energy companies, research organizations,
government/regulatory agencies and private industry.
Global’s offerings range from strategic planning to turn-key program design and implementation and technology applications.
Global is a wholly-owned subsidiary of EnerNOC, Inc committed to helping its clients achieve strategic business objectives with a staff of world-class experts, state of the art tools, and proven methodologies.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1059 of 1069

2011 Electric Integrated
Resource Plan

Appendix E – North Idaho
Transmission Study

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1060 of 1069
500 MW of New Generation in the Rathdrum Area Page 1

Interoffice Memorandum
System Planning
MEMO: SP-2011-08 Rev A
DATE: August 11, 2011
TO: James Gall, IRP Group
FROM: Reuben Arts
SUBJECT: 500 MW of New Generation in the Rathdrum Area

Introduction
Based on initial 2011 IRP analysis 200 MW of new capacity is required in 2019-2020 and an additional
300 MW of capacity in the 2022-2024 time period. North Idaho is one of several potential locations this
capacity could be added, but requires further detail to understand its potential.
Problem Statement
The IRP group is specifically interested in the cost for both the point of integration (POI) station and
associated system upgrades, to integrate the new generation with the following options:
1. Cabinet-Rathdrum 230 kV transmission line (assume 5 miles from Rathdrum)
2. Rathdrum-Boulder 230 kV transmission line (assume Lancaster looped in, and assume the
generation is half way between Lancaster and Rathdrum)
3. Rathdrum-Beacon 230 kV transmission line (assume 1-2 miles from Rathdrum)
4. Double Tap, Rathdrum-Boulder and Rathdrum-Beacon 230 kV transmission lines (again assume
Lancaster is looped in and that the new generation will tap between Lancaster and Rathdrum)
5. Mixed location. 300 MW at the least cost option (between 1 and 4) and an additional 200 MW on
the Cabinet-Rathdrum 230 kV transmission line.
6. Other Transmission Alternatives

Power Flow Analysis
The case that was used to highlight the impacts of an additional 500 MW in the Rathdrum area was the
WECC approved and Avista modified light summer high flow case (AVA-11ls1ae-12BA1251-WOH4277).
The West of Hatwai path typically experiences high flows during light Avista load hours. High West of
Hatwai flows tend to coincide with high Western Montana Hydro generation, high Boundary generation,
high flows on Montana to Northwest, and light loads in Eastern Washington, North Idaho, and Montana.
Existing Clark Fork RAS is in place, and assumed armed, since the Western Montana Hydro (WMH)
complex is greater than 1450 MW. Since the New Project would require significant Avista system
transmission changes, and RAS changes, the results are listed as though RAS were not armed. This does
affect the results of some contingencies, but ultimately does not change the conclusions of this memo.

Option 1
Perhaps one of the worst performing arrangements is option 1.This option immediately requires another
line, or a line reconductor, from the 500 MW project back to Rathdrum. In order to stay within N-0 thermal
limits the project can only be 175 MW without any system upgrades. In a high flow, N-0 scenario, the line
segment from the project back to Rathdrum loads to around 163%, which is roughly 272 MW overloaded.
There are a handful of N-1 and N-2 contingencies that cause significant thermal violations, the worst N-1
being the loss of the 230 kV transmission line from the new project to Rathdrum. See Figure 1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1061 of 1069
500 MW of New Generation in the Rathdrum Area Page 2

Figure 1 – N-1 Contingency

In addition to this worst case outage there are two N-2 scenarios that cause fairly significant problems as
well. The Beacon-Rathdrum and Boulder-Lancaster-Rathdrum 230 kV transmission lines share a common
structure for the majority of the line lengths. Losing both lines to the west of Lancaster causes the Bell S3-
Lancaster 230 kV transmission line to overload. Losing both lines to the east of Lancaster, causes nearly
the same scenario as shown in Figure 1.
To alleviate these overloads three new 230 kV transmission lines, would need to be built. First the
Rathdrum-New Project 230 kV transmission line must be reconductored at a cost of roughly $2.25M.
Second, A 230 kV transmission line, with new right-of-way, must be built from the New Project to
Lancaster. The estimated distance for this line is roughly 5 miles. The estimated loaded cost for this line,
including a new line position at Lancaster and at the New Project, is roughly $9M. Finally, another 230 kV
transmission line, again with new right-of-way, is required from Lancaster to Boulder. This line length is
estimate at roughly 15 miles. The estimated loaded cost of the new line, including new line positions, is
roughly $17M. New right-of-way in this area will be difficult to obtain, which would have the potential of
more than doubling costs.
RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our
transmission system, RAS does not provide operational flexibility and in some cases can compound the
impacts of future generation needs. However, it does represent the cheapest solution and is therefore
listed as solution 1.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1062 of 1069
500 MW of New Generation in the Rathdrum Area Page 3

Option 1 N-0 Max.
Output
Facility Requirement1 Total2
($000)
Solution 1 500 MW Reconductor 230 kV transmission line from new station to
Rathdrum, New 230 kV DB-DB Station and RAS3 13,250
Solution 2 500 MW Reconductor from Rathdrum-New Project. New line from
Lancaster to New Project. New line from Lancaster to
Boulder, New 230 kV DB-DB Station
36,250

Option 2
This option would tap the Rathdrum-Boulder, or what soon will be the Rathdrum-Lancaster-Boulder, 230
kV transmission line. This options has no N-0 issues at the full requested 500 MW. There are a handful of
N-1 and N-2 contingencies that cause significant thermal violations, the worst being the loss of the
Lancaster-Boulder & Rathdrum-Beacon 230 kV transmission lines. These lines share a common structure
and therefore represent a credible N-2 scenario. This outage causes the Lancaster-Bell S3 230 kV
transmission line to load to 189%, or roughly 450 MW above its thermal limit. See Figure 2.

Figure 2 - N-2 Contingency

To alleviate these overloads two new 230 kV transmission lines, would need to be built. A 230 kV
transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated
distance for this line is roughly 3 miles. The estimated loaded cost for this line, including a new line
position at Lancaster and at the New Project, is roughly $8M. Another 230 kV transmission line, again with
new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles.
The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way
in this area will be difficult to obtain, which would have the potential of more than doubling costs.
1 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable.
2 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 3 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1063 of 1069
500 MW of New Generation in the Rathdrum Area Page 4

RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our
transmission system, RAS does not provide operational flexibility and in some cases can compound the
impacts of future generation needs. However, it does represent the cheapest solution and is therefore
listed as solution 1.

Option 2 N-0 Max.
Output
Facility Requirement4 Total5
($000)
Solution 1 500 MW New 230 kV DB-DB Station and RAS6 11,000
Solution 2 500 MW New line from Lancaster to New Project. New line from
Lancaster to Boulder, New 230 kV DB-DB Station
33,000

Option 3
This option taps the Rathdrum-Beacon 230 kV transmission line. Again, this options has no N-0 issues at
the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause significant
thermal violations, the worst being the loss of the Beacon-New Project & Rathdrum-Lancaster 230 kV
transmission lines. These lines share a common structure and therefore represent a credible N-2
scenario. This outage forces the entire proposed 500 MW toward Cabinet and Noxon. This causes
overloads on the Cabinet-Noxon and Pine Creek-Benewah 230 kV transmission lines. See Figure 3.

Figure 3 - N-2 Contingency

4 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable.
5 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 6 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1064 of 1069
500 MW of New Generation in the Rathdrum Area Page 5

To alleviate these overloads two new 230 kV transmission lines, would need to be built. A 230 kV
transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated
distance for this line is roughly 3 miles. The estimated loaded cost for this line, including a new line
position at Lancaster and at the New Project, is roughly $8M. Another 230 kV transmission line, again with
new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles.
The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way
in this area will be difficult to obtain, which would have the potential of more than doubling costs.

RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our
transmission system, RAS does not provide operational flexibility and in some cases can compound the
impacts of future generation needs. However, it does represent the cheapest solution and is therefore
listed as solution 1.

Option 3 N-0 Max.
Output
Facility Requirement7 Total8
($000)
Solution 1 500 MW New 230 kV DB-DB Station and RAS9 11,000
Solution 2 500 MW New line from Lancaster to New Project. New line from
Lancaster to Boulder, New 230 kV DB-DB Station
33,000

Option 4
This option taps the Rathdrum-Beacon & Rathdrum-Lancaster 230 kV transmission lines. This options has
no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that cause
significant thermal violations, the worst being the loss of the Beacon-New Project & Lancaster-New
Project 230 kV transmission lines. These lines share a common structure and therefore represent a
credible N-2 scenario. This outage forces the entire proposed 500 MW toward Cabinet and Noxon. This
causes overloads on the Cabinet-Noxon and Pine Creek-Benewah 230 kV transmission lines. (Very
similar to Figure 3 on the previous page).

To alleviate these overloads two new 230 kV transmission lines, would need to be built. A 230 kV
transmission line, with new right-of-way, must be built from the New Project to Lancaster. The estimated
distance for this line is roughly 3 miles. The estimated loaded cost for this line, including a new line
position at Lancaster and at the New Project, is roughly $8M. Another 230 kV transmission line, again with
new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly 15 miles.
The estimated loaded cost of the new line, including new line positions, is roughly $17M. New right-of-way
in this area will be difficult to obtain, which would have the potential of more than doubling costs.

RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our
transmission system, RAS does not provide operational flexibility and in some cases can compound the
impacts of future generation needs. However, it does represent the cheapest solution and is therefore
listed as solution 1.

Option 4 N-0 Max.
Output
Facility Requirement Total
($000)
Solution 1 500 MW New 230 kV DB-DB Station and RAS 15,000
Solution 2 500 MW New line from Lancaster to New Project. New line from
Lancaster to Boulder, New 230 kV DB-DB Station
37,000
7 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable.
8 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 9 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1065 of 1069
500 MW of New Generation in the Rathdrum Area Page 6

Option 5
This option taps the Rathdrum-Beacon & Rathdrum-Cabinet 230 kV transmission lines. A new switching
station is required for each tap. A 300 MW generating station would be on the Beacon-Rathdrum 230 kV
transmission line and 200 MW would be on the Rathdrum-Cabinet 230 kV transmission line. This option
has no N-0 issues at the full requested 500 MW. There are a handful of N-1 and N-2 contingencies that
cause significant thermal violations, the worst being the loss of the Beacon-New Project & Lancaster-
Rathdrum 230 kV transmission lines. These lines share a common structure and therefore represent a
credible N-2 scenario. This outage forces the entire proposed 500 MW toward Cabinet and Noxon. This
causes overloads on the Cabinet-Noxon and Pine Creek-Benewah 230 kV transmission lines. (Very
similar to what was shown in Figure 3).

To alleviate these overloads three new 230 kV transmission lines, would need to be built. A 230 kV
transmission line, with new right-of-way, must be built from the New Project (300MW piece) to Lancaster.
The estimated distance for this line is roughly 5 miles. The estimated loaded cost for this line, including a
new line position at Lancaster and at the New Project, is roughly $9M. Another 230 kV transmission line,
again with new right-of-way, is required from Lancaster to Boulder. This line length is estimate at roughly
15 miles. The estimated loaded cost of the new line, including new line positions, is roughly $17M. Finally,
for the loss of the Rathdrum-New Project (200MW piece) 230 kV transmission line, causes the Cabinet-
Noxon 230 kV transmission line to load to 117%. To alleviate this overload a new line, with new right-of-
way must be built back to Rathdrum. The estimated loaded cost of this 5 mile line, along with associated
line positions, is $9M. New right-of-way in this area will be difficult to obtain, which would have the
potential of more than doubling costs.

RAS may be a viable solution. If at all possible RAS should be a last resort. Unlike improving our
transmission system, RAS does not provide operational flexibility and in some cases can compound the
impacts of future generation needs. However, it does represent the cheapest solution and is therefore
listed as solution 1.
Option 5 N-0 Max.
Output
Facility Requirement10 Total11
($000)
Solution 1 500 MW Two New 230 kV DB-DB Stations and RAS12 22,000
Solution 2 500 MW Two New 230 kV DB-DB Stations, New line from Lancaster
to New Project (300MW). New line from Lancaster to
Boulder, New line from New Project (200MW) to Rathdrum
51,000

Option 6 – Other Transmission Alternatives
In addition to the five options listed, there are a few more options that may seem to be intuitive
interconnection points. These integration options are:
a. Lancaster 230 kV (BPA) switching station
b. Rathdrum 230/115/13.2 kV substation
c. Cabinet-Rathdrum & Noxon-Lancaster 230 kV transmission lines
d. Bell-Taft 500 kV transmission line

Option 6a - Connecting to the Lancaster 230 kV switching station would save Avista the cost of a new
switching station. It would also negate the need for a new transmission line, with associated right-of-way,
from the new project to Lancaster. The estimated savings, adding the previously quoted loaded costs, less
10 Cost estimates do not include costs of the radial line to the POI, the generator or generator station if applicable.
11 Total is for network and direct assigned costs, are in 2011 dollars, and is +/- 50%. 12 The RAS portion is a worst case scenario where another fiber loop is required. $3M allocated for RAS.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1066 of 1069
500 MW of New Generation in the Rathdrum Area Page 7

the added cost of connecting to Lancaster, is $13M13. This does not take into account any fees associated
with connecting to BPA. This option assumes there is room in the Lancaster substation to accept the new
line position. If Lancaster substation cannot accommodate the new line position, the cost savings to
interconnect at Lancaster may be negligible or non-existent.
This option would still have all the contingency issues and associated upgrades similar to Option 2.

Option 6b - Connecting to the Rathdrum substation saves the cost of building another switching station. All
contingency results are nearly identical to connecting the project to option 2 or option 3. The estimated
savings of this option is $4M14. This option assumes there is room in the Rathdrum substation to accept
the new line position. If Rathdrum substation cannot accommodate the new line position, the cost savings
to interconnect at Rathdrum may be negligible or non-existent.

Option 6c – Tapping the Cabinet-Rathdrum & Noxon-Lancaster 230 kV transmission lines does improve
the network performance, in comparison to tapping only the Cabinet-Rathdrum 230 kV transmission line.
However, this option still requires all the same network upgrades that option 1 requires since it is still
possible to have an N-2 situation where the generation of the New Project, Noxon and Cabinet is
separated from the Coeur d’Alene/Spokane load. (See Figure 1). This option is listed for completeness.

Option 6d - Connecting solely to the Bell-Taft 500 kV transmission line cannot be done without RAS and
possibly some network upgrades on BPA’s system. In addition to the network upgrades that would likely
be required on BPA’s system, Avista would also be financially liable to pay wheeling fees from the new
project across BPA’s lines to Avista’s load. If the project is connected to both BPA’s Bell-Taft 500 kV
transmission line and Avista’s Rathdrum area 230 kV system, effectively avoiding wheeling charges, both
RAS and significant network upgrades will be required. Due to the cost of a new 500 kV substation,
associated RAS and the potentially large cost of network upgrades on BPA’s 500 kV system, this option is
not recommended.

Conclusion
Of the formally identified options, options 2 and 3 represent the least cost and best performing options. Of
the other transmission alternatives, the Lancaster switching station, followed by the Rathdrum substation,
interconnection options represent the least cost and best performing alternative options. The following
favorable options are:
Option 2: $11-33M (RAS only vs System Upgrades)15
Option 3: $11-33M (RAS only vs System Upgrades)15
Lancaster Alternative Option: $7-20M (RAS only vs System Upgrades)
Rathdrum Alternative Option: $7-33M (RAS only vs System Upgrades)
13 Assumes a network upgrade solution would be pursued, instead of a RAS only solution. 14 This $4M savings would be for either a RAS only or a network upgrade solution.
15 If the new project is interconnected to the west of Lancaster, the Lancaster-New Project 230 kV transmission line
is not needed. Hence the network upgrade cost would be reduced by $8M.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1067 of 1069

2011 Electric Integrated
Resource Plan

Appendix F – 2011 Electric IRP
New Resource Table for
Transmission

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1068 of 1069
Resource POR Capacity Year
Resource Location or Local Area POD Start Stop MW Total
Noxon 4 (incremental)Noxon, MT Noxon, MT AVA System 4/1/2012 Indefinite 14.0
Wind Oaksdale, WA Thorton AVA System 8/1/2012 Indefinite 102.0 116.0
Lancaster CCCT Rathdrum, ID Bell/Westside AVA System 1/1/2013 10/31/2026 125.0
Lancaster CCCT Rathdrum, ID Mid-C AVA System 1/1/2013 10/31/2026 150.0 275.0
Coyote Springs 2 Boardman, OR Coyote Springs 2 AVA System 5/1/2018 Indefinite 16.0 16.0
SCCT TBD TBD AVA System 1/1/2019 Indefinite 86.3 86.3
Wind Reardan, WA Reardan AVA System 1/1/2020 Indefinite 60.0 60.0
Wind Reardan, WA Reardan AVA System 1/1/2021 Indefinite 60.0
SCCT TBD TBD AVA System 1/1/2021 Indefinite 86.3 146.3
CCCT TBD TBD AVA System 1/1/2024 Indefinite 280.8 280.8
CCCT TBD TBD AVA System 11/1/2026 Indefinite 280.8 280.8
SCCT TBD TBD AVA System 1/1/2030 Indefinite 47.8 47.8
Total 1309 1309
August 18, 2011
2011 Avista IRP
New Resource Table For Transmission
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 1, Page 1069 of 1069
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 2, Page 1 of 3
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 2, Page 2 of 3
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 2, Page 3 of 3

CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality

Avista Utilities Energy Resources Risk Policy
Pages 1 through 28
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 3, Page 1 of 28
Map of the Palouse Wind Project

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 4, Page 1 of 1
2009 Electric Integrated Resource Plan
August 31, 2009
AC-0910 IRP Cover.indd 1 8/5/09 5:03:12 PM
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 1 of 729
Special thankS to our talented vendorS from
the Spokane area who produced thiS irp:
Ross Printing Company
Thinking Cap Design
Printed on recycled paper.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 2 of 729
Table of ConTenTs
Executive Summary i
Introduction and Stakeholder Involvement 1-1
Loads and Resources 2-1
Energy Efficiency 3-1
Environmental Policy 4-1
Transmission and Distribution 5-1
Generation Resource Options 6-1
Market Analysis 7-1
Preferred Resource Strategy 8-1
Action Items 9-1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 3 of 729
This document contains forward-looking statements. Such
statements are subject to a variety of risks, uncertainties
and other factors, most of which are beyond the company’s
control, and many of which could have a significant impact on
the company’s operations, results of operations and financial
condition, and could cause actual results to differ materially
from those anticipated.
For a further discussion of these factors and other important
factors, please refer to our reports filed with the Securities and
Exchange Commission which are available on our website at
www.avistacorp.com. The company undertakes no obligation
to update any forward-looking statement or statements to
reflect events or circumstances that occur after the date on
which such statement is made or to reflect the occurrence of
unanticipated events.
Safe Harbor Statement
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 4 of 729
Table 1: Net Position Forecast ______________________________________________________ i
Table 2: 2009 Preferred Resource Strategy __________________________________________ viii
Table 3: 2007 Preferred Resource Strategy ___________________________________________ ix
Table 1.1: TAC Participants ________________________________________________________1-2
Table 1.2: TAC Meeting Dates and Agenda Items _______________________________________1-3
Table 1.3: Washington IRP Rules and Requirements ____________________________________1-6
Table 2.1: Global Insight National Long Range Forecast Assumptions _______________________2-4
Table 2.2: Company-Owned Hydro Resources ________________________________________2-17
Table 2.3: Company-Owned Thermal Resources ______________________________________2-19
Table 2.4: Large Congtractual Rights and Obligations __________________________________2-21
Table 2.5: Washington State RPS Detail (aMW) _______________________________________2-26
Table 2.6: Winter Capacity Position (MW) - Plan for Position Excluding Maintenance __________2-27
Table 2.7: Summer Capacity Position (MW) - Plan for Position Excluding Maintenance ________2-28
Table 3.1: Current Avista Energy Efficiency Programs __________________________________3-10
Table 6.1: CCCT (Water Cooled) Levelized Costs per MWh _______________________________6-4
Table 6.2: CCCT with Carbon Sequestration Levelized Costs per MWh ______________________6-5
Table 6.3: Frame SCCT Levelized Costs per MWh ______________________________________6-6
Table 6.4: LMS 100 Levelized Costs per MWh _________________________________________6-6
Table 6.5: Wind Capital and Fixed O&M Costs _________________________________________6-7
Table 6.6: Columbia Basin Wind Project Levelized Costs per MWh _________________________6-8
Table 6.7: Small Scale Project Levelized Costs per MWh _________________________________6-8
Table 6.8: Offshore Wind Project Levelized Costs per MWh _______________________________6-8
Table 6.9: Coal Capital Costs (2009$) _______________________________________________6-9
Table 6.10: Ultra Critical Pulverized Coal Project Levelized Cost per MWh ___________________6-10
Table 6.11: IGCC Coal Project Levelized Cost per MWh _________________________________6-10
Table 6.12: IGCC with Carbon Sequestration Coal Project Levelized Cost ($/MWh) ____________6-10
Table 6.13: Hydro Upgrade Project Characteristics______________________________________ 6-11
Table 6.14: Hydro Upgrade Nominal Levelized Costs per MWh ____________________________6-12
Table 6.15: Hydro Upgrade 2009$ Levelized Costs per MWh______________________________6-12
Table 6.16: Solar Nominal Levelized Cost ($/MWh) _____________________________________6-13
Table 6.17: Solar 2009$ Levelized Cost ($/MWh) _______________________________________6-14
Table 6.18: Biomass Capital Costs __________________________________________________6-15
Table 6.19: Biomass Nominal Levelized Costs per MWh _________________________________6-15
Table 6.20: Biomass 2009 Dollar Levelized Cost per MWh________________________________6-15
Table 6.21: Geothermal Levelized Costs per MWh ______________________________________6-16
Table 6.22: Tidal/Wave Levelized Costs per MWh ______________________________________6-17
Table 6.23: Small Cogeneration Levelized Costs per MWh _______________________________6-17
Table 6.24: Nuclear Levelized Costs per MWh _________________________________________6-18
Table of T ables
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 5 of 729
Table 6.25: Hydrokinetics Levelized Costs per MWh ____________________________________6-18
Table 6.26: Pumped Storage Levelized Costs per MWh __________________________________6-19
Table 6.27: Large Scale Hydro Levelized costs per MWh _________________________________6-19
Table 6.28: Resource Analysis Summary for Preferred Resources Strategy Analysis ___________6-21
Table 6.29: Resource Analysis Summary for Other Resources Options ______________________6-22
Table 7.1: AURORAXMP Zones ______________________________________________________7-3
Table 7.2: 20-Year Annual Average Peak & Energy Load Growth Rates _____________________7-3
Table 7.3: Western Interconnect Transmission Upgrades Included in Analysis ________________7-4
Table 7.4: New Resources Available to Meet Resource Deficits ____________________________7-7
Table 7.5: Natural Gas Price Basin Differentials from Henry Hub (Nominal Dollars) ____________7-9
Table 7.6: Monthly Price Differentials for Malin _________________________________________7-9
Table 7.7: Western Interconnect Coal Prices (2009$) ___________________________________7-10
Table 7.8: Northwest Hydro Capacity Factors _________________________________________ 7-11
Table 7.9: Western Interconnect Wind Capacity Factors _________________________________ 7-11
Table 7.10: Stochastic Study Correlation Matrix ________________________________________7-14
Table 7.11: EPA Carbon Study (Nominal Price per Short/Ton) _____________________________7-15
Table 7.12: Ten Cost Scenarios Based on Wood Mackenzie and EPA Studies (Nominal Price per Short Ton) ____7-15
Table 7.13: January through June Area Correlations ____________________________________7-20
Table 7.14: July through December Area Correlations ___________________________________7-20
Table 7.15: Area Load Coefficient of Determination (Std Dev/Mean) ________________________7-21
Table 7.16: Area Load Coefficient of Determination (Std Dev/Mean) ________________________7-21
Table 7.17: Annual Mid-Columbia Electric Prices ($/MWh) ________________________________7-28
Table 7.18: Main and Mid-Columbia Forecast Results (Nominal Levelized) ___________________7-43
Table 7.19: Main and Mid-Columbia Forecast Results (2009 Dollars Levelized) _______________7-43
Table 8.1: 2009 Preferred Resource Strategy __________________________________________8-8
Table 8.2: 2007 Preferred Resource Strategy __________________________________________8-9
Table 8.3: Levelized Avoided Costs ($/MWh) _________________________________________8-16
Table 8.4: PRS Rate Base Additions for Capital Expenditures ____________________________8-18
Table 8.5: Unconstrained Carbon Scenario - Least Cost Portfolio _________________________8-23
Table 8.6: Portfolio Cost and Risk Comparison ________________________________________8-23
Table 8.7: Low Load Growth Resource Strategy Changes to PRS _________________________8-25
Table 8.8: High Load Growth Resource Strategy Changes to PRS ________________________8-25
Table 8.9: Large Hydro Upgrade Resource Strategy Modifications_________________________8-27
Table 8.10: Portfolio Cost and Risk Comparison ________________________________________8-29
Table 8.11: Other Renewables Available - Changes to PRS _______________________________8-29
Table 8.12: Annual Load & Resources (aMW) _________________________________________8-31
Table 8.13: Loads & Resources at Winter Peak (MW) ___________________________________8-32
Table 8.14: Loads & Resources at Summer Peak (MW) __________________________________8-33
Table of T ables (continued)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 6 of 729
Figure 1: Load Resource Balance— Winter Capacity ____________________________________ ii
Figure 2: Load Resource Balance—Energy____________________________________________ ii
Figure 3: Efficient Frontier _________________________________________________________ iv
Figure 4: Annual Flat Mid-Columbia Prices ____________________________________________ v
Figure 5: Annual Average Henry Hub Natural Gas Price __________________________________ vi
Figure 6: Cumulative Conservation Acquisitions ________________________________________vii
Figure 7: Forecast of Conservation Acquisition _________________________________________vii
Figure 8: Preferred Resource Strategy______________________________________________ viii
Figure 9: Estimated Price of CO2 Credits for 2009 IRP ___________________________________ x
Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions _______________ x
Figure 2.1: Avista’s Service Territory __________________________________________________2-2
Figure 2.2: Population Change for Spokane, Kootenai and Bonner Counties __________________2-3
Figure 2.3: Total Population for Spokane, Kootenai and Bonner Counties _____________________2-3
Figure 2.4: Three-County Population Age 65 and Over ___________________________________2-5
Figure 2.5: Three-County Job Change ________________________________________________2-5
Figure 2.6: Three-County Non-Farm Jobs _____________________________________________2-6
Figure 2.7: Avista Annual Average Customer Forecast ___________________________________2-7
Figure 2.8: Household Size Index ___________________________________________________2-10
Figure 2.9: Annual Use per Customer________________________________________________ 2-11
Figure 2.10: Avista’s Retail Sales Forecast ____________________________________________2-12
Figure 2.11: Annual Net Native Load _________________________________________________2-13
Figure 2.12: Calendar Year Peak Demand _____________________________________________2-14
Figure 2.13: Electric Load Forecast Scenarios __________________________________________2-15
Figure 2.15: Winter Capacity Position _________________________________________________2-24
Figure 2.16: Summer Capacity Position _______________________________________________2-25
Figure 2.17: Annual Average Position _________________________________________________2-25
Figure 3.1: Historical Conservation Acquisition __________________________________________3-2
Figure 3.2: Forecast of Conservation Acquisition _______________________________________3-11
Figure 3.3: Supply of Evaluated Conservation Measures (Levelized TRC Cost) _______________3-12
Figure 4.1: Price of Carbon Dioxide Credits ___________________________________________ 4-11
Figure 5.1: Avista Transmission System _______________________________________________5-2
Figure 5.2: Levelized Cost of Feeder Upgrades ________________________________________5-12
Figure 5.3: Estimated Feeder Supply Curve ___________________________________________5-12
Figure 6.1: CCCT Output Per 100 MW of Nameplate Capacity _____________________________6-4
Figure 7.1: NERC Interconnection Map _______________________________________________7-2
Figure 7.2: Renewable Resource Additions to Meet RPS__________________________________7-5
Figure 7.3: Northwest Peak Load/Resource Balance _____________________________________7-6
Figure 7.4: Total Western Interconnect Capacity Deficits __________________________________7-7
Table of figures
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 7 of 729
Table of figures (continued)
Figure 7.5: Henry Hub Natural Gas Price Forecast ______________________________________7-8
Figure 7.6: Price of Carbon Credits__________________________________________________7-13
Figure 7.7: Cost of Carbon Credits __________________________________________________7-13
Figure 7.8: Distribution of Annual Average Carbon Prices for 2012 _________________________7-16
Figure 7.9: Distribution of Annual Natural Gas Prices for 2012_____________________________7-17
Figure 7.10: Henry Hub Natural Gas Distributions _______________________________________7-17
Figure 7.11: Random Draws from the Henry Hub Price Distribution __________________________7-18
Figure 7.12: Random Draws Load Forecast with Year 2009 at 100 __________________________7-19
Figure 7.13: Distribution of Avista’s Hydro Generation ____________________________________7-23
Figure 7.14: Wind Ouput Distribution _________________________________________________7-24
Figure 7.15: Base Case New Resource Selection _______________________________________7-26
Figure 7.16: Annual Flat Mid-Columbia Electric Prices ____________________________________7-27
Figure 7.17: Selected Mid-Columbia Annual Flat Price Duration Curves ______________________7-27
Figure 7.18: Western States Greenhouse Gas Emissions _________________________________7-29
Figure 7.19: Base Case Wetern Interconnect Resource Energy ____________________________7-30
Figure 7.20: Unconstrained Carbon Emissions Resource Selection _________________________7-31
Figure 7.21: Mid-Columbia Prices Comparison with and without Carbon Legislation _____________7-32
Figure 7.22: Western U.S. Carbon Emissions Comparison ________________________________7-33
Figure 7.23: Unconstrained Carbon Scenario Resource Dispatch ___________________________7-33
Figure 7.24: Western Interconnect Fuel Cost Comparison _________________________________7-34
Figure 7.25: Henry Hub Prices for High and Low Natural Gas Price Scenarios _________________7-35
Figure 7.26: Greenhouse Gas Prices for High and Low Natural Gas Price Scenarios ____________7-36
Figure 7.27: High Natural Gas Prices Scenario Resource Selection _________________________7-36
Figure 7.28: Low Natural Gas Prices Scenario Resource Selection __________________________7-37
Figure 7.29: Mid-Columbia Electric Price Forecast _______________________________________7-38
Figure 7.30: Resource Dispatch - High Gas Price Scenario ________________________________7-38
Figure 7.31: Resource Dispatch - Low Gas Price Scenario ________________________________7-39
Figure 7.32: Solar Saturation Scenario Resource Selection ________________________________7-40
Figure 7.33: Western Interconnect Carbon Emissions Comparison __________________________7-41
Figure 7.34: Resource Dispatch - Solar Saturation Scenario _______________________________7-41
Figure 8.1: Resource Acquisition History ______________________________________________8-2
Figure 8.2: Efficient Frontier Curve ___________________________________________________8-4
Figure 8.3: Efficient Frontier in a Constrained Environment ________________________________8-5
Figure 8.4: Physical Resource Positions_______________________________________________8-6
Figure 8.5: REC Requirement vs. Qualifying RECs for Washington State RPS _________________8-7
Figure 8.6: Energy Efficiency Annual Expected Acquisition _______________________________8-10
Figure 8.7: Annual Average Load and Resource Balance ________________________________ 8-11
Figure 8.8: Winter Peak Load and Resource Balance ___________________________________8-12
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 8 of 729
Figure 8.9: Summer Peak Load and Resource Balance __________________________________8-13
Figure 8.10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions _____________8-14
Figure 8.11: Base Case Efficient Frontier ______________________________________________8-15
Figure 8.12: Avoided Costs for Conservation ___________________________________________8-16
Figure 8.13: Efficient Frontier Portfolios 2029 New Resources _____________________________8-17
Figure 8.14: Power Supply Expense __________________________________________________8-19
Figure 8.15: Power Supply Cost Sensitivities ___________________________________________8-20
Figure 8.16: Carbon Related Power Supply Expense_____________________________________8-21
Figure 8.17: Efficient Frontier Comparison _____________________________________________8-22
Figure 8.18: High & Low Load Growth Cost Comparison __________________________________8-26
Figure 8.19: Efficient Frontier Base Case vs. Other Renewables Available ____________________8-28
Figure 8.20: Real Power Supply Expected Cost Growth Index (2010 = 100) ___________________8-30
Table of figures (continued)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 9 of 729
AARG Annual Average Rate of Growth
AVA Avista
aMW Average Megawatts
BPA Bonneville Power Administration
CCCT Combined-Cycle Combustion
Turbine
CFL Compact Fluorescent Lamp
CO2 Carbon Dioxide
CSA Climate Stewardship Act (also
known as
the McCain-Lieberman Bill)
CVR Controlled Voltage Reduction
Dth decatherm
EF Efficiency
EIA Energy Information Administration
FERC Federal Energy Regulatory
Commission
GE The General Electric Company
GHG Greenhouse Gas
GWh Gigawatt-hour
HRSG Heat Recovery Steam Generator
HVAC Heating, Ventilation and Air
Conditioning (HVAC)
IDP Idaho Power Company
IGCC Integrated Gasification Combined
Cycle
IRP Integrated Resource Plan
IS Information Systems
kV kilo-volt
kW kilowatt
kWh kilowatt-hour
LIRAP Low Income Rate Assistance
Program
LP Linear Programming
Mmbtu Million British Thermal Units,
1 mmbtu = 1 dth of Natural Gas
MW megawatt
MWh megawatt-hour
NCEP National Commission for
Energy Policy
NEB Non-Energy Benefits
Nominal Discounting Method that Includes
Inflation
NPCC Northwest Power and Conservation
Council (formerly Northwest Power
Planning Council)
NPV Net Present Value
NWPP Northwest Power Pool
O&M Operations and Maintenance
OASIS Open Access Same-Time
Information
System
OSU Oregon State University
PC Personal Computer
PGE Portland General Electric
PRS Preferred Resource Strategy
PRiSM Preferred Resource Strategy Line
Programming Model
psig Pounds Per Square Inch Gauge
PTC Production Tax Credit
PUD Public Utility District
PURPA Public Utility Regulatory Policies
Act of 1978
Real Discounting Method that Excludes
Inflation
RPS Renewable Portfolio Standards
RTO Regional Transmission
Organization
SCCT Simple-Cycle Combustion Turbine
TAC Technical Advisory Committee
TIG Transmission Improvements Group
TRC Total Resource Cost
Triple E External Energy Efficiency Board
VFD Variable Frequency Drive
WECC Western Electricity Coordinating
Council
WNP-3 Washington Public Power Supply
System (WPPSS, now Energy
Northwest) – Washington Nuclear
Plant No. 3
LiSt of acronymS and Key termS
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 10 of 729
Avista has a long tradition of innovation as a provider of clean, renewable energy. The 2009 Integrated Resource
Plan (IRP) continues that tradition as it looks into the future needs of our customers. The IRP analyzes and
outlines a strategy to meet projected demand through energy efficiency and a careful mix of new renewables and
traditional resources.
The plan includes economic growth forecasts for the Avista service territory. Electricity sales growth is expected
to occur at a rate of 1.7 percent over the next two decades. Avista projects that it will have sufficient resources to
meet growth until 2018 when new energy supplies will need to be brought online.
Avista expects to add increasing amounts of new renewables to its generation portfolio in the coming years. This
is partly due to active and pending state and federal regulations. Regardless of legislation, Avista believes that
renewables represent viable energy sources that reduce the need for fossil fuels and diversify our resource mix.
New renewable energy sources like wind and solar power currently are more expensive to build than traditional
energy resources. An added challenge is they are intermittent resources, meaning that the wind doesn’t always
blow and the sun doesn’t always shine. Customers except high reliability so utilities will still need energy resources
like natural gas and hydropower to keep the lights on. This presents a challenge to resource planners who must
consider realiabilty as well as rate and environmental impacts.
The IRP is updated every two years and looks 20 years into the future. This plan is developed by Avista’s professional
energy analysts using sophisticated modeling tools and input from interested community stakeholders.
Each IRP is a thoroughly researched and data driven document to guide responsible resource planning for the
company. The plan’s Preferred Resource Strategy (PRS) section covers our projected resource acquisitions over
the next 20 years.
Some highlights of the PRS include:
• 150 MW of wind power by 2012 to take advantage of renewable energy tax incentives, diversify our fuel
mix, and meet renewable portfolio standards.
• An additional 200 MW of wind power over the IRP timeframe.
• 26 percent of future load growth is met by new conservation.
• Construction of 750 MW of clean-burning natural gas-fired generation facilities.
• Avista does not plan to add any coal-fired generation to its resource mix.
• Aggressive energy efficiency measures are expected to save 226 aMW of cumulative energy over the
next 20 years.
• 5 MW of hydro upgrades are planned for the Little Falls and Upper Falls hydro projects.
• Large hydro upgrades will be studied as alternative new renewable resources for the 2011 IRP.
• Transmission upgrades will be needed to add new generation and Avista will continue to participate in
regional efforts to expand the region’s transmission system.
This document is mostly technical in nature. The IRP has an Executive Summary and chapter highlights at the
beginning of each section to help guide the reader.
Avista expects to begin developing the 2011 IRP in early 2010. Stakeholder involvement is encouraged and
interested parties may contact John Lyons at 509-495-8515 or [e-mail] for more information
on participating in the IRP process.
2009 irP introduction
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 11 of 729
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 12 of 729
Executive Summary
2009 Electric IRPAvista Corp i
Executive Summary
Executive Summary
Avista’s 2009 Integrated Resource Plan (IRP) guides the utility’s resource acquisition strategy over the next two years and the overall direction of resource procurements for the remainder of the 20-year planning horizon. The IRP provides a snapshot of the
Company’s resources and loads, and provides
guidance regarding resource needs and acquisitions. The Preferred Resource Strategy (PRS) is a mix of renewable resources,
conservation, upgrades at existing facilities,
and new gas-fired generation.
The PRS balances low cost, reliable service,
reasonable future rate volatility, and renewable
resource requirements. Avista’s management and stakeholders from the Technical Advisory Committee (TAC) play a key role in guiding the
development of the IRP. TAC members
include customers, commission staff,
consumer advocates, academics, utility peers, government agencies, and other interested parties. The TAC provides significant input on
modeling, resource assumptions, and the
general direction of the planning process.
Resource Needs
Plant upgrades and conservation measures are integral to Avista’s resource strategy, but are ultimately inadequate to meet all future load growth. Annual energy deficits
begin in 2018, with loads plus a planning margin exceeding resource capability by 27
aMW. Energy deficits rise to 126 aMW in 2022 and 527 aMW in 2029. The Company
will be short 45 MW of capacity in 2015. In 2022 and 2029, capacity deficits rise to 139 MW and 667 MW, respectively. Table 1 presents Avista’s net load position for the first 10 years of the study.
Table 1: Net Position Forecast
Net Position 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019Energy (aMW) 309 185 123 110 93 59 38 31 -27 -35
Capacity (MW) 293 124 53 31 0 -45 -74 45 11 -46
Increasing deficits are a result of forecasted 1.7 percent energy and capacity load
growth through 2029. Expirations of long-term contracts also increase deficiencies.
Figures 1 and 2 provide graphical representations of the Company’s load and resource balance. The forecasted load in each year includes the one-in-two peak forecast plus planning and operating reserve obligations. The forecast would be higher without past
conservation acquisitions.
Avista Corp 2009 Electric IRP – Public Draft i
Noxon Rapids Upgrade Crew
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 13 of 729
Executive Summary
2009 Electric IRPii Avista Corp
Executive Summary
Figure 1: Load Resource Balance—Winter Capacity
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Avista Corp 2009 Electric IRP – Public Draft ii
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 14 of 729
Executive Summary
2009 Electric IRPAvista Corp iii
Executive Summary
Modeling and Results
Avista used a multi-step approach to develop its PRS. The process began with the identification and quantification of potential new resources to serve future demand across the West. A Western Interconnect-wide study was performed to understand the
impact of regional markets on the Northwest electricity marketplace. Avista’s existing
resource stack was combined with the present transmission grid to simulate hourly
operations for the Western Interconnect from 2010 to 2029.
Cost-effective new resources and transmission were added as necessary to meet
growing loads. Monte Carlo-style analysis varied hydro, wind, load, forced outages, greenhouse gas emissions, and gas price data over 250 iterations of potential future conditions. The simulation results were used to estimate the Mid-Columbia electric
market, and the iterations collectively formed the Base Case for this IRP.
Estimated market prices were used to analyze potential conservation initiatives and available supply-side resources to meet forecasted resource requirements. Each new
resource option was valued against the Mid-Columbia market to identify the future value
of each asset to the Company, as well as its inherent risk measured in year-to-year power supply cost volatility. Future market values and risk were compared with the capital and fixed operation and maintenance costs that would be incurred. Avista’s
Preferred Resource Strategy Linear Programming Model (PRiSM) assisted in selecting
the PRS for serving future load. The PRS selection was based on forecasted energy
and capacity needs, resource values, state mandated renewable portfolio standards, and limiting power supply expense variability.
Portfolio scenarios were used to identify tipping points that would change the PRS under alternative conditions beyond the Base Case. The scenarios identified changes to underlying assumptions that could alter the PRS, such as changes to load growth,
capital costs, hydro upgrades, the emergence of other small renewable projects and
nuclear revival.
The preferred resource portfolio must address two key challenges that include the
mitigation of future costs and risk given a set of environmental constraints. An efficient
frontier helps determine trade offs between risk and cost. This approach is similar to finding the optimal mix of risk and return when developing a personal investment portfolio. As expected returns increase, so do risks; whereas reducing risk reduces
overall returns. Finding the PRS is similar to the investor’s dilemma, but the trade-off is
future costs against power supply cost variation. Figure 3 presents the change in cost
and risk from the PRS on the Efficient Frontier.
Avista Corp 2009 Electric IRP – Public Draft iii
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 15 of 729
Executive Summary
2009 Electric IRPiv Avista Corp
Executive Summary
Figure 3: Efficient Frontier
$150
$170
$190
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3,300 3,350 3,400 3,450 3,500 3,550
2010-2020 NPV of power supply costs (millions)
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Least Cost w/o
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Least RiskEfficient Frontier
Electricity and Natural Gas Market Price Forecasts
Figure 4 shows the Company’s electricity price forecast developed for the 2009 IRP. The Mid-Columbia market price is expected to average $79.56 per MWh in 2009 dollars over the next 20 years; the average nominal price is $93.74 per MWh. Spreads between
on- and off-peak prices are $14.34 per MWh in 2010 and $32.71 per MWh in 2029.
Stochastic prices are higher than deterministic prices, as the stochastic model accounts
for carbon, hydro, natural gas, forced outage and wind energy risks.
Avista Corp 2009 Electric IRP – Public Draft iv
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 16 of 729
Executive Summary
2009 Electric IRPAvista Corp v
Executive Summary
Figure 4: Annual Flat Mid-Columbia Prices
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Electricity prices are highly correlated with natural gas prices because natural gas-fired
generation is the marginal resource in the Western Interconnect. Base Case natural gas
prices at Henry Hub are shown in Figure 5. The levelized Henry Hub nominal price is expected to be $9.05 per Dth over the next 20 years and the real 2009 dollar levelized cost is $7.67. The natural gas forecast is derived from a combination of sources in the
near term including the New York Mercantile Exchange, the Energy Information
Administration, Wood Mackenzie and other consultants. Longer term prices rely on the forecast from Wood Mackenzie. The forecast includes a price adder of $0.50 per Dth in 2013 and $1.00 per Dth after 2018 (2009 dollars) to account for the increase in
demand of natural gas due to a shift from coal to natural gas-fired generation.
Avista Corp 2009 Electric IRP – Public Draft v
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 17 of 729
Executive Summary
2009 Electric IRPvi Avista Corp
Executive Summary
Figure 5: Annual Average Henry Hub Natural Gas Price
5.0
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Energy Efficiency
Avista’s energy efficiency efforts provide conservation programs and education for
residential, commercial, industrial and low income customers. Programs fall into
prescriptive and site-specific classifications. Prescriptive programs offer cash incentives
for standardized products, such as compact fluorescent light bulbs. These programs are directed towards residential and small commercial customers. Site-specific programs
provide cash incentives for any cost-effective energy savings measure with a payback
greater than one year. Site-specific programs require customized services for
commercial and industrial customers because many applications need to be tailored to each customer’s premises and processes.
Figure 6 shows how conservation has decreased the Company’s energy requirements
by 138.5 aMW since programs began in the late 1970s. 109 aMW of efficiency projects acquired over the past 18 years are still online.
Avista Corp 2009 Electric IRP – Public Draft vi
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 18 of 729
Executive Summary
2009 Electric IRPAvista Corp vii
Executive Summary
Figure 6: Cumulative Conservation Acquisitions
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includes 10.4 aMW (7.5 aMW local and 2.9 aMW regional) of conservation are expected to be obtained in 2010. Figure 7 shows the projected levels of local and regional conservation over the next 20 years.
Figure 7: Forecast of Conservation Acquisition
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Avista Corp 2009 Electric IRP – Public Draft vii
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 19 of 729
Executive Summary
2009 Electric IRPviii Avista Corp
Executive Summary
Preferred Resource Strategy
The PRS is developed after careful consideration of information gathered over the IRP
process. The PRS is reviewed and critiqued by management and the TAC. The 2009
plan relies on a combination of conservation, distribution system upgrades, wind, hydro
upgrades, and gas-fired combined-cycle combustion turbines. It also identifies transmission projects to improve system reliability and to access generation resources necessary to comply with renewable portfolio standards. Figure 8 illustrates the
Company’s PRS.
Figure 8: Preferred Resource Strategy
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Table 2: 2009 Preferred Resource Strategy
Resource
By the End of
Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 150.0 48.0
Distribution Efficiencies 2010-2015 5.0 2.7
Little Falls Unit Upgrades 2013-2016 3.0 0.9
NW Wind 2019 150.0 50.0
CCCT 2019 250.0 225.0
Upper Falls 2020 2.0 1.0
NW Wind 2022 50.0 17.0
CCCT 2024 250.0 225.0
CCCT 2027 250.0 225.0
Conservation All Years 339.0 226.0
Total 1,449.0 1,020.6
Avista Corp 2009 Electric IRP – Public Draft viii
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 20 of 729
Executive Summary
2009 Electric IRPAvista Corp ix
Executive Summary
The PRS resources, shown in nameplate capability, are shown in tabular format in
Table 2 for the 2009 PRS and Table 3 for the 2007 PRS.
Table 3: 2007 Preferred Resource Strategy
Resource By the End of Year Nameplate(MW)Energy (aMW)
Non-Wind Renewable 2011 20.0 18.0
Non-Wind Renewable 2012 10.0 9.0
NW Wind 2013 100.0 33.0
Non-Wind Renewable 2013 5.0 4.5
Share of CCCT 2014 75.0 67.5
NW Wind 2015 100.0 33.0
NW Wind 2016 100.0 33.0
Non-Wind Renewable 2019 10.0 9.0
Non-Wind Renewable 2020 10.0 9.0
Non-Wind Renewable 2021 5.0 4.5
Share of CCCT1 2019 297.0 267.3
Share of CCCT 2027 305.0 274.5
Conservation All Years 331.5 221.0
Total 1,368.5 983.3
The 2009 IRP requires just over $1.0 billion in net present value of new capital
investments over the next 20 years.
Carbon Emissions
Carbon emission costs have been included in the Base Case since the 2007 IRP. Carbon, or CO2, cost estimates are from a national market study by Wood Mackenzie.
Figure 8 shows projected CO2 emissions prices. Figure 9 shows the projected carbon
emissions for existing and new generation assets. These estimates do not include emissions from market and contract purchases, and CO2 emissions are not reduced for wholesale sales. The white area of Figure 10 indicates estimated emission levels
without legislative action.
Avista Corp 2009 Electric IRP – Public Draft ix
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 21 of 729
Executive Summary
2009 Electric IRPx Avista Corp
Executive Summary
Figure 9: Estimated Price of CO2 Credits for 2009 IRP
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Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
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Action Items
The Company’s 2009 Action Plan outlines activities and studies to be developed and
presented in the 2011 Integrated Resource Plan. The Action Plan was developed using input from the Company’s management team and the TAC. Action Item categories include resource additions and analysis, demand side management, environmental
policy, modeling and forecasting enhancements, and transmission planning.
Avista Corp 2009 Electric IRP – Public Draft x
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 22 of 729
2009 Electric IRPAvista Corp 1-1
Chapter 1 - Introduction and Stakeholder InvolvementChapter 1- Introduction and Stakeholder Involvement
1. Introduction and Stakeholder Involvement
Avista Utilities submits a biennial Integrated Resource Plan (IRP) to the Idaho and
Washington public utility commissions.1 The 2009 IRP is Avista’s eleventh plan
identifying and describing its Preferred Resource Strategy (PRS) for meeting customer’s
future requirements while balancing cost and risk measures.
The Company is statutorily obligated to provide reliable electric service to customers at
rates, terms, and conditions that are “just, fair, reasonable and sufficient.” We assess resource acquisition strategies and business plans to acquire resources to meet resource adequacy requirements and optimize the value of our current resource
portfolio. Avista uses the IRP as a resource evaluation tool, rather than a plan for
acquiring a particular asset. The 2009 IRP refines our process for the evaluation of
resource decisions, requests for proposals and other acquisition efforts.
IRP Process
Avista actively sought input from a variety of constituents through the Technical
Advisory Committee (TAC). The TAC included Commission Staff, customers,
academics, government agencies, consultants, utilities and other interested parties. The
Company sponsored six TAC meetings for the 2009 IRP. The TAC process began on May 14, 2008 and the final meeting to present the results of the 2009 IRP occurred on June 24, 2009. Over 70 people were invited to each meeting. Each TAC meeting
covered different aspects of the 2009 IRP planning activities and solicited contributions
and assessments regarding modeling assumptions, modeling processes, and results. Agendas and presentations are in Appendix A and on Avista’s web site located at www.avistautilities.com/inside/resources/irp/electric.
Stakeholder Participation
The IRP process provides substantial opportunities for stakeholders to participate in
Avista’s resource planning activities. The Company utilizes three main stakeholder
groups for the public involvement component of the IRP. The main group involves stakeholders with expertise in various aspects of utility planning to provide input
concerning the studies, resource data, modeling efforts and critical review of the
modeling results. This group includes Commission Staff, planners from other utilities,
academics, and consultants. The second group includes parties involved with a specific aspect of the IRP. Examples of this group include environmental groups such as the Northwest Energy Coalition and government agencies. The third area of public
involvement includes delegates from and participation in regional planning efforts, such
as the Northwest Power and Conservation Council and the Western Electricity
Coordinating Council.
1 Washington IRP requirements are contained in WAC 480-100-251 Least Cost Planning. Idaho IRP requirements are outlined in Case No. U-1500-165 Order No. 22299, Case No. GNR-E-93-1, Order No. 24729, and Case No. GNR-E-93-3, Order No. 25260.
Avista Corp 2009 Electric IRP – Public Draft 1-1
Executive Summary
Figure 9: Estimated Price of CO2 Credits for 2009 IRP
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Figure 10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
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Tons per MWh of Load
Action Items
The Company’s 2009 Action Plan outlines activities and studies to be developed and
presented in the 2011 Integrated Resource Plan. The Action Plan was developed using input from the Company’s management team and the TAC. Action Item categories include resource additions and analysis, demand side management, environmental
policy, modeling and forecasting enhancements, and transmission planning.
Avista Corp 2009 Electric IRP – Public Draft x
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 23 of 729
Chapter 1 - Introduction and Stakeholder Involvement
2009 Electric IRP1-2 Avista Corp
Chapter 1- Introduction and Stakeholder Involvement
Public Process
The 2009 IRP is developed and written with the aid of a public process. All of the 2009
TAC presentations are available for review at the Company’s website. The entire 2009 IRP, its appendices, and previous IRPs are available at Avista’s web site.
Technical Advisory Committee
Avista’s IRP is developed with significant amounts of public input and involvement. The
Company had six TAC meetings supplemented with phone and email contact to develop this plan. Some of the topics included in the 2009 TAC series were: resource
options, conservation, modeling, fuel price forecasts, load forecasts, market drivers and
environmental issues.
The TAC mailing list includes over 70 individuals from 46 different organizations. The
Company greatly appreciates all of the time and effort expended by the participants in
the TAC process and looks forward to their continued involvement in the 2011 IRP.
Avista wishes to acknowledge the contributions of the TAC participants in Table 1.1.
Table 1.1: TAC Participants
Participant Organization
Andy Ford Washington State University
Robin Toth Greater Spokane Inc.
Dave Van Hersett Resource Development Associates
Mike Connelly Idaho Forest Group
John Daquisto Gonzaga University
Lea Daeschel Washington Attorney General’s Office
Deborah Reynolds Washington Utility and Transportation Commission
Steve Johnson Washington Utility and Transportation Commission
David Nightingale Washington Utility and Transportation Commission
Vanda Novak Washington Utility and Transportation Commission
Carrie Dolwick Northwest Energy Coalition
Kirsten Wilson Washington State General Administration
Rick Sterling Idaho Public Utilities Commission
Chuck Murray Community Trade and Economic Development
Tom Noll Idaho Power
Maury Galbraith Northwest Power and Conservation Council
Villamour Gamponia Puget Sound Energy
Mike Kersh Inland Empire Paper
Table 1.2 provides a list of TAC meeting dates and agenda items covered in each
meeting.
Avista Corp 2009 Electric IRP – Public Draft 1-2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 24 of 729
2009 Electric IRPAvista Corp 1-3
Chapter 1 - Introduction and Stakeholder InvolvementChapter 1- Introduction and Stakeholder Involvement
Table 1.2: TAC Meeting Dates and Agenda Items
Meeting Date Agenda Items
TAC 1 – May 14, 2008 • Load and Resource Balance Update
• Climate Change Update
• Renewable Acquisitions
• Loss of Load Probability Analysis
• 2009 IRP Topic Discussions – Work Plan and Analytical Process Changes
TAC 2 – August 27, 2008 • Risk Assumptions/PRiSM
• Resource Assumptions
• Scenarios and Futures
• Demand Side Management
TAC 3 – October 22, 2008 • Load Forecast
• Natural Gas Price Forecast
• Electric Price Forecast
• Legislative Update
TAC 4 – January 28, 2009 • 2008 Peak Load Event
• Natural Gas and Electric Price Update
• Resource Assumptions
• Transmission
• Draft Preferred Resource Strategy
TAC 5 – March 25, 2009 • Conservation
• Preferred Resource Strategy
• Scenarios and Futures
• 2009 IRP Topics
TAC 6 – June 24, 2009 • Presentation of the 2009 PRS
• 2009 IRP Action Items
Issue Specific Public Involvement Activities
Besides TAC meetings, Avista also sponsors and participates in several other collaborative processes involving a range of public interests.
External Energy Efficiency (“Triple E”) Board
The Triple E Board began in 1995 for stakeholders and public groups to gather and discus conservation efforts. The Triple E Group grew out of the DSM Issues group, which was influential in developing the country’s first distribution surcharge for
conservation acquisition for Avista.
FERC Hydro Relicensing – Clark Fork River Projects
Over 50 stakeholder groups participated in the Clark Fork hydro-relicensing process beginning in 1993. This led to the first all-party settlement filed with a Federal Energy
Regulatory Commission (FERC) relicensing application, and eventual issuance of a 45-
year FERC operating license effective March 1, 2001. The nationally recognized Living
License concept was a result of this process. This collaborative process continues in the implementation phase of the Living License with stakeholders participating in various
protection, mitigation and enhancement measures.
Avista Corp 2009 Electric IRP – Public Draft 1-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 25 of 729
Chapter 1 - Introduction and Stakeholder Involvement
2009 Electric IRP1-4 Avista Corp
Chapter 1- Introduction and Stakeholder Involvement
FERC Hydro Relicensing – Spokane River Projects
The Company has utilized a hydro relicensing process for the Spokane River Projects
similar to the process used for relicensing the Clark Fork Projects. Avista was issued a 50-year license for the Spokane River Projects by FERC in June 2009. Approximately
100 stakeholder groups participated in this collaborative effort.
Low Income Rate Assistance Program (LIRAP)
LIRAP progress is shared with several community action agencies in the Company’s Washington service territory through regular meetings. The program began in 2001 and
has quarterly meetings to review administrative issues and needs.
Regional Planning
The Pacific Northwest’s generation and transmission system is operated in a coordinated fashion. Avista participates in many organization’s planning processes.
Information from this participation is used to supplement the Company’s IRP process.
Some organizations Avista participates in are:
• Western Electricity Coordinating Council
• Northwest Power and Conservation Council
• Northwest Power Pool
• Pacific Northwest Utilities Conference Committee
• ColumbiaGrid
• Northwest Transmission Assessment Committee
• Seams Steering Group – Western Interconnection
• North American Electric Reliability Council
Future Public Involvement
Avista actively solicits input from interested parties to enhance the integrated resource
planning process. Advice will be requested from members of the Technical Advisory Committee on a wide variety of resource planning issues. We will continue to work on expanding the diversity of the members on the TAC, and will strive to maintain the TAC
meetings as an open public process.
2009 IRP Outline
The 2009 IRP consists of nine chapters plus an executive summary. A series of
technical appendices supplement this report.
Executive Summary
This chapter summarizes results and highlights of the 2009 IRP.
Chapter 1: Introduction and Stakeholder Involvement
This chapter introduces the IRP and provides details concerning public participation and involvement in the integrated resource planning process.
Avista Corp 2009 Electric IRP – Public Draft 1-4
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 26 of 729
2009 Electric IRPAvista Corp 1-5
Chapter 1 - Introduction and Stakeholder InvolvementChapter 1- Introduction and Stakeholder Involvement
Chapter 2: Loads and Resources
The first half of this chapter covers Avista’s load forecast and relevant local economic
forecasts. The last half describes Company-owned generating resources, major contractual rights and obligations, capacity and energy tabulations and reserve issues.
Chapter 3: Energy Efficiency
This chapter discusses Avista’s energy efficiency programs. It provides an overview of
the programs, descriptions of conservation measures, analysis of conservation measures for the IRP and the conservation results for the 2009 IRP.
Chapter 4: Environmental Policy
This chapter focuses on modeling efforts and issues surrounding greenhouse gas
emissions and state and federal environmental regulations.
Chapter 5: Transmission and Distribution Planning
This chapter discusses Avista’s distribution and transmission systems, as well as
regional transmission planning issues. Transmission cost studies used in IRP modeling
efforts are also covered.
Chapter 6: Generation Resource Options
This chapter covers costs and operating characteristics of generation resource types
modeled for the 2009 IRP.
Chapter 7: Market Analysis
This chapter covers the analysis of wholesale markets for the 2009 IRP.
Chapter 8: Preferred Resource Strategy
This chapter provides details about Avista’s 2009 PRS. It compares the PRS to a variety of theoretical portfolios under stochastic and scenario-based analyses.
Chapter 9: Action Items
This chapter provides an overview of progress made on Action Items from the 2007 IRP
and presents details about Action Items for the 2009 IRP.
Avista Corp 2009 Electric IRP – Public Draft 1-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 27 of 729
Chapter 1 - Introduction and Stakeholder Involvement
2009 Electric IRP1-6 Avista Corp
Chapter 1- Introduction and Stakeholder Involvement
Regulatory Requirements
The IRP process for Washington has several requirements that must be met and
documented under Washington Administrative Code (WAC). Table 1.3 provides the
applicable WACs and indicates the chapter where each rule or requirement is met.
Table 1.3 Washington IRP Rules and Requirements
Rule and Requirement Plan Citation
WAC 480-100-238(4) – Work
plan filed no later than 12 months
before next IRP due date. Work plan outlines content of IRP. Work plan outlines method for
assessing potential resources.
Work plan submitted to the WUTC on August 29,
2008, See Appendix B
WAC 480-100-238(5) – Work
plan outlines timing and extent of
public participation.
Appendix B
WAC 480-100-238(2)(a) – Plan
describes mix of energy supply resources.
Chapter 6- Generation Resource Options
WAC 480-100-238(2)(a) – Plan
describes conservation supply.
Chapter 3- Energy Efficiency
WAC 480-100-238(2)(a) – Plan
addresses supply in terms of current and future needs of utility ratepayers.
Chapter 2- Loads & Resources
WAC 480-100-238(2)(b) – Plan uses lowest reasonable cost
(LRC) analysis to select mix of
resources.
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers resource costs.
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers market-volatility risks.
Chapter 4- Environmental Policy
Chapter 7- Market Analysis Chapter 8- Preferred Resource Strategy
WAC 480-100-238 (2)(b) – LRC analysis considers demand side uncertainties.
Chapter 3- Energy Efficiency
WAC 480-100-238(2)(b) – LRC analysis considers resource
dispatchability.
Chapter 6- Generation Resource Options Chapter 7- Market Analysis
WAC 480-100-238(2)(b) – LRC analysis considers resource
effect on system operation.
Chapter 7- Market Analysis Chapter 8- Preferred Resource Strategy
Avista Corp 2009 Electric IRP – Public Draft 1-6
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 28 of 729
2009 Electric IRPAvista Corp 1-7
Chapter 1 - Introduction and Stakeholder InvolvementChapter 1- Introduction and Stakeholder Involvement
WAC 480-100-238(2)(b) – LRC
analysis considers risks imposed
on ratepayers.
Chapter 4- Environmental Policy
Chapter 6- Generation Resource Options
Chapter 7- Market Analysis Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC analysis considers public policies regarding resource preference
adopted by Washington state or
federal government.
Chapter 2- Loads & Resources Chapter 4- Environmental Policy Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(b) – LRC
analysis considers cost of risks associated with environmental effects including emissions of
carbon dioxide.
Chapter 4- Environmental Policy
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(2)(c) – Plan
defines conservation as any
reduction in electric power consumption that results from increases in the efficiency of
energy use, production, or
distribution.
Chapter 3- Energy Efficiency
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan
includes a range of forecasts of future demand.
Chapter 2- Loads and Resources
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(a) – Plan develops forecasts using methods that examine the effect
of economic forces on the
consumption of electricity.
Chapter 2- Loads and Resources Chapter 5- Transmission & Distribution Chapter 8- Preferred Resource Strategy
WAC 480-100-238-(3)(a) – Plan
develops forecasts using methods that address changes in the number, type and efficiency of
end-uses.
Chapter 2- Loads and Resources
Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution
WAC 480-100-238(3)(b) – Plan
includes an assessment of
commercially available conservation, including load management.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
WAC 480-100-238(3)(b) – Plan includes an assessment of
currently employed and new
policies and programs needed to obtain the conservation improvements.
Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution
Avista Corp 2009 Electric IRP – Public Draft 1-7
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 29 of 729
Chapter 1 - Introduction and Stakeholder Involvement
2009 Electric IRP1-8 Avista Corp
Chapter 1- Introduction and Stakeholder Involvement
WAC 480-100-238(3)(c) – Plan
includes an assessment of a wide
range of conventional and commercially available nonconventional generating
technologies.
Chapter 6- Generator Resource Options
Chapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(d) – Plan
includes an assessment of
transmission system capability and reliability (as allowed by current law).
Chapter 5- Transmission & Distribution
WAC 480-100-238(3)(e) – Plan includes a comparative
evaluation of energy supply
resources (including transmission and distribution) and
improvements in conservation
using LRC.
Chapter 3- Energy Efficiency Chapter 5- Transmission & Distribution
WAC-480-100-238(3)(f) –
Demand forecasts and resource
evaluations are integrated into the long range plan for resource
acquisition.
Chapter 3- Energy Efficiency
Chapter 5- Transmission & Distribution
Chapter 6- Generator Resource OptionsChapter 8- Preferred Resource Strategy
WAC 480-100-238(3)(g) – Plan includes a two-year action plan
that implements the long range plan.
Chapter 9- Action Items
WAC 480-100-238(3)(h) – Plan
includes a progress report on the implementation of the previously filed plan.
Chapter 9- Action Items
WAC 480-100-238(5) – Plan includes description of
consultation with commission
staff. (Description not required)
Chapter 1- Introduction and Stakeholder Involvement
WAC 480-100-238(5) – Plan
includes description of work plan. (Description not required)
Appendix B
Avista Corp 2009 Electric IRP – Public Draft 1-8
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 30 of 729
2009 Electric IRPAvista Corp 2-1
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
2. Loads and Resources
Introduction and Highlights
Loads and resources represent two key components of the Integrated Resource Plan
(IRP). The first half of this chapter summarizes customer and load forecasts for our service territory. This includes forecast ranges, load scenarios and an overview of recent enhancements to our forecasting models and processes. The second half of the
chapter covers resource requirements, including descriptions of Company-owned and
operated resources, as well as long-term contracts.
Section Highlights
• Weak economic growth is expected through 2011 in Avista’s service territory.
• Historic conservation acquisitions are included in the load forecast; higher
acquisition levels anticipated in this IRP reduce the load forecast further.
• Annual electricity sales growth from 2010-2020 averages 1.7 percent over the next decade (199 aMW) and 1.7 percent over the entire 20-year forecast.
• Peak loads are expected to grow at a 1.7 percent annual rate over the next 10 years (312 MW) and 1.7 percent over the 20-year forecast.
• Energy deficits begin in 2018; absent conservation deficits would begin in 2016.
• Renewable portfolio standard deficiencies are the driver of near-termresource need.
Economic Conditions in the Electric Service Territory Avista serves a wide area of eastern Washington and northern Idaho. This area
is geographically and economically diverse.
Avista serves most of the urbanized and
suburban areas in 24 counties. Figure 2.1 is a map of the Company’s electric and natural gas service territories. The orange
areas are electric and yellow areas are
natural gas service territories. The economy of the Inland Northwest has transformed over the past 20 years, from a natural resource-based manufacturing to diversified light manufacturing and services.
Much of the mountainous area of the region is owned by the Federal government and
managed by the United States Forest Service. Timber harvest reductions on public
lands have closed many local sawmills. Two pulp and paper plants served by Avista have access to large forest land holdings; but they continue to face stiff domestic and international competition for their products.
Avista Corp 2009 Electric IRP- Public Draft 2-1
Avista’s Plug-In Hybrid Sun Car
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 31 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-2 Avista Corp
Chapter 2: Loads & Resources
Figure 2.1: Avista’s Service Territory
Employment grows during periods of economic expansion and contracts during
recessions. Our service territory experienced large scale unemployment during two
national recessions in the 1980s. Avista’s service territory was mostly bypassed by the
1991/92 national recession, but was not as fortunate during the 2001 recession. The current recession is expected to end by 2011. Effects of recessions and economic growth are best illustrated by employment for the three principal counties in Avista’s
electric service territory: Bonner, Kootenai and Spokane. Regional employment data is
provided later in this chapter.
Population often is more stable than employment during times of economic change;
however, population contracts during severe economic downturns as people leave in
search of employment opportunities. Over the past 25 years, 1987 was the only year
the region experienced a net loss in population. Figure 2.2 details actual and projected annual population changes in Bonner, Kootenai, and Spokane counties from 1990 to 2030. Figure 2.3 shows total population in these three counties for the same period.
Avista Corp 2009 Electric IRP- Public Draft 2-2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 32 of 729
2009 Electric IRPAvista Corp 2-3
Chapter 2 - Loads and Resources
Chapter 2: Loads & Resources
Figure 2.2: Population Change for Spokane, Kootenai and Bonner Counties
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Avista Corp 2009 Electric IRP- Public Draft 2-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 33 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-4 Avista Corp
Chapter 2: Loads & Resources
People, Jobs and Customers
Avista acquires national and county-level employment and population forecasts from
Global Insight, Inc. Global Insight is an internationally recognized economic forecasting
consulting firm used by various agencies in Washington and Idaho. The data
encompasses the three principal counties which comprise over 80 percent of our service area economy, namely, Spokane County in Washington; and Kootenai and Bonner counties in Idaho. The national forecast for this IRP was prepared in March
2008; county-level estimates were completed in June 2008 and the load forecast was
completed in July 2008.
The forecast and underlying assumptions used in this IRP were presented at the Third
Technical Advisory Committee (TAC) meeting for Avista’s 2009 Integrated Resource
Plan on October 22, 2009. Key forecasts assumptions are shown in Table 2.1.
Table 2.1: Global Insight National Long Range Forecast Assumptions
Assumption Range Assumption Range
Gross Domestic Product 1.9%-3.2%Housing Starts (mil.) 1.5-1.8/year
Consumer Price Index 3.5%-1.7%Job Growth 0.9%/year
West Texas Crude 2000$ $30-$50 Worker Productivity 2%
Fed Funds Rate 4%-8%Consumer Sentiment 90
Unemployment Rate 4.3%-4.9%
Looking forward, the national economy slows after recovering from the present recession, setting the stage for regional economic performance in Avista’s electric
service area. As shown in the charts above, population growth rebounds after slow
growth from 1997 to 2002. Population growth is expected to resume its recent trend
after 2010.
Regional population growth is supported by retiree immigration, representing between
10 and 20 percent of overall population growth. Figure 2.4 presents the population
history and forecast for individuals 65 years and over in the three-county area. Between 1990 and 2010 this segment averages a compound growth rate of 2.6 percent in Bonner County, 4.1 percent in Kootenai County and 1.0 percent in Spokane County.
The age group represents 14.2 percent of the overall population in 2010. The forecast
predicts growth of 3.1 percent, 4.0 percent, and 2.8 percent, respectively, pushing the
overall contribution of this age group to 20.2 percent in 2030.
Avista Corp 2009 Electric IRP- Public Draft 2-4
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 34 of 729
2009 Electric IRPAvista Corp 2-5
Chapter 2 - Loads and Resources
Chapter 2: Loads & Resources
Figure 2.4: Three-County Population Age 65 and Over
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Employment growth often drives population growth. Figure 2.5 shows historical employment trends from 1990 and anticipated growth through 2030.
Figure 2.5: Three-County Job Change
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Avista Corp 2009 Electric IRP- Public Draft 2-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 35 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-6 Avista Corp
Chapter 2: Loads & Resources
Overall non-farm wage and salary employment over the past 20 years averaged 2.8
percent for Bonner County, 5.1 percent for Kootenai County and 2.1 percent for Spokane County. Figure 2.6 provides additional non-farm employment data. Over the
forecast horizon growth rates are predicted at 1.4 percent, 2.8 percent, and 1.4 percent,
respectively. As indicated in the following chart, annual employment growth is expected
to be approximately 6,200 new jobs.
Figure 2.6: Three-County Non-Farm Jobs
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Customer growth projections follow from baseline economic forecasts. The Company
tracks four key customer classes—residential, commercial, industrial and street lighting.
Residential customer forecasts are driven by population. Commercial forecasts rely heavily on employment and lagged residential growth trends. Industrial customer growth is correlated with employment growth. Employment statistics have the greatest
probability of near term changes as we emerge from the present recession. Street
lighting trends with population growth.
Avista forecasts sales by rate schedule. The overall customer forecast is a compilation
of the various rate schedules of our served states. For example, the residential class
forecast is comprised of separate forecasts prepared for rate schedules 1, 12, 22 and
32 for Washington and Idaho. See Figure 2.7 for Avista’s annual average customer forecast levels.
Avista Corp 2009 Electric IRP- Public Draft 2-6
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 36 of 729
2009 Electric IRPAvista Corp 2-7
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
Figure 2.7: Avista Annual Average Customer Forecast
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Avista served 311,807 residential customers, 39,154 commercial customers, 1,393
industrial customers and 433 street lighting customers for a total of 352,786 retail
customers in 2008. This is an increase from 340,652 retail customers in 2006. The 2029 forecast predicts 443,278 residential, 56,849 commercial, 1,654 industrial and 644 street lighting customers for a grand total of 502,425 retail customers. The 20-year
compound growth rate averages 1.7 percent.
Weather Forecasts
The baseline electricity sales forecast is based on 30-year normal temperatures recorded at the Spokane International Airport weather station, as tabulated by the
National Weather Service from 1971 through 2000. Daily values go back as far as 1890.
There are several other weather stations with historical records in the Company’s electric service area; however data is available for a much shorter duration. Sales forecasts are prepared using monthly data because more granular load information is
not available. The Company finds high correlations between the Spokane International
Airport and other weather stations in its service territory. It uses heating degree days to
measure cold weather and cooling degree days to measure hot weather in its retail sales forecast.
In response to questions from the TAC, the Company has implemented estimates of the
impacts of climate change in its retail load forecast. Ample evidence of cooling and warming trends exists in the 115-year record. The recent trend has been a warming climate compared to the 30-year normal. Trends in heating and cooling degree days for
Spokane are roughly equal to the scientific community’s predictions for this geographic
Avista Corp 2009 Electric IRP- Public Draft 2-7
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 37 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-8 Avista Corp
Chapter 2: Loads & Resources
area, implying a one degree warming every 25 years. Incorporating the warming trend
finds that in 20 years summer load would be approximately 26 aMW higher than the 30 year average weather case. In the winter, loads would be approximately 40 aMW lower in 2029, for a net impact of a 14 aMW load decrease. The Company will continue to
study these data trends in its two year Action Plan and report findings in the 2011 IRP.
Price Elasticity Price elasticity is a central economic concept for projecting electricity demand. Price elasticity of demand is the ratio of the percentage change in the quantity demanded of a
good or service to a percentage change in its price. Elasticity measures the
responsiveness of buyers to changes in electricity prices. A consumer who is sensitive
to price changes has a relatively elastic demand profile. A customer who is unresponsive to price changes has a relatively inelastic demand profile. During the 2000-01 energy crisis, customers showed increased sensitivity, or price elasticity of
demand, by reducing their overall electricity usage in response to price increases.
Cross-price elasticity, is the ratio of the percentage change in the quantity demanded of one good to a percentage change in the price of another good. A positive coefficient
indicates that the two products are substitutes; a negative coefficient indicates they are
complementary goods. Substitute goods are replacements for one another. As the price
of the first good increases relative to the price of the second good, consumers shift their consumption to the second good. Complementary goods are used together; increases in the price of one good result in a decrease in demand for the second good along with
the first. The principal cross price elasticity impact on electricity demand is the
substitutability of natural gas in some applications, including water and space heating.
Income elasticity of demand is the ratio of the percentage change in the quantity
demanded of one good to a percentage change in consumer income. Income elasticity
measures the responsiveness of consumer purchases to income changes. Two impacts
affect electricity demand. The first is affordability. As incomes rise, a consumer’s ability to pay for goods and services increases. The second income-related impact is the amount and number of customers using equipment within their homes and businesses.
As incomes rise, consumers are more likely to purchase more electricity-consuming
equipment, live in larger dwellings and use electrical equipment more often.
The correlation between retail electricity prices and the commodity cost of natural gas
has increased in recent years. We estimate customer class price elasticity in our
computation of electricity and natural gas demand. Residential customer price elasticity
is estimated at negative 0.15. Commercial customer price elasticity is estimated at negative 0.10. The cross-price elasticity of natural gas and electricity is estimated to be positive 0.05. Income elasticity is estimated at positive 0.75, meaning electricity is more
affordable as incomes rise.
Avista Corp 2009 Electric IRP- Public Draft 2-8
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 38 of 729
2009 Electric IRPAvista Corp 2-9
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
Retail Price Forecast
The retail sales forecast is based on retail prices increasing an average of 10 percent
annually from 2010 to 2018, followed by increases at the rate of inflation thereafter.
Approximately one third of the rate rise is assumed to be driven by carbon-related legislation, assuming that future federal carbon legislation does not provide for any rate mitigation. The remaining two-thirds of rate rise is for capital additions and higher fuel
costs.
ConservationIt is difficult to separate the interrelated impacts of rising electricity and natural gas prices, rising incomes and conservation programs. Avista collects data on total demand
and must derive the impacts associated with consumption changes. The Company has
offered conservation programs since 1978. The impact of conservation on electricity
usage is fully embedded in the historical data; therefore, we concluded that existing conservation levels (7.5 aMW) are embedded in the forecast. Where conservation acquisition decreases from this level, retail load obligations would increase. As this IRP
forecasts growing conservation acquisition, this growth reduces retail load obligations
from the forecast.
Use Per Customer Projections
The database used to project usage per customer uses monthly electricity sales and the
number of customers by rate schedule, customer class, and state from 1997 to 2008.
Historical data is weather-normalized to remove the impact of heating and cooling degree day deviations from expected normal values, as discussed above. Retail electric price increase assumptions are applied to price elasticity estimates to estimate price-
induced reductions in electrical use per customer.
The Company included a forecast of personal residential electric vehicles in the Base Case. These vehicles are a combination of plug-in hybrids and electric-only and represent a proportional share from the Northwest Power and Conservation Council’s
estimates available in mid-2008. Avista’s share by 2030 is expected to be 85,000 plug-
in hybrid cars, increasing residential load about 1.3% from 2010 to 2030.
The residential use per customer trend over the long term is flat, consistent with
embedded conservation, warming temperatures and price elasticity offset by electric
vehicles. The number of occupants per household is also decreasing over time. Figure
2.8 shows the number of persons per household over the next 20 years.
Avista Corp 2009 Electric IRP- Public Draft 2-9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 39 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-10 Avista Corp
Chapter 2: Loads & Resources
Figure 2.8: Household Size Index
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Residential customers tend to be homogeneous relative to dwelling size. Commercial
customers are heterogeneous, ranging from small customers with varying electricity
intensity per square foot of floor space to big box retailers with generally higher
intensities. The addition of new large commercial customers, specifically universities and hospitals, can greatly skew average use per average customer statistics. Customer
usage is illustrated in Figure 2.9.
Estimates for residential use per customer across all schedules are relatively smooth. Commercial usage per customer is forecast to increase for several years due to additional buildings either built or anticipated to be built by existing very large
customers, such as Washington State University and Sacred Heart Hospital. Expected
additions for very large customers are included in the forecast through 2015, and no
additions are included in the forecast after 2015. We will include publicly-announced long lead time buildings in the load forecast in future IRPs.
Avista Corp 2009 Electric IRP- Public Draft 2-10
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 40 of 729
2009 Electric IRPAvista Corp 2-11
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
Figure 2.9: Annual Use per Customer
Retail Electricity Sales Forecast
Between 1997 and 2008 the region was affected by major economic changes, not the least of which was a marked increase in wholesale and retail electricity prices. The energy crisis of 2000-01 included the implementation of widespread, permanent
conservation efforts by our customers. In 2004, rising retail electricity rates further
reinforced conservation efforts. Several large industrial facilities served by the Company
closed permanently during the 2001-02 economic recession. Recently the economy has entered a significant recession.
Retail electricity consumption rose from 8.2 billion kWh in 1999 to over 8.9 billion kWh in
2008. This increase was in spite of the combined impacts of higher prices and decreased electricity demand during the energy crisis. The forecasted average annual increase in retail sales over the 2009 to 2029 period is 1.8 percent.
The sales forecast takes a “bottom up” approach, summing forecasts of the number of
customers and usage per customer to produce a retail sales forecast. Individual forecasts for our largest industrial customers (Schedule 25) include planned or
announced production increases or decreases. Lumber and wood products industries
have slowed down from very high production levels, which is consistent with the decline
in housing starts at the national level and the current recession. The load forecasts for these sectors were reduced to account for decreased production levels. Anticipated sales to aerospace and aeronautical equipment suppliers have increased and local
plants have announced plans to hire more workers and increase their output.
Avista Corp 2009 Electric IRP- Public Draft 2-11
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 41 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-12 Avista Corp
Chapter 2: Loads & Resources
Actual, not weather corrected, retail electricity sales to Avista customers in 2008 were 8.93 billion kWh. Heating degree days in 2008 were 103 percent of normal, almost completely offset in terms of energy use by 121 percent of normal cooling degree days.
The forecast for 2030 is 12.85 billion kWh, representing a 1.7 percent compounded
increase in retail sales. See Figure 2.10. Degree days in 2030 are forecast to be 87
percent of the 1971-2000 thirty year normal for heating and 149 percent for cooling.
Figure 2.10: Avista’s Retail Sales Forecast
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Street Lights
Industrial
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Load Forecast
Load forecasts are derived from retail sales. Retail sales in kilowatt hours are converted
into average megawatt hours using a regression model to ensure monthly load shapes
conform to history. The Company’s load forecast is termed its native load. Native load is
net of line losses across the Avista transmission system.
Native load growth is shown in Figure 2.11. Note the significant drop in 2001 during the
energy crisis. Loads from 1997 to 2008 are not weather normalized. Annual growth is
expected to be 1.7 percent over the next twenty years. The 2005 and 2007 IRP load
forecasts are presented for comparison purposes. Loads are moderately lower in the 2009 IRP compared with the 2007 IRP due to the cumulative impact of additional
conservation measures from the 2007 IRP being incorporated in this forecast.
Avista Corp 2009 Electric IRP- Public Draft 2-12
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 42 of 729
2009 Electric IRPAvista Corp 2-13
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
Figure 2.11: Annual Net Native Load
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2009 IRP
2007 IRP
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Peak Demand Forecast
The peak demand forecast in each year represents the most likely value for that year. It
does not represent the extreme peak demand. The most likely peak demand has a 50
percent chance of being exceeded in any year. The peak forecast is produced by running a regression between actual peak demand and net native load. The peak demand forecast is in Figure 2.12. Peak loads are expected to grow at 1.7 percent
between 2009 and 2019 (223 MW) and 1.7 percent over the entire 20-year forecast.
Avista Corp 2009 Electric IRP- Public Draft 2-13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 43 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-14 Avista Corp
Chapter 2: Loads & Resources
Figure 2.12: Calendar Year Peak Demand
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Historical data are influenced by extreme weather events. The comparatively low 1999 peak demand figure was the result of a warmer-than-average winter peak day; the peak
in 2006 was the result of a below-average winter peak day. The 1999 and 2006 peak
demand values illustrate why relying on compound growth rates for the peak demand
forecast is an oversimplification and why the Company plans to own or control enough generation assets and contracts to meet peak demand during weather events.
Avista has witnessed significant summer load growth as air conditioning penetration has
risen in its service territory. That said, Avista expects to remain a winter-peaking utility in the foreseeable future. It is possible that very mild winter weather and extremely hot summertime temperatures could result in our summer peak load exceeding our
wintertime demand level in a given year. This will be an anomaly. The 2007 IRP
provided an illustration of this trend into the future.
Figure 2.13 shows the high and low load growth scenarios compared to the base load
forecast. The high load growth scenario projects 2.6 percent load growth over the 20
year forecast. The low load forecast assumes 0.6 percent load growth over the next 20
years.
Avista Corp 2009 Electric IRP- Public Draft 2-14
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 44 of 729
2009 Electric IRPAvista Corp 2-15
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
Figure 2.13: Electric Load Forecast Scenarios
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2009 IRP
High Growth
Low Growth
Avista Resources and Contracts
The Company relies on a diversified portfolio of generating assets to meet customer
loads. Avista owns and operates eight hydroelectric projects located on the Spokane and Clark Fork Rivers. Its thermal assets include partial ownership of two coal-fired units in Montana, four natural gas-fired projects within its service territory, another
natural gas-fired project in Oregon and a biomass plant near Kettle Falls, Washington.
Spokane River Hydroelectric Projects
Avista owns and operates six hydroelectric projects on the Spokane River. These projects received a new 50-year FERC operating license in June 2009. The following
section includes a short description of the Spokane River projects with the maximum
capacity and nameplate ratings for each plant. The maximum capacity of a generating unit is the total amount of electricity a plant can safely generate. This is often higher than the nameplate rating. The nameplate, or installed capacity is the plant’s capacity
as rated by the manufacturer.
Post Falls The upper most hydro facility on the Spokane River is Post Falls, located at its Idaho namesake near the Washington/Idaho border. The project began operation in 1906 and
maintains lake elevation during the summer for Lake Coeur d’Alene. The project has six
units, with the last added in 1980. The project is capable of producing 18.0 MW and has a 14.75 MW nameplate rating. Avista is studying the potential to replace the
Avista Corp 2009 Electric IRP- Public Draft 2-15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 45 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-16 Avista Corp
Chapter 2: Loads & Resources
powerhouse with two larger units to increase energy production at the plant, and
another option to increase generation by upgrading Unit 6.
Upper Falls
The Upper Falls project began generating in 1922 in downtown Spokane and is within
the city’s Riverfront Park. This project is comprised of a single 10.0 MW unit with a
10.26 MW maximum capacity rating. Rewinding the generator and replacing the runner is evaluated in this IRP; the upgrade would increase generation by approximately 2.0
MW.
Monroe Street The Monroe Street facility was the Company’s first generating unit. It started service in 1890 near what is now Riverfront Park. Rebuilt in 1992, the single generating unit has a
15.0 MW maximum capacity and a 14.8 MW nameplate rating. In year’s past a second
powerhouse at Monroe Street was evaluated. As part of the Company’s efforts to
increase renewable generation, this option will be studied further.
Nine Mile
The Nine Mile project was built by a private developer in 1908 near Nine Mile Falls,
Washington, nine miles northwest of Spokane. The Company purchased it in 1925 from the Spokane & Eastern Railway. Its four units have a 17.6 MW maximum capacity1 and a 26.4 MW nameplate rating. Currently Unit 1 provides no generation and Unit 2 is
limited to half load. These units will be replaced and are expected to be online by 2012
and 2013. A rubber dam will be added to the facility, replacing flashboards, to take
advantage of high flows. The total incremental capacity is 8.8 MW and an additional 4.4 aMW of renewable energy from its former operational capability.
Long Lake
The Long Lake project is located northwest of Spokane and maintains Lake Spokane, also known as Long Lake. The facility was the highest spillway dam with the largest turbines in the world when it was completed in 1915. The plant was upgraded with new
runners in the 1990s, adding 2.2 aMW of renewable energy. The project’s four units
provide 88.0 MW of combined capacity and have an 81.6 MW nameplate rating. This IRP evaluates two additional upgrades at the project, either an additional 24 MW unit in the existing powerhouse or the development of a second powerhouse with a 60 MW
generator.
Little Falls The Little Falls project was completed in 1910 near Ford, Washington, and is Avista’s furthest downstream hydro facility on the Spokane River. The facility was recently
upgraded to generate an additional 0.6 aMW of renewable energy with a runner
replacement on Unit 4. The facility’s four units generate 35.2 MW of maximum capacity and have a 32.0 MW nameplate rating. Generator rewinds at each of these units were included at as resource options in this IRP for a total potential of 4.0 MW of additional
capacity and 1.3 aMW of energy.
1 This is the de-rated capacity considering the outage of unit 1 and de-rate of unit 2
Avista Corp 2009 Electric IRP- Public Draft 2-16
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 46 of 729
2009 Electric IRPAvista Corp 2-17
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
Clark Fork River Hydroelectric Project
The Clark Fork River Project includes hydroelectric projects near Clark Fork, Idaho, and Noxon, Montana, 70 miles south of the Canadian border. The plants are operated under a FERC license through 2046.
Cabinet Gorge
The Cabinet Gorge plant started generating power in 1952 with two units. The plant was expanded with two additional generators in the following year. The current maximum capacity of the plant is 270.5 MW; it has a nameplate rating of 265.2 MW. Upgrades at
this project began with the replacement of Unit 1 in 1994. Unit 3 was upgraded in 2001
and Unit 2 was upgraded in 2004. Unit 4, received a $6 million turbine upgrade in 2007, increasing its generating capacity from 55 MW to 64 MW, and adding 2.1 aMW of renewable energy. The Company is evaluating the addition of a fifth unit at the project.
This addition would add 50 to 60 MW of capacity and up to 10.2 aMW of renewable
energy.
Noxon Rapids The Noxon Rapids project includes four generators installed between 1959 and 1960,
and a fifth unit added in 1977. The current plant configuration has a maximum capacity
of 541.0 MW and a generator nameplate rating of 480.6 MW. The project’s units are currently being upgraded. The Unit 1 upgrade was completed in April 2009 and the remaining units will be replaced over the next three years. The upgrades are expected
to add 30 MW of capacity and 6 aMW of qualified renewable energy to the Company’s
resource portfolio.
Total Hydroelectric Generation
In total, our hydroelectric plants are capable of generating as much as 986 MW. Table
2.2 summarizes the Company’s hydro projects. This table also includes the average
annual energy output of each facility based on the 70-year hydrologic record.
Table 2.2: Company-Owned Hydro Resources
Project Name RiverSystem Location StartDate
Nameplate
Capacity (MW)
Maximum
Capability (MW)
Expected
Energy (aMW)
Monroe Street Spokane Spokane, WA 1890 14.8 15.0 11.6
Post Falls Spokane Post Falls, ID 1906 14.7 18.0 9.8
Nine Mile Spokane Nine Mile Falls, WA 1925 26.4 17.6 13.3
Little Falls Spokane Ford, WA 1910 32.0 35.2 23.7
Long Lake Spokane Ford, WA 1915 81.6 88.0 58.4
Upper Falls Spokane Spokane, WA 1922 10.3 10.0 8.6
Cabinet Gorge Clark Fork Clark Fork, ID 1952 265.2 270.5 123.8
Noxon Rapids Clark Fork Noxon, MT 1959 541.0 480.6 197.1
Total 986.0 934.9 446.3
Avista Corp 2009 Electric IRP- Public Draft 2-17
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 47 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-18 Avista Corp
Chapter 2: Loads & Resources
Thermal Resources
Avista owns seven thermal assets located across the Northwest. Each thermal plant is
expected to continue to be available through the 20-year duration of the 2009 IRP. The
Company’s thermal resources provide dependable low-cost energy to serve base loads and provide peak load serving capabilities. A summary of Avista’s thermal resources is shown in Table 2.3.
Colstrip
The Colstrip plant, located in Eastern Montana, consists of four coal-fired steam plants owned by a group of utilities. PPL Montana operates the facilities. Avista owns 15 percent of Units 3 and 4. Unit 3 was completed in 1984 and Unit 4 was finished in 1986.
The Company’s share of each Colstrip unit has a maximum net capacity of 111.0 MW
and a nameplate rating of 123.5 MW. Capital improvements to both units were completed in 2006 and 2007 to improve efficiency, reliability and generation capacity. The upgrades included new high-pressure steam turbine rotors and a conversion from
analog to digital control systems. These capital improvements increased the Company’s
share of generation by 4.2 MW at each unit without any additional fuel consumption.
RathdrumRathdrum is a two-unit simple-cycle combustion turbine. The gas-fired plant is located
near Rathdrum, Idaho. It entered service in 1995 and has a maximum capacity of 180.0
MW in the winter and 126.0 MW in the summer. The nameplate rating is 166.5 MW.
Northeast
The Northeast plant, located in northeast Spokane, is a two-unit aero-derivative simple-
cycle plant completed in 1978. The plant is capable of burning natural gas or fuel oil, but
current air permits prevent the use of fuel oil. The combined maximum capacity of the units is 68.0 MW in the winter and 42.0 MW in the summer, with a nameplate rating of 61.2 MW. Northeast is primarily used for reserve capacity to protect against reliability
concerns and market aberrations.
Boulder Park The Boulder Park project was completed in Spokane Valley in 2002. The site uses six
natural gas-fired internal combustion engines to produce a combined maximum capacity
and nameplate rating of 24.6 MW.
Coyote Springs 2 Coyote Springs 2 is a natural gas-fired combined cycle combustion turbine located near
Boardman, Oregon. The plant began service in 2003. The maximum capacity is 280.6
MW in the winter and 226.5 MW in the summer and the duct burner provides the unit with an additional capability of up to 20.4 MW. The nameplate rating for this plant is 287.3 MW.
Kettle Falls and Kettle Falls CT
The Kettle Falls biomass facility was completed in 1983 near Kettle Falls, Washington and is one of the largest biomass plants in North America. The open-loop biomass
steam plant is fueled by waste wood products from area mills and forest slash, but can
Avista Corp 2009 Electric IRP- Public Draft 2-18
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 48 of 729
2009 Electric IRPAvista Corp 2-19
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
also run on natural gas. A gas-fired CT was
added to the facility in 2002. The CT burns
natural gas and sends exhaust heat to the wood facilities boiler to increase wood fuel efficiency.
The wood portion of the plant has a
maximum capacity of 50.0 MW and a nameplate rating is 50.7 MW; typically the plant operates between 45 and 47 MW due to
fuel quality issues. The plant’s capacity
increases to 56.0 MW when operated in combined-cycle mode with the CT. The CT produces 5.2 MW of peaking capability in the
summer and 7.8 MW in the winter. The CT
resource has limited operations in winter when the gas pipeline is constrained. Avista is
evaluating upgrading the capacity of the pipeline, This IRP also evaluates the addition of a wood gasifier to the project so that the CT can use less natural gas and generate more renewable energy.
Table 2.3: Company-Owned Thermal Resources
Project Name Location Fuel Type StartDate
WinterMaximum
Capacity (MW)
SummerMaximum
Capacity (MW)
Nameplate
Capacity (MW)
Colstrip 3 (15%) Colstrip, MT Coal 1984 111.0 111.0 123.5
Colstrip 4 (15%) Colstrip, MT Coal 1986 111.0 111.0 123.5
Rathdrum Rathdrum, ID Gas 1995 180.0 126.0 166.5
Northeast Spokane, WA Gas 1978 68.0 42.0 61.2
Boulder Park Spokane, WA Gas 2002 24.6 24.6 24.6
Coyote Springs 2 Boardman, OR Gas 2003 301.0 246.9 287.3
Kettle Falls2 Kettle Falls, WA Wood/Gas 1983 50.0 50.0 50.7
Kettle Falls CT Kettle Falls, WA Gas 2002 7.8 5.2 7.2
Total 853.4 716.7 844.5
Power Purchase and Sale Contracts
The Company utilizes several power supply purchase and sale arrangements to meet
some load requirements. This chapter describes some of the larger contracts in effect
during the scope of the 2009 IRP. Contracts can provide many benefits including
environmentally low-impact and low-cost hydro and wind power. A 2010 annual summary of Avista’s large contracts is in Table 2.4.
2 Assumes combined cycle mode; when not in this mode the operational capacity is between 45-47 MW depending upon fuel quality.
Avista Corp 2009 Electric IRP- Public Draft 2-19
Kettle Falls Generation Station
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 49 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-20 Avista Corp
Chapter 2: Loads & Resources
Bonneville Power Administration – WNP-3 Settlement
Avista (then Washington Water Power) signed settlement agreements with Bonneville
Power Administration (BPA) and Energy Northwest (formerly the Washington Public Power Supply System or WPPSS) on September 17, 1985, ending construction delay claims against both parties. The settlement provides an energy exchange through June
30, 2019, with an agreement to reimburse the Company for certain WPPSS –
Washington Nuclear Plant No. 3 (WNP-3) preservation costs and an irrevocable offer of
WNP-3 capability for acquisition under the Regional Power Act.
The energy exchange portion of the settlement contains two basic provisions. The first
provision provides approximately 42 aMW of energy to the Company from BPA through
2019, subject to a contract minimum of 5.8 million megawatt-hours. Avista is obligated to pay BPA operating and maintenance costs associated with the energy exchange as determined by a formula that ranges from $16 to $29 per megawatt-hour in 1987 year
constant dollars.
The second provision provides BPA approximately 32 aMW of return energy at a cost equal to the actual operating cost of the Company’s highest-cost resource. A further discussion of this obligation, and how Avista plans to account for it, is covered under the
Planning Margin heading of this chapter.
Mid-Columbia Hydroelectric Contracts During the 1950s and 1960s, public utility districts (PUDs) in central Washington
developed hydroelectric projects on the Columbia River. Each plant was oversized
compared to the loads then served by the PUDs. Long-term contracts were signed with
public, municipal and investor-owned utilities throughout the Northwest to assist with project financing and to ensure a market for the surplus power.
The Company entered into long-term contracts for the output of four of these projects
“at cost.” The contracts provide energy, capacity and reserve capabilities; in 2010 contracts will provide approximately 164 MW of capacity and 85 aMW of energy. Over the next 20 years, the Wells (2018) and Rocky Reach (2011) contracts will expire.
Avista may be able to extend these contracts; however, it has no assurance today that
extensions will be offered. Due to this uncertainty, the IRP does not include these contracts beyond their expiration dates.
Avista renewed its contract with Grant PUD in 2005 for power from the Priest Rapids
project. The contract term will equal the term in the forthcoming Priest Rapids and
Wanapum dam FERC licenses in 2052.
Lancaster
Avista acquired the output rights to the Lancaster combined-cycle generating station as
part of the sale of Avista Energy to Shell in 2007. Lancaster is also known as the Rathdrum Generating Station, but the plant is referred to as Lancaster in this IRP to remove confusion with the Rathdrum CT. The project is under a tolling Power Purchase
Agreement (PPA) with Energy Investors Funds (80 percent owner) and Goldman Sachs
(20 percent owner) through October 2026. Avista has the right to dispatch the plant and
Avista Corp 2009 Electric IRP- Public Draft 2-20
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 50 of 729
2009 Electric IRPAvista Corp 2-21
Chapter 2 - Loads and ResourcesChapter 2: Loads & Resources
is responsible for providing fuel, energy, and capacity payments. The 2007 IRP showed
that the Lancaster project was a lower cost acquisition than a greenfield site and was
also lower in cost than recent CCCT transactions in the Northwest.
Table 2.4: Large Contractual Rights and Obligations
Contract Type End Date
WinterCapacity
(MW)
SummerCapacity
(MW)
2010AnnualEnergy
(aMW)
Canadian Entitlement Sale n/a 6.3 6.3 3.6
Douglas Settlement Purchase Sep-2018 2.5 3.9 3.7
Forward Market Purchase Dec-2010 100.0 100.0 100.0
Grant Displacement Purchase Sep-2011 17.4 19.6 22.0
Lancaster Purchase Oct-2026 281.0 264.0 237.8
Nichols Pumping Sale n/a 6.8 6.8 6.8
PGE Capacity Exchange Dec-2016 150.0 150.0 0.0
Potlatch PURPA Dec-2011 75.0 75.0 47.6
Rocky Reach Purchase Oct-2011 34.5 34.0 20.3
Stateline Purchase Dec-2011 0.0 0.0 8.3
Stimson Lumber PURPA Sep-2011 4.2 4.4 4.2
Upriver (net load) PURPA Dec-2011 8.2 -1.3 6.1
Wanapum/Priest Rapids Purchase Mar-2052 67.6 66.6 34.8
Wells Purchase Aug-2018 26.1 25.9 14.7
WNP-3 Purchase/Sale Jun-2019 89.3 0.0 42.3
Reserve Margins
Planning reserves accommodate situations when loads exceed and/or resources are
below expectations due to adverse weather, forced outages, poor water conditions or
other contingencies. There are disagreements within the industry on adequate reserve margin levels. Many stem from system differences, such as resource mix, system size, and transmission interconnections. For example, a hydro-based utility generally has a
higher capacity to energy ratio than a thermal-based utility.
Reserve margins, on average, increase customer rates when compared to resource portfolios without reserves, due to carrying additional cost of generation. Reserve resources have the physical capability to generate electricity, but high operating costs
limit economic dispatch and the potential to create revenues to offset capital
investments.
Avista Planning Margin
Avista retains two types of planning margins—capacity and energy. Capacity planning is
a traditional planning metric for many utilities to ensure they can meet peak loads at
times of system strain. Energy planning is used for utilities with resources that have an unpredictable fuel source, such as wind and hydro, but also to cover load variance. For
capacity planning, Avista reserves are not directly based on unit size or resource type.
Avista Corp 2009 Electric IRP- Public Draft 2-21
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 51 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-22 Avista Corp
Chapter 2: Loads & Resources
Planning reserves are set at a level equal to 15 percent planning reserve margin during
the Company’s peak load hour.
For energy planning, resources must be adequate to meet customer requirements.
Extreme weather conditions can change monthly energy obligations by up to 30
percent. If generation capability does not meet high load variations, customers and the
utility are exposed to increased short term market volatility. In addition to load variance, Avista also uses a planning margin for its hydro generation. Unlike weather, hydro is not normally distributed due to river regulation by the hydroelectric projects.
There is a difference of regional opinion concerning the proper method for establishing a resource planning margin. Many utilities in the Northwest base their capacity planning on critical water using the 1936/37 hydro year as the critical time period. The critical
water year of 1936/37 is poor on an annual basis, but it is not necessarily critical month-
to-month. The utility could build resources to reach the 99 percent confidence level, and
could significantly decrease the frequency of market purchases, but this strategy requires approximately 200 MW of additional generation capability. Additional capital expenditures to support this level of reliability would put upward pressure on retail rates.
Analysis of historical data indicates that an optimal criterion is the use of a 90 percent
confidence interval based on the monthly variability of load and the 10th percentile of monthly historical hydro energy. This results in a 10 percent chance of load exceeding the planning criteria for each month. In other words, there is a 10 percent chance that
the Company would need to purchase energy from the market in any given month.
Additional variability is inherent in Avista’s WNP-3 contract with BPA. The contract includes a return energy provision that can equal 32 aMW annually. The contract would be exercised under adverse conditions, such as low hydroelectric generation or high
loads. The contract was last exercised in 2001. Energy planning margin is increased by
32 aMW to account for the WNP-3 obligation through its expiration in 2019. The total capacity planning margin and energy margin adds 267 MW of required capacity and 227 aMW of energy in 2010.
Other Planning Methods
Parallel to planning margins is a gray area between energy and capacity planning. Sustained peaking and Loss of Load Probability (LOLP) metrics can be used to further evaluate system constraints. Avista has actively participated in the Northwest Power
and Conservation Council’s Resource Adequacy committees over the past few years.
This effort has used LOLP and sustained capacity analyses to evaluate the Northwest’s
resource position over extended timeframes. Preliminary work indicates that the Northwest should carry approximately a 25 percent planning margin in the wintertime and a 17 percent planning margin in the summertime. These levels are much higher
than the 12 to 15 percent levels recommended in other markets, primarily due to the
Northwest’s heavier reliance on hydroelectric generation. Given the uncertainties surrounding higher planning margins, Avista will not adopt the NPCC metrics in this planning cycle. The Company will continue to participate in the regional process and will
use the results for future resource planning.
Avista Corp 2009 Electric IRP- Public Draft 2-22
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 52 of 729
2009 Electric IRPAvista Corp 2-23
Chapter 2 - Loads and Resources
Chapter 2: Loads & Resources
Sustained peaking capacity is a tabulation of loads and resources over a period
exceeding the traditional one-hour definition. It is also a measure of reliability and recognizes that peak loads do not stress the system for just one hour. The difference from traditional one hour peak analysis is a look at multiple days versus one hour. The
analysis also considers hydro system impacts by freezing temperatures and hydro
reservoir depletion.
LOLP has only recently gained attention in the Northwest. The industry standard is a 5.0 percent acceptable loss of load. Avista has created a tool to evaluate LOLP, but there is
still significant uncertainty surrounding how much energy from the wholesale market
would be available to Avista at a time of regional peak loads. At the first TAC meeting, an early analysis was shown for 2009 and included many scenarios. The results of this study indicated for the 2009 planning year the LOLP is 2.1 percent in the winter and 3.8
percent in the summer, but this includes a market availability of 300 MW. If only 200
MW of on-peak market is available, the LOLP increases to 7.4 percent in the winter and
12.1 percent in the summer. Additional studies are required for this analysis. The goal for the LOLP tool is to ensure the Preferred Resource Strategy adds resources adequate to meet reliability criteria, but the critical assumption is the amount of energy
available from the market. The Northwest Power and Conservation Council is studying
this problem, and Avista will use the results from that process.
Washington State Renewable Portfolio Standard
In the November 2006 general election, Washington State voters approved Citizens
Initiative 937. The initiative requires utilities with more than 25,000 customers to source
3 percent of their energy from qualified renewables by 2012, 9 percent by 2016, and 15 percent by 2020. Utilities also must acquire all cost effective conservation and energy efficiency measures. Even though Avista does not require new resources to meet
forecasted loads through 2017, this new law requires Avista to acquire qualified
renewable generation or Renewable Energy Certificates (REC) resources it otherwise
would not need to meet the initiative’s renewable goals.
Avista will meet or exceed its renewable requirement goals between 2012 and 2015
with a recent REC purchase and qualified hydroelectric upgrades. The Company plans
to acquire resources to ensure that it is not forced to make REC purchases in a strained market in nine of 10 years due to lower-than-expected wind and hydro generation levels. See Table 2.5.
Resource Requirements
The differences between loads and resources illustrate potential needs the Company must address through future resource acquisitions. Avista regularly develops a 20-year forecast of peak capacity loads and resources. Peak load is the maximum one-hour
obligation, including operating reserves, on the expected average coldest day in
January and the average hottest day in August. Peak resource capability is the
maximum one hour generation capability of Company resources, including net contract contribution, at the time of the one-hour system peak, and excludes resource that are
on maintenance during peak load periods.
Avista Corp 2009 Electric IRP- Public Draft 2-23
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 53 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-24 Avista Corp
Chapter 2: Loads & Resources
Avista is surplus capacity through 2014. It then carries a modest deficit until the
Portland General Exchange contract expires in 2016. Avista is then capacity surplus in 2019. Deficits grow after 2018 as peaking requirements increase with load growth, and
as the Company’s resource base declines with the expiration of market purchases and
Mid-Columbia hydroelectric project contracts. Winter and summer capacity positions are
shown in Figures 2.15 and 2.16, respectively. Tabular views of this data are in Table 2.6 and Table 2.7.
In addition to balancing capacity, Avista procures enough resources to meet its energy
obligations. The energy position includes resources at their full capability during normal
weather conditions in each month. It includes generation maintenance schedules and loads based on expected normal temperatures. The first deficit year for energy
(including the planning margin) is 2018. Quarterly deficits begin in the fourth quarter of
2014. A graphical representation of Avista’s positions is shown in Figure 2.17; a tabular
version of the data is shown Table 2.8. Each of these charts includes conservation levels per the 2007 IRP. In Chapter 8, conservation levels are updated to reflect 2009 IRP levels.
Figure 2.15: Winter Capacity Position
0
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Avista Corp 2009 Electric IRP- Public Draft 2-24
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 54 of 729
2009 Electric IRPAvista Corp 2-25
Chapter 2 - Loads and Resources
Chapter 2: Loads & Resources
Avista Corp 2009 Electric IRP- Public Draft 2-25
0
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Figure 2.16: Summer Capacity Position
Load
Hydro
Contracts
Figure 2.17: Annual Average Position
Load
Base Thermal
Load w/PM, w/o Maint
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Chapter 2: Loads & Resources
Avista is surplus capacity through 2014. It then carries a modest deficit until the Portland General Exchange contract expires in 2016. Avista is then capacity surplus in 2019. Deficits grow after 2018 as peaking requirements increase with load growth, and
as the Company’s resource base declines with the expiration of market purchases and
Mid-Columbia hydroelectric project contracts. Winter and summer capacity positions are
shown in Figures 2.15 and 2.16, respectively. Tabular views of this data are in Table 2.6 and Table 2.7.
In addition to balancing capacity, Avista procures enough resources to meet its energy
obligations. The energy position includes resources at their full capability during normal weather conditions in each month. It includes generation maintenance schedules and loads based on expected normal temperatures. The first deficit year for energy
(including the planning margin) is 2018. Quarterly deficits begin in the fourth quarter of
2014. A graphical representation of Avista’s positions is shown in Figure 2.17; a tabular
version of the data is shown Table 2.8. Each of these charts includes conservation levels per the 2007 IRP. In Chapter 8, conservation levels are updated to reflect 2009 IRP levels.
Figure 2.15: Winter Capacity Position
0
500
1,000
1,500
2,000
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3,000
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Contracts Peakers
Load Load w/PM, w/o Maint
Avista Corp 2009 Electric IRP- Public Draft 2-24
Chapter 2: Loads & Resources Avista is surplus capacity through 2014. It then carries a modest deficit until the Portland General Exchange contract expires in 2016. Avista is then capacity surplus in 2019. Deficits grow after 2018 as peaking requirements increase with load growth, and as the Company’s resource base declines with the expiration of market purchases and Mid-Columbia hydroelectric project contracts. Winter and summer capacity positions are shown in Figures 2.15 and 2.16, respectively. Tabular views of this data are in Table 2.6 and Table 2.7. In addition to balancing capacity, Avista procures enough resources to meet its energy obligations. The energy position includes resources at their full capability during normal weather conditions in each month. It includes generation maintenance schedules and loads based on expected normal temperatures. The first deficit year for energy (including the planning margin) is 2018. Quarterly deficits begin in the fourth quarter of
2014. A graphical representation of Avista’s positions is shown in Figure 2.17; a tabular
version of the data is shown Table 2.8. Each of these charts includes conservation
levels per the 2007 IRP. In Chapter 8, conservation levels are updated to reflect 2009 IRP levels.
Figure 2.15: Winter Capacity Position
0
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1,000
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Contracts Peakers
Load Load w/PM, w/o Maint
Avista Corp 2009 Electric IRP- Public Draft 2-24
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 55 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-26 Avista Corp
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P
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D
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26
Ch
a
p
t
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r

2
:

L
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s

&

R
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s
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s

Ta
b
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2
.
5
:

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t
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)

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20
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6
W A

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F
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1
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29

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Pl
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68
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RP
S

%
0%

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%

3
%

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%

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%

3
%

9
%

9
%

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%

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%

1
5
%

1
5
%

1
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%

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%

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%

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%

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Re
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3
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3
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R
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16
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1
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4
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t

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6
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6

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y
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1
20
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4
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D
r
a
f
t

26
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 56 of 729
2009 Electric IRPAvista Corp 2-27
Chapter 2 - Loads and Resources
Ch
a
p
t
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r

2
:

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o
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58
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To
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PE
A
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P
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S
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T
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47
4

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4
2

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4
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7
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4
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1
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1
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4
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8

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5
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RE
S
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R
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P
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Pl
a
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R
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8
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3
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3
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3
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9

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3
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3
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3
3
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3
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k

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6
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8
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1
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3
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6

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5
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9
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A
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.

3
1
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3
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5
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6
0

2
0

-
4
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1
6
4

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2
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1

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2
3
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2
7
3

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6

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3
6
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4
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7
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6

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7
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8
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3
Av
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s
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a

C
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p

20
0
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e
c
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I
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P
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b
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c

D
r
a
f
t

27
Ch
a
p
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r

2
:

L
o
a
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s

&

R
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s
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c
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s

Ta
b
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e

2
.
6
:

W
i
n
t
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r

C
a
p
a
c
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P
o
s
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t
i
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n

(
M
W
)

-

P
l
a
n

f
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r

P
o
s
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n

E
x
c
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u
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M
a
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20
1
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2
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2
0
2
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6

2
0
2
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2
0
2
8

2
0
2
9
RE
Q
U
I
R
E
M
E
N
T
S
Na
t
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e

L
o
a
d
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,
7
7
9

-
1
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8
1
2

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1
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8
3
9

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1
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8
6
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1
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8
9
3

-
1
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3
7

-
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9
6
7

-
1
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9
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-
2
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0
3
3

-
2
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2
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1

-
2
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1
2
4

-
2
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1
5
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-
2
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1
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-
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2
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-
2
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2
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-
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3
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-
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3
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9
Co
n
t
r
a
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t
s

O
b
l
i
g
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t
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n
s
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4
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-
2
3
9

-
2
3
9

-
2
3
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2
3
9

-
1
6
4

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1
6
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1
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4

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1
2

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1
2

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2

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2

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2

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2

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1
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To
t
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l

R
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q
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s
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1
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-
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-
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-
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3

-
2
,
1
3
6

-
2
,
1
6
6

-
2
,
1
9
7

-
2
,
2
3
4

-
2
,
2
7
3

-
2
,
3
3
1

-
2
,
3
6
4

-
2
,
3
9
8

-
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1
RE
S
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S
Co
n
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a
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s

R
i
g
h
t
s
65
7

5
5
7

5
3
9

5
3
9

5
3
9

4
6
4

4
6
4

4
6
4

4
6
4

4
6
2

3
7
2

3
7
2

3
7
2

3
7
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3
7
1

3
7
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3
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1

9
0

9
0

9
0
Hy
d
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R
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s
o
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c
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s
1,
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,
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9
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9
9
7

9
9
7

9
9
7

9
9
7

9
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9
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9
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1

9
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9
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4
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9
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9
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9
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4
Ba
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L
o
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s
58
0

5
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Pe
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U
n
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22
6

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2
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2
2
6

2
2
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2
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2
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2
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2
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To
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PE
A
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P
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S
I
T
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47
4

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1
5

2
4
2

2
4
6

2
1
4

1
7
0

1
4
1

2
3
2

2
2
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1
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9

5
0

-
1
0

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1
4

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4
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8
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8
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5
2
8

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5
8
7
RE
S
E
R
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G
Pl
a
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R
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s
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M
a
r
g
i
n
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6
7

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2
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2

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8
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9
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9
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3
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3
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9

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3
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9

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3

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2
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3
3
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3
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k

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W
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M
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.
20
7

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6
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2
6
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3
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8

-
3
3
7

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3
7
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6

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4
6

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9
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E
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3
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1
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0

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2
0
1

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7
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Av
i
s
t
a

C
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20
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I
R
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-

P
u
b
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c

D
r
a
f
t

27
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 57 of 729
Chapter 2 - Loads and Resources
2009 Electric IRP2-28 Avista Corp
Ch
a
p
t
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r

2
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Ta
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2
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RE
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Co
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To
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R
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RE
S
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Co
n
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s

R
i
g
h
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s
54
5

4
4
5

4
2
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4
2
5

4
2
5

3
5
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3
5
0

3
5
0

3
5
0

3
4
6

3
4
6

3
4
6

3
4
6

3
4
6

3
4
6

3
4
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3
4
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8
2

8
2

8
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Hy
d
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R
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95
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Ba
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L
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T
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m
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57
7

5
8
1

5
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Pe
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To
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PE
A
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P
O
S
I
T
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N
37
4

2
2
2

2
6
6

2
5
5

2
5
1

1
8
9

1
8
4

2
8
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2
5
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2
2
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1
9
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1
4
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1
1
6

8
7

9
0

2
4

-
2
7

-
3
1
3

-
3
2
2

-
3
7
7
RE
S
E
R
V
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P
L
A
N
N
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G
Pl
a
n
n
i
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R
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s
e
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M
a
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g
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n
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4
9

-
2
5
4

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2
5
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2
6
1

-
2
6
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2
7
1

-
2
7
5

-
2
7
9

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2
8
3

-
2
8
7

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2
9
1

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2
9
5

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3
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3
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3
1
3

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3
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3
2
5

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3
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3
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Pe
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k

P
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w
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M
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.
12
5

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3

8

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1
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1

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3
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6
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9
2

-
1
5
2

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1
8
2

-
2
1
6

-
2
1
7

-
2
8
9

-
3
4
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6
3
7

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6
5
1

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7
1
1
PO
S
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M
A
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.

2
9
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1
2
4

5
3

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0

-
4
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-
7
4

4
5

1
1

-
4
6

-
7
6

-
1
0
8

-
1
3
9

-
1
6
9

-
2
0
6

-
2
4
5

-
3
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4

-
6
0
0

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6
3
4

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6
6
7
Av
i
s
t
a

C
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p

20
0
9

E
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c
t
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c

I
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P
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b
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c

D
r
a
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28
Ch
a
p
t
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r

2
:

L
o
a
d
s

&

R
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s
o
u
r
c
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s

Ta
b
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e

2
.
8
:

A
n
n
u
a
l

E
n
e
r
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y

P
o
s
i
t
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o
n

(
a
M
W
)

-

P
l
a
n

f
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r

C
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t
i
n
g
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n
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y

N
e
t

P
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s
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t
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n

20
1
0

2
0
1
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2
0
1
2

2
0
1
3

2
0
1
4

2
0
1
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7

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2
4

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0
2
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2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9
RE
Q
U
I
R
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M
E
N
T
S
Na
t
i
v
e

L
o
a
d
-1
,
1
4
8

-
1
,
1
7
1

-
1
,
1
8
9

-
1
,
2
0
2

-
1
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2
2
2

-
1
,
2
5
2

-
1
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2
7
0

-
1
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2
8
9

-
1
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3
1
1

-
1
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3
2
9

-
1
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3
4
8

-
1
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3
6
7

-
1
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3
8
6

-
1
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4
0
5

-
1
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4
2
9

-
1
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4
5
2

-
1
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4
9
1

-
1
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5
1
1

-
1
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5
3
3

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1
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5
3
Co
n
t
r
a
c
t

O
b
l
i
g
a
t
i
o
n
s
-1
3
9

-
1
3
9

-
1
3
9

-
1
3
9

-
1
3
9

-
6
4

-
6
4

-
1
2

-
1
1

-
1
1

-
1
1

-
1
1

-
1
1

-
1
1

-
1
1

-
1
1

-
1
1

-
1
1

-
1
1

-
1
1
To
t
a
l

R
e
q
u
i
r
e
m
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s
-1
,
2
8
7

-
1
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3
1
0

-
1
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3
2
8

-
1
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3
4
1

-
1
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3
6
1

-
1
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3
1
5

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1
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3
3
4

-
1
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3
0
1

-
1
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3
2
2

-
1
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3
3
9

-
1
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3
5
8

-
1
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3
7
8

-
1
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3
9
7

-
1
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4
1
6

-
1
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4
3
9

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29
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 58 of 729
2009 Electric IRPAvista Corp 3-1
Chapter 3 - Energy EfficiencyChapter 3–Energy Efficiency
3. Energy Efficiency
Introduction
Avista’s energy efficiency programs provide a wide range of conservation options and education for
residential, commercial, industrial and low income
customers. Programs fall into prescriptive and site-
specific classifications. Prescriptive programs offer cash incentives for standardized products, such as
compact fluorescent light bulbs and high efficiency
appliances. These programs are primarily directed
towards residential and small commercial customers. Site-specific programs provide cash incentives for any cost-effective energy savings
measure with a payback greater than one year.
These site-specific programs require customized services for commercial and industrial customers because many applications need to be tailored to
the unique characteristics of customer’s premises
and processes.
Chapter Highlights
• Conservation additions provide 26 percent of new supplies through 2020.
• 2009 IRP includes 0.3 aMW (3.3 percent) more conservation than the 2007 IRP.
• Avista has offered conservation programs for over 30 years.
• The Company has acquired 138.5 aMW of electric efficiency in the past three decades; an estimated 109 aMW continue to reduce customer loads.
• The Company is prepared to quickly respond to another energy crisis with efficiency measures.
• Approximately 3,000 efficiency measures were evaluated for the 2009 IRP.
• 7.5 aMW of local and 2.9 aMW of regional conservation are expected in 2010.
Avista has continuously offered electric efficiency programs since 1978. Some of Avista’s most notable efficiency achievements include the Energy Exchanger programs,
which converted over 20,000 homes from electric to natural gas space or water heating
from 1992 to 1994; pioneering the country’s first system benefit charge for energy
efficiency in 1995; and the immediate conservation response during the 2001 Western energy crisis which tripled annual energy savings at only twice the cost in half the time during a period of high wholesale market prices. The Company’s conservation programs
provide savings that regularly meet or exceed its regional share of energy efficiency
savings as outlined by the Northwest Power and Conservation Council (NPCC). Figure
3.1 illustrates Avista’s historical electricity conservation acquisitions.
Avista Corp 2009 Electric IRP – Public Draft 3-1
Energy efficient window replacement at Avista’s
headquarters in Spokane, Washington
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 59 of 729
Chapter 3 - Energy Efficiency
2009 Electric IRP3-2 Avista Corp
Chapter 3–Energy Efficiency
Figure 3.1: Historical Conservation Acquisition
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Avista has acquired 138.5 aMW of cumulative electricity efficiency resources over the last 30-years; of the 138.5 aMW total, 109 aMW acquired during the last 18 years is
assumed to still be online and providing resource value today. Northwest Energy
Efficiency Alliance’s (NEEA’s) cumulative conservation estimates are based on an 18-
year average weighted measure life.
All conservation measures and programs have been examined based on surrogate
generation costs in this IRP. New savings targets have been established and the Company is planning a significant ramp-up of energy efficiency activity in the coming years.
Avista is also expanding the breadth of its energy efficiency activities to include demand response initiatives and is analyzing the potential for transmission and distribution efficiency measures. More details about transmission and distribution efficiency projects
can be found in the Transmission and Distribution chapter of this IRP. Our demand
response pilot is still in process, so there is not enough data to currently determine if Avista will continue demand response initiatives, and they were not included in this IRP. The results of the demand response pilot will be addressed in detail in the 2011 IRP.
Avista Corp 2009 Electric IRP – Public Draft 3-2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 60 of 729
2009 Electric IRPAvista Corp 3-3
Chapter 3 - Energy EfficiencyChapter 3–Energy Efficiency
Cooperative Regional Market Transformation Programs
Avista is a funding and fully participating member of NEEA, www.nwalliance.org. NEEA
is funded by regional investor-owned and public utilities to acquire electric efficiency
measures that are best achieved through broad market transformation efforts. These programs reach beyond individual service territories and consequently require regional cooperation to succeed.
Past NEEA funding has been $20 million shared throughout the region. Avista’s four percent annual portion of NEEA funding has been $800,000. The Northwest funding
utilities have been discussing increasing this amount by 50 percent or more and
reapportioning member shares to reflect current retail load. Avista’s share would be
increased from 4.0 percent to 5.41 percent. This increase in our regional funding share would increase our savings acquisition by 30% or more. NEEA has proven to be a cost-
effective component of regional resource acquisition. Avista has and continues to
leverage NEEA ventures when cost-effective enhancements can be achieved.
Attributing regionally acquired conservation savings to individual utilities is difficult. To
ensure that resources are not double-counted at regional and local levels, NEEA has
excluded all energy for which local utility rebates have been granted. This allows the
summation of local and regional acquisitions to determine the total impact in a market. Avista has typically applied our funding share of slightly less than four percent to
NEEA’s annual claim of energy savings. It was assumed that historic acquisitions would
remain flat at the most recent level because there are no reliable 20-year estimates of
regional program acquisitions. This assumption is speculative and dependent on the opportunities for regional market transformation during this period. It is consistent with the recent history of NEEA funding.
Program Funding
Avista changed its approach to conservation cost-recovery in 1995 from the traditional capitalization of the investments to cost-recovery through a non-bypassable public benefits surcharge (the tariff rider). Avista currently manages four separate tariff riders
for Washington electric, Idaho electric, Washington natural gas and Idaho natural gas
investments. Based upon the demand for funds and incoming tariff rider revenues, this
balance can be positive or negative at any particular point in time.
The aggregate tariff rider balances were returned to a zero balance in 2005 from a
$12.4 million deficit in the aftermath of the 2001 Western energy crisis. Recent demand for conservation services has exceeded tariff rider revenues. The most recent projection forecasts a $3.6 million negative balance in the Washington electric DSM tariff rider by
the end of 2009. The Idaho electric tariff balance is projected to be just below $4.0
million with schedule 91 increases effective August 1, 2009.
Energy Independence Act
Washington’s Energy Indpendence Act, established under Initiative 937 (I-937), and
codified under RCW 19.285, requires utilities with over 25,000 customers to obtain a
fixed percentage of their electricity from qualifying renewable resources. The mandates
are three percent of retail load in Washington by 2012, nine percent by 2016 and 15 percent by 2020. As experience has shown in other jurisdictions, these requirements
Avista Corp 2009 Electric IRP – Public Draft 3-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 61 of 729
Chapter 3 - Energy Efficiency
2009 Electric IRP3-4 Avista Corp
Chapter 3–Energy Efficiency
could be changed by the state legislature in the future. In addition to its RPS, I-937 also
requires utilities with over 25,000 customers to acquire all cost-effective and achievable
energy conservation. The methodology for identifying the conservation target must be
consistent with the methods used by the Northwest Power and Conservation Council (NPCC) in its power plans. Avista’s methodology for identifying its conservation target is consistent with the NPCC Sixth Power Plan methodology to the extent possible given
the timing of the two processes (this IRP was completed prior to the completion of the
Sixth Power Plan). The conservation inputs for this IRP process leveraged the NPCC
work. To the extent that significant changes are incorporated into the Sixth Power Plan after the completion of this IRP, it is Avista’s intent to reserve the opportunity to
substitute our share of the regional conservation potential ultimately defined by the Sixth
Power Plan, on a year-by-year basis, for the conservation targets identified in this IRP.
The first performance period for the Washington energy efficiency target will be 2010-
2011. Washington regulations require the Company to file its biennial conservation
target on or before January 31, 2010. Avista’s report, as required by WAC 480-109
(3)(c), will “describe the technologies, data collection, processes, procedures and assumptions the utility used to develop these figures. This report must describe and
support any changes in assumptions or methodologies used in the Utility’s most recent
IRP or the Conservation Council’s [NPCC] Power Plan.” WAC 480-109 requires
approval, approval with modifications or rejection by the WUTC of the Company’s targets. Avista’s filing will follow, and this IRP will be consistent with, the NPCC’s Sixth Power Plan. The Company’s report will include traditional conservation efforts (possibly
exclusive of electric to natural gas conversions), non-programmatic adoption of energy
efficiency measures consistent with the Sixth Power Plan and distribution efficiency
measures which would include savings on the utility and customer sides of the meter. Since distribution efficiencies count toward our goal, meeting plan requirements with the
least net cost to ratepayers will involve interdepartmental coordination of efforts and
development of new processes.
American Recovery and Reinvestment Act of 2009
Portions of the American Recovery and Reinvestment Act of 2009 (ARRA) provide
economic stimulus funding for energy conservation, including residential audits,
weatherization and smart grid development. Avista is working with local governments to
field residential audits funded by a combination of our energy efficiency tariff rider, local government Energy Efficiency Conservation Block Grant (EECBG) funds, State Energy Program funds and the customer. The most recent iteration of these analyses calls for a
"mid-level" audit that includes the installation of low-cost measures such as CFL's, door
sweeps, water tank blankets, low-flow showerheads, furnace filter replacements, refrigerator and coil cleaning and several infiltration reduction measures. The audit is a $325 direct investment including about $160 in low-cost direct-install measures and
$165 in auditor labor cost. The Company anticipates some program administrative labor
needs on the back-end and estimates this to be the equivalent of about 2.9 full-time
employees.
Avista Corp 2009 Electric IRP – Public Draft 3-4
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 62 of 729
2009 Electric IRPAvista Corp 3-5
Chapter 3 - Energy EfficiencyChapter 3–Energy Efficiency
The Company currently estimates that customers will pay $150, with the remainder of
the $325 incremental audit cost being split between the tariff rider and local government
EECBG funds. The full cost of back office labor will also be funded by the tariff rider. If a
local government chooses to not provide EECBG funds, customers will be responsible for paying the total cost of the audit. This enables Avista to offer this service throughout
our Washington and Idaho jurisdictions, regardless of how different local governments
choose to use their EECBG funds.
The ARRA economic stimulus funding low income weatherization will be allocated directly to regional community action agencies, as they already have the infrastructure
necessary to distribute these funds to low income customers. Therefore, Avista will not
be involved in administering programs funded under this portion of the ARRA. Low
income populations served by the economic stimulus funding will not be counted towards our conservation goals since the Company is not contributing to the acquisition
process.
Avista may participate in a regional smart grid demonstration project. The project scope would include distribution automation, distributed generation, energy storage, advanced metering infrastructure (AMI), software and support and demand response. The
application deadline for this project is August 26, 2009.
Electricity Efficiency in the 2009 IRP
Avista has reviewed its efficiency options to ensure it is evaluating all alternatives in an effort to delay building additional generation industry infrastructure. The Heritage Project began during the 2007 IRP evaluation and “roadmaps” for several key areas were
developed and followed. The roadmaps included: energy efficiency, demand response,
transmission and distribution, and analytics.
Energy Efficiency
The Company has completed a comprehensive assessment of industry best practices in
energy efficiency and enhanced its program offerings. As a result of this process, the
Company launched rebate programs for residential fireplace dampers, non-residential
prescriptive side-stream filtration, prescriptive energy/heat recovery ventilation, prescriptive demand control ventilation, prescriptive steam trap maintenance, retro-
commissioning, as well as offering CFL coupons and community outreach and
education on low cost and no cost ways to save energy. In addition, the Company has
an on-going Facilities Model Program focusing on energy efficiency while maintaining and upgrading our facilities. Several projects at Avista’s facilities, such as HVAC control upgrades, variable frequency drives (VFDs) on fan motors, and upgrades to the
economizer cooling were estimated to save the Company 270,000 kWh and nearly
20,000 therms per year. The Company continues to assess the implementation of cost-
effective energy efficiency upgrades where appropriate.
Load Management
While Avista faces higher market prices during peak demand periods, our costs are very
different from other parts of the country. Technology costs continue to decline while
technological improvements continue to develop making integration with our system a
Avista Corp 2009 Electric IRP – Public Draft 3-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 63 of 729
Chapter 3 - Energy Efficiency
2009 Electric IRP3-6 Avista Corp
Chapter 3–Energy Efficiency
possibility. Since the Load Management Roadmap was developed, a program manager
was added to evaluate load management. As part of this effort, a two year pilot of end-
use control technology as well as customer acceptance was launched. This pilot will be
completed on December 31, 2009. The Company will report on the pilot results in the 2011 IRP.
Analytics
Identification of cost-effective energy efficiency through traditional conservation or
distribution efficiencies, as well as demand response, is dependent upon a technically sound and transparent analytical approach. Representatives from several departments
developed concepts for resource evaluation of six resource value categories. Four of
these values are part of a total avoided cost of energy usage while the remaining two
values represent reductions in system coincident peak. Components included in the avoided cost of energy are commodity cost of energy, avoidance of carbon emissions, reducing retail rate volatility, and transmission and distribution system loss reduction.
The value of system coincident peak capacity includes deferring future investments in
generation capacity and transmission and distribution.
Transmission and Distribution
Avista completed a comprehensive assessment of the available cost-effective electric
efficiency opportunities. This is always a factor in the completion of all IRP efforts given,
but it is significantly increased. Further evaluation of these efficiency opportunities
continue past the IRP processes. Avista evaluates energy-efficiency potential for the IRP in a manner that can augment the conservation business planning process and
ultimately lead to appropriate revisions in efficiency acquisition operations.
Consistency between the IRP Evaluation and Conservation Operations
Avista evaluates energy-efficiency potential for the IRP in a manner that can augment the conservation business planning process and ultimately lead to appropriate revisions
in conservation acquisition operations.
Avista utilizes the IRP process to comprehensively reevaluate the conservation market. This assessment evaluates individual technologies (generally prescriptive programs) where possible as well as program potential when a technology approach is infeasible.
The evaluation assesses resource characteristics and constructs a conservation supply
curve using the levelized total resource cost (TRC) and acquirable resource potential for each technology. Cost-effective technologies, compared to the defined avoided cost, are incorporated into the IRP acquisition target.
Further detailed program evaluation is applied when technologies in the program cannot
be defined to permit their individual evaluation. This is the case in the Company’s comprehensive limited income program, a portion of the non-residential site specific programs and the cooperative regional programs. The target acquisition for these
programs is based on the modification of the historical baseline for known or likely
changes in the market. This includes but is not necessarily limited to modifying the baseline for price elasticity and load growth.
Avista Corp 2009 Electric IRP – Public Draft 3-6
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 64 of 729
2009 Electric IRPAvista Corp 3-7
Chapter 3 - Energy EfficiencyChapter 3–Energy Efficiency
Evaluation of Efficiency Technology Opportunities
The Regional Technical Forum (RTF) periodically surveys Pacific Northwest utilities and
evaluates the amount of remaining conservation potential in the region. The Company used the results of these efforts as the starting point for evaluating different types of
conservation technologies. Approximately 3,000 efficiency concepts were evaluated by
Avista’s staff using a six-stage review process. The process began with concepts using
easily obtained data and moved toward more technically rigorous analyses. Measures that ranked poorly on the initial review did not receive further consideration. The individual phases of the analytical process are as follows.
Defining: Refinement and redefinition of the concept list to eliminate duplicative concepts and develop common definitions.
Qualitative ranking: The refined concepts were ranked based on a qualitative feasibility assessment. Concepts determined to not be acquirable through utility intervention were eliminated from further consideration.
Defining cost characteristics: Concepts with a reasonable potential for incorporation in the conservation portfolio were evaluated based on preliminary assessments of cost-
effectiveness. This step required estimates of incremental customer cost, non-energy
benefits, energy savings and measure life to develop a TRC levelized cost. Concepts
were sorted based upon these cost characteristics.
Defining resource potential: Acquirable potentials for concepts specific to Avista’s
customers were estimated for the remaining concepts. These acquirable potentials
came from an evaluation of technical and economic potential adjusted for utility intervention limitations to address barriers to customer adoption regardless of the
economics.
Identifying load profiles: The value of capacity contribution (transmission, distribution and generation) is also included for evaluation of the total avoided cost. The Company
based the avoided cost of energy on a 20-year, 8,760-hour avoided cost matrix. A 70-
year avoided cost projection was also developed to account for the longevity of some measures. This avoided cost structure made it necessary to develop an 8,760-hour load profile for each evaluated measure. Avista uses thirty-three residential and non-
residential load profiles in this part of the exercise. Appendix C contains a list of the load
profiles used in this analysis.
Calculating TRC cost-effectiveness: A full TRC cost-effectiveness evaluation was
performed on the remaining 706 residential and 2,484 non-residential concepts. The
following section provides a more detailed explanation of the review of these concepts. A summary list of concepts reaching the evaluation stage is included in Appendix D.
Evaluation of TRC Cost-Effectiveness for Finalist Concepts
The construction of the TRC cost for each measure was based on the incremental
customer cost. Non-energy benefits were considered, but none of the evaluated measures had a large enough non-energy benefit to materially change the final cost-effectiveness evaluation.
Estimating the TRC values is an intrinsically quantitative process. This required a present value calculation of the avoided energy and capacity cost over the measure life
Avista Corp 2009 Electric IRP – Public Draft 3-7
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 65 of 729
Chapter 3 - Energy Efficiency
2009 Electric IRP3-8 Avista Corp
Chapter 3–Energy Efficiency
for each concept. The avoided cost of energy was based upon an application of the
measure’s 8,760-hour load profile to the 8,760-hour avoided cost structure.
For purposes of measure evaluation, it was appropriate to focus upon deferring a
summer space-cooling-driven load. The 3,190 evaluated concepts had significant
differences in their impact upon system coincident load and these differences were not
always apparent based upon the general pattern of the measure load shape. To determine the expected impact upon the deemed space cooling-driven system peak load the 3,190 concepts and 33 load shapes (including a flat load option) were
categorized into three groups.
Zero impact: Measures that would not have any impact on a summer space-cooling-
driven peak received a zero valuation regardless of their load profile. This includes
measures such as residential space-heating efficiencies.
Non-Drivers: Measures that were not related to space cooling but would potentially
contribute to system load during a space cooling-driven peak received a capacity
valuation based upon the average demand of their specific load profile during eight hour
summer peak load period. The eight peak hours were 1 pm to 8 pm, weekdays only, between June 15 and September 15. These measures include commercial lighting and
residential appliances.
Drivers: Measures that would drive a space cooling peak received a capacity valuation based on the maximum hourly demand identified in their 8,760-hour load profile. This
includes measures such as residential and non-residential air conditioning efficiency.
A TRC ratio was developed after the TRC cost and benefit calculations were completed.
Even though this analysis limits the identification of future DSM acquisition to measures
that fully pass the TRC cost-effectiveness test, the Company plans on evaluating all
measures with a benefit-to-cost ratio of 0.75 or higher in order to provide a fair evaluation of the marginally failing measures.
Having identified TRC cost-effective measures, the next step determined the annual acquisition of the identified potential. This completed the evaluation of those concepts that were suitable for review by groups of technology types within the IRP. These
results are revisited following the explanation of the programmatically reviewed
elements of the DSM portfolio.
Evaluation of Comprehensive Program Elements
The all-inclusive nature of Avista’s non-residential site specific and limited income
portfolios make it infeasible to generically evaluate the entire spectrum of possible
efficiency measures. Nevertheless, it is necessary to develop estimates for the potential
of these markets in order to establish a meaningful business planning process. Unique efficiency measures could not be generically evaluated as individual technologies. In place of this approach, the Company established a historical baseline level of
acquisition and modified it to incorporate the impact of known or likely changes in the
market.
The Company’s limited income portfolio is all-inclusive for qualifying efficiency
measures. The portfolio is implemented in cooperation with community action agencies
that are given wide latitude in their approach to distributing program funds. No changes
Avista Corp 2009 Electric IRP – Public Draft 3-8
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 66 of 729
2009 Electric IRPAvista Corp 3-9
Chapter 3 - Energy EfficiencyChapter 3–Energy Efficiency
were expected in the ability of agency infrastructure to deliver these programs, and
there were not any known market or technology changes that would cause a significant
change in the ability to obtain efficiency resources from this segment. It was determined
that a historical baseline would be the most appropriate starting point for estimating future throughput. The economic stimulus funding from the ARRA for low income
weatherization was unknown at the time this analysis was completed. There may be
material increases in the low income population served by the economic stimulus
funding. Analysis funding impacts will be treated as an Action Item for reporting in the 2011 IRP. This historical baseline was modified for load growth and retail price elasticity based upon assumptions consistent with the forecasts available at the time. This
resulted in a forecast of limited income acquisition for incorporation into the final
conservation forecast.
Although some of the measures incorporated into the site-specific program were
specifically evaluated, a large portion of non-residential acquisition comes from
measures which could not be generically evaluated. As with the limited income
program, the historical baseline was modified for anticipated load growth and retail price elasticity to develop a forecast. Unlike the limited income program, it was necessary to separate the specifically evaluated measures from the historical baseline, and then
combine the two again as part of the final expected conservation acquisition. This
process is illustrated in a flowchart in Appendix E.
Technical Potential
Every five years, the NPCC develops a regional Power Plan that evaluates technically
available conservation potential. This amount is reduced to reflect the fraction of
measures that can never be practically achieved, even if the measures were free and
cost-effective. The Council believes this practically achievable conservation potential can reach penetration levels of 85 percent over the next twenty years.
The Sixth Power Plan is currently being drafted and will not be completed until after
submission of the 2009 IRP, however, the Council’s most recent draft plan estimates Avista’s portion of the regional target to be 329 aMW for the twenty year period. This is an early estimate but should be within 10 to 15 percent of the final regional technical
potential per the Council’s Sixth Power Plan.
The Company’s last external study on our energy savings potential was done in 2005.As an action item, Avista is committing to updating our estimates through another third-
party savings potential study. We anticipate this study will cover all states and fuels
intended to be used in the preparation of the 2011 IRP.
The Council only provides targets at a higher, utility level. Our measures along with their acquirable potential are illustrated in Appendix F.
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R. Lafferty, Avista
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2009 Electric IRP3-10 Avista Corp
Chapter 3–Energy Efficiency
Compilation of the Final DSM Resource Estimates
The following conservation targets were developed by summing individually evaluated concepts and the evaluated programs over a 20-year period. The first two years of the targets are detailed in Table 3.1. Transmission and Distribution efficiency improvements
are covered in Chapter 5.
Table 3.1: Current Avista Energy Efficiency Programs
Portfolio 2010 Target 2011 Target
Limited Income Residential 1,977,099 2,056,183
Residential 20,518,584 21,339,327
Prescriptive Non-Residential 18,211,396 18,939,852
Site-Specific Non-Residential 24,936,765 25,934,236
Total Local Acquisition (kWh) 65,643,844 68,269,598
Local 7.5 7.8
Regional 2.9 2.9
Total before Distribution Efficiencies (aMW)10.4 10.7
Estimated NPCC Sixth Plan Goal (aMW) 11.2 12.4
A graphical representation of the annual conservation targets for the full 20-year horizon is illustrated in Figure 3.3. A flat annual 2.94 aMW estimate of Avista’s share of regional resource acquisition (Avista’s pro-rated share of NEEA’s annual savings) is included in
the estimate. In the absence of reliable 20-year estimates of regional program
acquisition, it was assumed that historic acquisition levels would remain flat at their most recent anticipated level. This assumption is speculative and dependent on the opportunities for regional market transformation during this period, but is consistent with
the recent history of flat NEAA funding.
Avista Corp 2009 Electric IRP – Public Draft 3-10
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R. Lafferty, Avista
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Figure 3.2: Forecast of Conservation Acquisition
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A measure-by-measure stacking of the 845 evaluated concepts, in ascending order of levelized TRC, leads to a traditional upward-sloping supply curve for this component of
the conservation target, as illustrated in Figure 3.3. Supply curves for 2010 and 2011
have been shown to represent the two years before the next IRP. The rightward shift of
the supply curve over time is a consequence of the assumption that lower cost measures will be less available in subsequent years due to early adoption thereby causing movement up the supply curve.
Since there is a gap in the cost of energy efficiency measures, the measures with a very high total resource cost cause a rapid sloping of the supply curve. Therefore, measures with a total resource cost in excess of $0.50 per kwh have not been included in Figure 3.3
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Figure 3.3: Supply of Evaluated Conservation Measures (Levelized TRC Cost)
annual GWH acquisition
Integrating IRP Results into the Business Planning Process
The IRP evaluation process provides a high-level estimate of cost-effective
conservation acquisition. Avista uses the results of the IRP evaluation to establish a budget for conservation measures, determine the size and skill sets necessary for future conservation operations, and identify general target markets for programs. However, the
results are not detailed enough to become an operational conservation business plan.
The results of the IRP analysis establish baseline goals for continued development and
enhancement of Avista’s conservation programs. The near-term conservation business planning is summarized by portfolio in the following sections.
Residential Portfolio
A review of residential program concepts and sensitivity to key assumptions indicate
that more detailed assumptions based on actual program plans and target markets may improve the cost-effectiveness of many of the residential concepts that marginally failed in this analysis. To account for this marginal failure rate, all concepts with TRC benefit-
to-cost ratios of 0.75 or better are evaluated as part of the business planning process.
Over 62 percent (443 out of 706) of the evaluated residential concepts met the criteria. Measures unavailable for the IRP evaluation will be inserted into a reevaluation process for possible inclusion in the Business Plan.
Limited Income Residential Portfolio
Avista is committed to maintaining stable funding and maintaining program flexibility for limited income conservation programs. There are six local community action partner (CAP) agencies the Company funds to deliver limited income weatherization and energy
efficiency programs. Five of the funded agencies offer electric efficiency measures. CAP
agency funding is currently set at $1,972,000 million per year ($490,000 to Idaho and
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Chapter 3 - Energy EfficiencyChapter 3–Energy Efficiency
$1,482,000 to Washington). Limited income programs include infiltration, insulation,
Energy Star approved windows, doors and refrigerators, space and water heating upgrades, and electric to natural gas space and water heating conversions. CAP agencies can offer other cost-effective programs with Avista’s approval. These
programs require periodic updates because of changes in fuel focus and target
measures. The Company is quantifying potential impacts of the three-year Northwest Sustainable Energy for Economic Development project.
Non-Residential Portfolio
There is sufficient uncertainty and potential for improvement in evaluated non-
residential program concepts to warrant regular reevaluations to ensure they retain a minimum TRC cost-to-benefit ratio of 0.75 based on refined program planning assumptions. Ninety four percent (2,337) of the 2,484 non-residential concepts
evaluated for the IRP meet the TRC criteria. The programs will be reviewed for target
marketing, the creation of a prescriptive program, or for targeting under a site-specific
program.
All electric-efficiency measures with a simple payback exceeding one year automatically
qualify for the non-residential portfolio. The IRP provides account executives, program managers and end-use engineers with valuable information regarding potentially cost-effective target markets. However, the unique and specific characteristics of a
customer’s facility override any high-level program prioritization.
Demand Response
The Idaho Public Utilities Commission approved a residential demand response pilot launched in July 2007. Smart thermostats and direct control unit (DCU) switches for
water heaters, as well as compressors for heat pumps or air conditioners, were selected
for this pilot. Seventy-two customers participated in the Sandpoint and Moscow area
projects. Two demand response events were called during 2008 and three demand response events were called during the winter of 2008-2009. This pilot is scheduled to
continue through December 31, 2009. The Company anticipates calling two to three
additional summer events and two to three more winter events before the end of this
pilot. Test results were not available in time for the 2009 IRP.
Summary
The IRP evaluation process assists the Company in developing a conservation business plan and meeting regulatory requirements. Avista uses this opportunity for
comprehensive evaluation as an integral part of the ongoing management of Avista’s
conservation portfolio. The acquisition targets provide valuable information for future budgetary, staffing and resource planning needs. However, numerical targets do not displace the Company’s fundamental obligation to pursue a resource strategy that best
meets customer needs under a continually changing environment. The efficiency targets
established in this IRP planning process may be modified as necessary to meet these
evolving obligations.
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R. Lafferty, Avista
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2009 Electric IRPAvista Corp 4-1
Chapter 4 - Environmental PolicyChapter 4–Environmental Policy
4. Environmental Policy
Environmental policy often means different things to different stakeholders. The 2007
IRP included a chapter on emissions that focused on legislation and regulations
concerning sulfur dioxide, nitrogen oxide, mercury, and carbon dioxide (CO2); including
modeling assumptions used for each emission type. With the exception of CO2, current regulatory environment diminishes the need for a specific discussion of other emissions in this chapter. Current Washington laws, specifically an emissions performance
standard, effectively forbid the addition of new coal plants in the Preferred Resource
Strategy, and mercury controls have been added to the Company’s coal projects located in Colstrip, Montana. This chapter is dedicated to a discussion of the two most important areas of environmentally related legislation: renewable portfolio standards
and the regulation of greenhouse gases.
Environmental Concerns
Greenhouse gas emissions present a resource planning challenge because of continuously evolving legislative developments resulting in ever-changing projections of the scope and costs of a carbon allocation market. If environmental concerns were the
only issue faced by utilities, resource planning would be reduced to choosing the
required amount and type of renewable generating technology to use. However, utility
planning is compounded by the need to maintain system reliability, acquire least cost resources, mitigate price volatility, meet renewable generation requirements and satisfy future greenhouse gas emissions constraints. Each generating resource also has
distinctive operating characteristics, cost structures and environmental challenges.
Traditional generation technologies are financially and operationally well understood. For example, coal-fired units have high capital costs, long lead times, and relatively low and stable fuel costs. They are difficult to site because of state laws, local opposition
and environmental issues ranging from mercury to greenhouse gas emissions. There
are also problems with the remote locations of coal mines or the high cost of
transporting coal. Natural gas-fired plants have relatively low capital costs, can be located closer to load centers than coal plants, can be constructed in a relatively short time frame, and have much lower emission levels than traditional coal-fired
technologies, but they are affected by high fuel price volatility.
Chapter Highlights
• Avista supports national greenhouse gas legislation that is workable, cost
effective, fair, protects the economy, supports technological innovation, and
addresses emissions from developing nations.
• The Company is a member of the Clean Energy Group.
• The Company is gaining experience in trading carbon credits through its membership in the Chicago Climate Exchange.
• Avista’s Climate Change Committee monitors emissions legislation and
issues.
• Avista participates in the annual Carbon Disclosure Project.
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Renewable energy technologies such as
wind, biomass, and solar have different
challenges. Renewable resources are attractive because they have low or no fuel costs and low or no emissions. But,
they provide limited on-peak capacity,
present integration challenges and have
high upfront capital costs. Similar to coal plants, renewable resource projects are usually located where their fuel source is
most abundant. Remote locations may
require significant investment in transmission interconnection and capacity expansion, as well as resolution of possible wildlife and aesthetic concerns. Unlike coal or natural gas-fired plants, the fuel for non-
biomass renewable resources cannot be transported from one location to another to
better utilize existing transmission facilities or minimize opposition to project
development. Biomass facilities can be particularly challenged because of their dependence on the health of the forest products industry and access to biomass materials located in publicly-owned forests.
Furthermore, the long-term economic viability of renewable resources is uncertain for at least two important reasons. First, federal investment and production tax credits are
scheduled to expire within the planning horizon of this IRP and their continuation cannot
be relied upon in light of the impact such subsidies have on the finances of the federal
government and the relative maturity of wind technology development. Second, the cost of renewable technologies is affected by many relatively unpredictable factors, including renewable portfolio standard mandates, material prices and currency exchange rates.
There is still a great deal of uncertainty regarding greenhouse gas emissions regulation. There continues to be strong regional and national support for addressing climate
change. Since the publication of the 2007 IRP, many changes in the approach and
potential for actual greenhouse gas emissions regulation have occurred, including:
ƒ Different and changing federal legislative proposals: Lieberman-Warner, Dingell-
Boucher, and now Waxman-Markey;
ƒ Leadership changes at the federal level leading to a determination to address
climate change. The election of President Obama and the commitment of
Congressional leaders to enact climate change legislation in the near-term.
ƒ Passage of H.R. 2454, the American Clean Energy and Security Act;
ƒ Joining RPS and greenhouse gas issues under the Waxman-Markey legislation;
and
ƒ Developments in climate change legislation in jurisdictions such as Washington
and Oregon.
Avista Corp 2009 Electric IRP – Public Draft 4-2
Newly installed solar panels at Avista’s headquarters
in Spokane, Washington
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Chapter 4 - Environmental PolicyChapter 4–Environmental Policy
Climate Change Policy Efforts
Avista’s Climate Change Committee (CCC) was chartered as an internal clearinghouse
for all matters related to climate change. In regards to climate change, the CCC:
ƒ Anticipates and evaluates strategic needs and opportunities relating to climate
change;
ƒ Analyzes the company-wide implications of various trends and proposals;
ƒ Develops recommendations on positions and action plans; and
ƒ Facilitates internal and external communications regarding climate change
issues.
The core team of the CCC includes members from Environmental Affairs, Government
Relations, Corporate Communications, Engineering, Energy Solutions, and Resource
Planning. Other areas of the Company are invited as needed. The monthly meetings for this group include work divided into immediate and long term concerns. The immediate
concerns include reviewing and analyzing state and federal legislation, reviewing
corporate climate change policy, and responding to internal and external data requests.
Longer term issues involve emissions tracking and certification, providing recommendations for greenhouse gas reduction goals and activities, evaluating the merits of different reduction programs, actively participating in the development of
legislation, and benchmarking climate change policies and activities against other
organizations.
Avista has maintained its membership in the Clean Energy Group which includes
Calpine, Entergy, Exelon, Florida Power and Light, Pacific Gas & Electric and Public
Service Energy Group. This group collectively evaluates and supports different greenhouse gas legislation such as H.R. 2454, the American Clean Energy and Security Act of 2009, submitted by Congressmen Henry A. Waxman and Edward J.
Markey and narrowly passed in June 2009. This legislation aims to combine RPS,
greenhouse gas and energy efficiency issues under a single bill. Avista also participates
in hydro and biomass issues through its membership in national hydroelectric and biomass associations.
Avista’s Position on Climate Change Legislation
Avista expects comprehensive federal greenhouse gas legislation to be enacted within
the next two to three years. This is slightly longer than projected in the 2007 IRP, primarily because of issues involving the current recession taking up legislative time.
The current lack of definitive legislation makes for an uncertain environment as Avista
plans to meet future customer loads. Avista does not have a preferred form of
greenhouse gas legislation at this time, but supports federal legislation that is:
ƒ Workable and cost effective;
ƒ Fair;
ƒ Protective of the economy and consumers;
ƒ Supportive of technological innovation; and
ƒ Includes emissions from developing nations.
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Chapter 4–Environmental Policy
Workable and cost effective legislation would be carefully crafted to produce actual
greenhouse gas reductions through a single system, as opposed to competing, if not
conflicting, state, regional and federal systems. The legislation also needs to be fair in that its impacts must be equitably distributed across all sectors of the economy based
on relative contribution to greenhouse gas emissions. Protecting the economy and
consumers is of utmost importance. The legislation cannot be so onerous that it stalls
the economy or fails to have any sort of adjustment mechanism in case the market solution fails causing allowance or offset prices to escalate at unmanageable rates. Supporting a wide variety of technological innovations should be a key component of
any greenhouse gas reduction legislation because innovation can help contain costs,
as well as provide a potential boost to the economy through an increased
manufacturing base. Climate change legislation must involve developing nations with increasing greenhouse gas emissions; legislation should include strategies for working
with other nations directly or through international bodies to control global emissions.
Greenhouse Gas Concerns for Resource Planning
Resource planning, in the context of greenhouse gas emissions regulation, raises
concerns about the balance between the Company’s obligations for environmental stewardship and cost implications for our customers. Consideration must be given to the
cost effectiveness of resource decisions as well as the need to mitigate the financial
impact of emissions risks.
Complying with greenhouse gas emission regulations, particularly in the form of a cap
and trade mechanism, involves two actions: ensuring the Company maintains sufficient
allowances and/or offsets to correspond with its emissions during a compliance period,
and undertaking measures to reduce the Company’s future emissions. Effectuating emission reductions on a utility-wide basis can entail any and all of the following:
ƒ Increasing efficiency of existing fossil-fueled generation resources;
ƒ Reducing emissions from existing fossil-fueled generation through fuel
displacement including co-firing with biomass or biofuels;
ƒ Permanently decreasing output from existing fossil-fueled resources and
substituting them with lower emitting resources;
ƒ Decommissioning or divesting fossil-fueled generation and substituting lower
emitting resources;
ƒ Reducing exposure to market purchases of fossil-fueled generation, particularly
during periods of diminished hydropower production, by establishing larger
reserves based on lower emitting technologies; and
ƒ Increasing investments in energy efficiency measures.
With the exception of increasing Avista’s commitment to energy efficiency, the cost and
risks of the other actions listed above cannot be adequately, let alone fully, evaluated until uncertainty about the nature of greenhouse gas emission regulations is resolved; that is, after a regulatory regime has been implemented and the economic effects of its
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Chapter 4 - Environmental PolicyChapter 4–Environmental Policy
interacting components can be modeled. A specific reduction strategy as part of an IRP
may be forthcoming when greater regulatory clarity and more precise modeling
parameters exist. In the meantime, the model for this IRP internalizes a carbon price
proxy based on the Wood Mackenzie forecast based on the November 2008 discussion draft legislation sponsored by Representatives John Dingell and Rick Boucher. The
2009 IRP focuses on the costs and mitigation of carbon dioxide since it is the most
prevalent and primary greenhouse gas emitted from fossil-fueled generation sources.
Emissions Legislation
Several themes have emerged from various climate change legislative proposals that
have been considered since publication of the 2007 IRP. These include:
ƒ Settling of scientific questions about human contributions to climate change; it is viewed as a largely anthropogenic or human-developed phenomenon.
ƒ A consensus view that regulation should be applied on an economy-wide basis, rather than one or two sectors at a time.
ƒ Technology will be a key component to reducing overall greenhouse gas emissions, particularly in the electric sector. Significant investment in carbon capture and sequestration technology will be needed since coal will continue to
be an important part of the U.S. generation fleet into the foreseeable future.
ƒ Developing countries must be involved in reducing global emissions as
greenhouse gas emissions generally increase with economic growth.
ƒ The longer federal legislation takes to enact, the higher the probability of that inconsistent state and regional regulatory schemes may be implemented. A
patchwork of regulation may obstruct the operation of businesses serving
multiple jurisdictions by causing market disruptions and increasing the
uncertainty of how federal and disparate state and regional regulatory systems might interact.
These themes all point towards a need to develop national greenhouse gas legislation in a timely manner to ensure the best environmental and economic outcomes. The current version of the Waxman-Markey bill importantly acknowledges these multi-
jurisdiction problems by temporarily superseding state and regional cap and trade
regulation over emissions covered under federal law between 2012 and 2017.
Federal Emissions and Renewables Legislation
The U.S. House of Representatives passed H.R. 2454, the American Clean Energy and
Security Act by Waxman and Markey on June 26, 2009. Among its many components,
this bill establishes greenhouse gas reduction goals, creates a national cap-and-trade program, and outlines a national RPS. Some of the bill’s details include:
ƒ RPS goals start at six percent in 2012 and increase to 20 percent by 2020.
ƒ Recognizes hydroelectric efficiency upgrades and additions effectuated since
January 1, 1992 as qualifying against the renewable energy standard.
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ƒ Removes existing hydroelectric power generation, excluding upgrades made
after January 1, 1992, from the load base against which the renewable energy
standard is applied.
ƒ Allows electric utilities to make $25 per MWh alternative compliance payments,
adjusted for inflation starting in 2010, in lieu of acquiring new renewable
resources or renewable energy certificates (REC).
ƒ Permits REC trading, and banking of RECs for three years.
ƒ Greenhouse gas reduction goals of 3 percent below 2005 levels by 2012, 17
percent by 2020, 42 percent by 2030 and 83 percent by 2005.
ƒ Proposes to administratively allocate allowances to electric utilities from 2011 through 2028, with 50 percent of them being allocated on the basis of a utility’s
share of emissions associated with retail sales and 50 percent being allocated
based on a utility’s annual average electricity deliveries.
ƒ Calculates a utility’s average annual emissions based upon data from 2006
through 2008, or any three consecutive calendar years between 1999 and 2008,
as may be selected by the utility.
ƒ Allows banking and borrowing of emission allowances.
ƒ Allows for some forms of carbon offsets.
ƒ Establishes mechanisms for containing costs and for regulating allowance and derivative markets.
Jeff Bingaman is also developing a federal RPS bill that is working its way through the
Senate. The Bingaman bill sets a 15 percent renewable energy goal by 2021 and allows
electric utilities to meet up to four percent of their RPS goals with energy efficiency. The bill also creates an off ramp provision exempting a utility from the RPS if their retail rates would increase by four or more percent in any given year for complying with the
law.
Avista’s main concerns with the potential federal climate change legislation concerns
the compliance costs, which centers primarily, though not exclusively, on the method of
allocating allowances and the amount of allowances the Company may be required to
purchase through auction. Avista favors the adoption of a compromise advocated by the Edison Electric Institute, which allows for half of the allowances allocated to electric utilities to be load based and half of the allowances to be emissions based. This is a
more equitable compromise than allocation based solely on historic emissions, which
could provide a windfall for non-utility generators for their past greenhouse gas emissions and effectively penalizes past use of renewable energy. Administrative or direct allocation, at least in the beginning of the program, is also favored because it will
mitigate compliance cost impacts on customers while the allowance markets and
emissions reductions technologies are developed.
State Level Emissions Legislation
The failure of the federal government to enact greenhouse gas emission regulations
during the current decade has encouraged many states to develop their own climate
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change laws and regulations. Climate change legislation can take many forms, including
comprehensive regulation in the form of a cap and trade system, and complementary
policies, such as renewable portfolio standards, energy efficiency standards, and
emission performance standards. All of these standards are included for Washington, but not necessarily in other jurisdictions where Avista operates. Individual state actions
can produce a patchwork of competing rules and regulations for utilities to follow, which
may be particularly problematic for multi-jurisdictional utilities such as Avista. There are
currently 23 states plus the District of Columbia with active renewable portfolio standards.
One of the more notable state level greenhouse gas initiatives outside of the Pacific
Northwest is the Regional Greenhouse Gas Initiative (RGGI) agreement between ten
northeastern and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island, and Vermont)
to implement a cap and trade program for carbon dioxide emissions from power plants.
The District of Columbia, Pennsylvania, and some Canadian Provinces are also
participating as RGGI observers. RGGI’s cap and trade regulations have been effective since January, 2009.
The Western Regional Climate Action Initiative, otherwise known as the Western
Climate Initiative (WCI), began with a February 26, 2007 agreement to reduce greenhouse gas emissions through a regional reduction goal and market-based trading
system. This group includes Arizona, British Columbia, California, Manitoba, Montana,
New Mexico, Oregon, Utah, Quebec and Washington. In September 2008, the WCI
released a set of Final Design recommendations for a regional cap and trade regulatory system to cover 90 percent of the societal greenhouse gas emissions within the region by 2015. The WCI is presently proceeding to finish its Work Plan, which completes
details necessary to implement its proposed cap and trade system. The WCI has also
recently initiated a process to identify and evaluate complementary policies that can be adopted region-wide to further ensure that greenhouse gas reduction goals are met. In addition, the WCI has formally submitted comments to Congress regarding the content
of the Waxman-Markey bill. There have also been a number of regional municipalities
participating in the U.S. Mayors Climate Protection Agreement to reduce GHG
emissions to seven percent below 1990 levels by 2012.
It is important to acknowledge that a federal cap and trade program, such as that
envisioned by the Waxman-Markey legislation, will not operate in isolation. Members of
the Western Climate Initiative, such as Washington, Oregon, and Montana, are likely to – as some of them have already – pursue complementary policies to regulate emission sources that are covered under cap and trade regulation, as well as those that will not
be regulated under a cap and trade program. The Waxman-Markey bill in its current
form illustrates this potentiality. Even though the federal legislation would preclude
states from implementing their own cap and trade regulations between 2012 and 2017, it would not prevent states from imposing any different form of regulations on the covered sources before, during or after that time frame, or from administering and
augmenting federal cap and trade regulations after 2017.
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2009 Electric IRP4-8 Avista Corp
Chapter 4–Environmental Policy
The adoption of greenhouse gas emission reduction goals, and any associated
regulations by Washington, could directly impact the Company’s generation assets in
the state, which are largely comprised of the Kettle Falls Generating Station, the
Northeast Combustion turbines and the Boulder Park peaking facilities. Oregon’s greenhouse gas reduction goals and potential future regulations can be applied to the
Coyote Springs 2 project.
Idaho Emissions Legislation
Idaho is not a member of WCI and does not regulate greenhouse gases or have an RPS. However, the state is actively trying to promote the development of local
renewable energy.
Montana Emissions Legislation
The Montana Global Warming Solutions Act (House Bill 753) was submitted in late 2006 to establish greenhouse gas reductions goals to be achieved by 2020. This legislation
did not leave committee. Montana now has a non-statutory goal of reducing greenhouse
gas emissions to 1990 levels by 2020. In 2007, the Legislature passed House Bill 25,
requiring new coal-fired facilities built in the state to sequester 50 percent of their emissions. Montana’s renewable portfolio standard law, which was enacted through Senate Bill 415 in 2005, does not apply to Avista because the Company does not serve
retail load in Montana. While involved in the Western Climate Initiative, Montana did not
consider any legislation during the 2009 Legislative Session to authorize its participation
in and implementation of the regional cap and trade system designed by the WCI.
Oregon Emissions Legislation
The State of Oregon has been actively developing legislation concerning greenhouse
gases and renewable portfolio standards. Oregon’s climate change legislation began in
December 2004 when the Oregon Strategy for Greenhouse Gas Reduction called for the development of a detailed GHG report by the end of 2007. That year, the
Legislature enacted House Bill 3543 calling for reductions of greenhouse gas emissions
to 10 percent below 1990 levels by 2020 and 75 percent below 1990 levels by 2050.
These reduction goals are in addition to a 1997 regulation requiring fossil-fueled generation developers to offset the project’s CO2 emissions exceeding 83 percent of the emissions of a state-of-the-art gas-fired CCCT by paying into the Climate Trust of
Oregon. Senate Bill 838 requires large electric utilities to generate 25 percent of annual
electricity sales with qualified renewable resources by 2025. Shorter term goals include five percent by 2011, 15 percent by 2015 and 20 percent by 2020. Governor Ted Kulongoski introduced Senate Bill 80 during the 2009 Legislative Session to authorize
the state’s implementation of cap and trade regulations either in isolation or as part of a
regional program. This legislation failed. Oregon continues to be an active member of
WCI.
Washington Emissions Legislation
The State of Washington has enacted several measures affecting fossil-fueled
generation and the diversification of generation resources. A law was enacted in 2004
that requires new fossil-fueled thermal electric generating facilities of more that 25 MW generation capacity to mitigate CO2 emissions through a plan including: third party
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Chapter 4 - Environmental PolicyChapter 4–Environmental Policy
mitigation, purchased carbon credits or cogeneration. Washington’s Energy
Independence Act (I-937), passed in the November 2006 election, established a
requirement for utilities with over 25,000 customers to use qualified renewable energy
or renewable energy certificates to serve three percent of retail load by 2012, nine percent by 2016 and 15 percent by 2020. Failure to meet the RPS requirements results
in a fine. The initiative also requires utilities to acquire all cost effective conservation and
energy efficiency measures.
Senate Bill 5840 was brought forward in 2009 to update I-937, qualify existing biomass generation (e.g., Kettle Falls) as an eligible renewable resource, and adjust the
renewable energy standards, but it failed to obtain the needed votes after emerging
from Conference Committee in the closing days of the Legislative Session. The
renewable requirement begins in 2012.
Avista is projected to meet or exceed its renewable requirements between 2012 and
2015 through a combination of hydro upgrades and REC purchases. The Company
could bank RECs acquired from the Stateline Wind contract in 2011 for 2012, but these RECs are allocated for its Buck-a-Block program. The 2009 IRP has been developed so that the I-937 RPS goals will be achieved by the Company.
In 2007 the Legislature passed Senate Bill 6001. It prohibits electric utilities from
entering into financial commitments beyond five years for fossil-fueled generation where CO2 emissions exceed 1,100 pounds per MWh. In 2013 the emissions performance
standard will be lowered every five years to reflect the emissions profile of the latest
commercially available CCCT. The emissions performance standard effectively
prevents utilities from developing new coal-fired generation or expanding the generation capacity of existing coal-fired generation, unless they can sequester emissions from the facility. The Legislature amended Senate Bill 6001 in 2009 to prohibit contractual
commitments where more than 12 percent of the total power supplied under the
contract comes from unspecified sources.
Governor Christine Gregoire signed Executive Order 07-02 in February 2007 which
established the following GHG emissions goals:
ƒ 1990 levels by 2020;
ƒ 25 percent below 1990 levels by 2035;
ƒ 50 percent below 1990 levels by 2050 or 75 percent below expected emissions in
2050;
ƒ Increase clean energy jobs to 25,000 by 2020; and
ƒ Reduce statewide fuel imports by 20 percent.
The goals of this Executive Order were later codified into law when the Legislature
enacted Senate Bill 6001 in 2007. Taking the next step to achieve the State’s
greenhouse gas reduction goals, the governor introduced legislation (Senate Bill 5735 and House Bill 1819) during the 2009 Legislative Session to authorize the Department of Ecology to adopt rules, consistent from recommendations from the Western Climate
Initiative, enabling the state to administer and enforce a regional cap and trade
program. When that legislation failed, Governor Gregoire signed Executive Order 09-05
Avista Corp 2009 Electric IRP – Public Draft 4-9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 81 of 729
Chapter 4 - Environmental Policy
2009 Electric IRP4-10 Avista Corp
Chapter 4–Environmental Policy
directing the Department of Ecology to develop emission reduction “strategies and
actions”, including complementary policies, to meet Washington’s 2020 emission
reduction target by October 1, 2010. This directive will require the agency to provide
“each facility that the Department of Ecology believes is responsible for the emission of 25,000 metric tons or more of carbon dioxide equivalent each year in Washington with”
an estimate of each facility’s baseline emissions and to designate “each facility’s
proportionate share of greenhouse gas emission” reductions necessary to achieve the
state’s 2020 emission reduction goal. The department is also asked, by December 1, 2009, to develop emission benchmarks by industry sector for facilities the Department of Ecology believes will be covered by a federal or regional cap and trade program; the
state may advocate the use of these emission benchmarks in any federal or regional
cap and trade program as an appropriate basis for the distribution of emission
allowances. The department must submit recommendations regarding its industry benchmarks and their appropriate use to the Governor by July 1, 2011.
Washington Renewable Portfolio Standard (I-937)
National RPS legislation is being developed through Waxman and Markey’s American
Clean Energy Security Act of 2009 (HR 2454) and Senator Bingaman’s draft RPS bill. The proposed federal RPS level ranges between 10 and 25 percent with several target
years. Federal legislation is expected to include a hydro netting provision, which
excludes loads served by hydropower energy from the RPS requirement. Federal
legislation conceptually – and significantly -- differs from I-937, in particular with respect to hydro-netting. The absence of hydro-netting makes the Washington RPS more stringent than proposed federal requirements. National legislation may count existing
biomass resources, including Kettle Falls, against the renewable energy standard, as
well as power from upgrades to hydropower facilities that were effectuated before 1999
(the date established in I-937 to determine resource eligibility). Treatment of renewable resources in federal legislation would not allow the Company to use RECs from
federally-eligible resources to comply with I-937, but Avista would be able to make REC
sales from certain facilities into a national market and perhaps individual state markets
governed by their own RPS requirements.
Emissions Measurement and Modeling
Greenhouse gas tracking is an important part of the IRP modeling process because
emissions legislation is one of the greatest fundamental risks facing the electricity
marketplace today. Reducing CO2 emissions from power plants will fundamentally alter the resource mix as society moves towards a carbon constrained future. Though there are no federal laws regulating carbon emissions presently, carbon costs still need to be
projected for planning purposes because expectations for carbon regulation can change
resource decisions.
This IRP uses a Wood Mackenzie carbon price forecast. Wood Mackenzie based its
carbon price forecast on November 2008 legislation sponsored by Representatives
Dingell and Boucher. Even though the Dingell-Boucher bill is no longer being considered for federal greenhouse gas legislation, it does provide a reasonable proxy for the current Waxman-Markey bill. Wood Mackenzie balanced its macro-economic
models by identifying a carbon price forecast to meet national greenhouse gas
reduction goals. Figure 4.1 shows the carbon price forecast for this IRP. The 2009 IRP
Avista Corp 2009 Electric IRP – Public Draft 4-10
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 82 of 729
2009 Electric IRPAvista Corp 4-11
Chapter 4 - Environmental PolicyChapter 4–Environmental Policy
assumes carbon will have a cost starting in 2012. The levelized cost of carbon is $46.14
(nominal) and $33.37 (2009 dollars). Natural gas prices greatly affect carbon offset
values. Therefore, when natural gas prices rise or fall, the IRP assumes carbon costs
will change to balance the relative competitiveness of gas and coal.
Figure 4.1: Price of Carbon Dioxide Credits
$0
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Avista Corp 2009 Electric IRP – Public Draft 4-11
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 83 of 729
Chapter 5 – Transmission & Distribution 5. Transmission and Distribution IntroductionThis section of the Integrated Resource Plan (IRP) provides an overview of Avista’s transmission system, recently completed and planned upgrades, transmission planning issues, and estimated costs and issues involved with integrating potential resources into the transmission system. Coordinating transmission system operations and planning activities among regional transmission providers is necessary to maintain reliable and economic service for Avista’s customers. Transmission providers and interested stakeholders continue to implement changes in the region’s approach to planning, constructing and operating the transmission system under new rules promulgated by the Federal Energy Regulatory Commission (FERC) and under
state and local siting agencies. This section was developed in full compliance with
Avista’s FERC Standards of Conduct governing communications between Avista
merchant and transmission functions.
Chapter Highlights
• Avista recently completed a $130 million transmission improvement project.
• The Company has over 2,200 miles of high voltage transmission.
• Avista is actively involved in regional transmission planning efforts.
• The costs of transmission upgrades are included in the 2009 Preferred Resource Strategy.
Avista’s Transmission System
Avista owns and operates approximately 685 miles of 230 kilovolt (kV) and 1,527 miles
of 115 kV transmission lines. Avista also owns an 11 percent interest in 495 miles of the
500 kV line between Colstrip and Townsend, Montana. The transmission system
includes switching stations and high-voltage substations with transformers, monitoring
and metering devices, and other system operation-related equipment. The system
transfers power from Avista’s generation resources to its retail load centers. The
Company also has network interconnections with the following utilities:
Avista Corp 2009 Electric IRP – Public Draft 5-1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 84 of 729
2009 Electric IRPAvista Corp 5-1
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
5. Transmission and Distribution
Introduction
This section of the Integrated Resource Plan
(IRP) provides an overview of Avista’s
transmission system, recently completed and
planned upgrades, transmission planning issues, and estimated costs and issues involved with integrating potential resources
into the transmission system.
Coordinating transmission system operations
and planning activities among regional
transmission providers is necessary to
maintain reliable and economic service for Avista’s customers. Transmission providers and interested stakeholders continue to
implement changes in the region’s approach
to planning, constructing and operating the transmission system under new rules promulgated by the Federal Energy
Regulatory Commission (FERC) and under
state and local siting agencies. This section
was developed in full compliance with Avista’s FERC Standards of Conduct governing communications between Avista
merchant and transmission functions.
Chapter Highlights
• Avista recently completed a $130 million transmission improvement project.
• The Company has over 2,200 miles of high voltage transmission.
• Avista is actively involved in regional transmission planning efforts.
• The costs of transmission upgrades are included in the 2009 Preferred
Resource Strategy.
Avista’s Transmission System
Avista owns and operates approximately 685 miles of 230 kilovolt (kV) and 1,527 miles of 115 kV transmission lines. Avista also owns an 11 percent interest in 495 miles of the
500 kV line between Colstrip and Townsend, Montana. The transmission system
includes switching stations and high-voltage substations with transformers, monitoring and metering devices, and other system operation-related equipment. The system transfers power from Avista’s generation resources to its retail load centers. The
Company also has network interconnections with the following utilities:
Avista Corp 2009 Electric IRP – Public Draft 5-1
Transmission upgrade work
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 85 of 729
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-2 Avista Corp
Chapter 5 – Transmission & Distribution
ƒ Bonneville Power Administration
(BPA)
ƒ Chelan County PUD
ƒ Grant County PUD
ƒ Idaho Power Company
ƒ NorthWestern Energy
ƒ PacifiCorp
ƒ Pend Oreille County PUD
Figure 5.1: Avista transmission system
In addition to providing enhanced transmission system reliability, network interconnections serve as points of receipt for power from generating facilities outside
Avista’s service area. These interconnections also provide for the interchange of power
with entities within and outside of the Pacific Northwest, including the integration of long
and short-term contract resources. Avista also has interconnections with several government-owned and cooperative utilities at transmission and distribution voltage levels, representing non-network radial points of delivery for service to wholesale loads.
Transmission Changes since the 2007 IRP
Avista has completed a multi-year $130 million transmission upgrade project. Much of
this construction was completed prior to 2007 and was documented in the 2007 IRP. Since the 2007 IRP the Company completed 60 miles of new 230 kV transmission between its Benewah and Shawnee substations to increase capacity between the north
and south portions of its system. The project provides a second 230 kV transmission
line between Avista’s northern and southern load service areas, significantly improving
reliability. Energized in December, 2007, Avista installed a new 200 megavolt- ampere-reactive (MVAR) 230 kV capacitor bank at the Benewah station in October of 2008, and
installed a new 125 MVA 230/115 kV transformer in November of 2008. This work,
Avista Corp 2009 Electric IRP – Public Draft 5-2
Chapter 5 – Transmission & Distribution
known as the West of Hatwai reinforcement, was part of a joint transmission project
between Avista and BPA.
Future Upgrades and Interconnections
Station Upgrades
Several station upgrades are planned for the next 10 years. The final scope of station upgrades has not yet been determined, but four of the Company’s 230 kV station upgrades (Noxon, Moscow, Westside and Pine Creek) are slotted for completion within
the next five to 10 years. A number of 115 kV capacitor banks will also be installed at
various substations throughout the Avista transmission system.
South Spokane 230 kV Reinforcement
Recent transmission studies indicate the need for an additional 230 kV line to the south
and west of Spokane. Avista currently has no 230 kV source southwest of the Spokane
area and relies on its 115 kV system for load service as well as bulk power flow through the area. The project scope is currently being defined; however, preliminary studies indicate the need for the following projects:
ƒ New 230/115 kV station near Garden Springs;
ƒ Tap the Benewah-Boulder 230 kV line southwest of the Liberty Lake area and
construct a new 230 kV switching station (for later development of a 230/115 kV
substation);
ƒ Connection of the Liberty Lake 230 kV station with the Garden Springs 230 kV
station;
ƒ New 230 kV line from Garden Springs to Westside; and
ƒ Origination and termination of the 115 kV lines from the Spokane 230/115 kV line.
The final scope for the South Spokane 230 kV Reinforcement project is scheduled for completion by the end of 2009. Its energization date is expected to be 2018, with staged
in-service dates beginning in 2014.
Canada to California Transmission Project and Devils Gap Interconnection
One of the primary projects under review at the Transmission Coordination Work Group (TCWG, see below) is a new transmission line involving four major projects.
ƒ 500 kV HVAC facilities from Selkirk in southeast British Columbia to the
proposed Northeast Oregon (NEO) Station, with an intermediate interconnection with Avista at a new Devils Gap Substation near Spokane;
ƒ 500 kV HVDC facilities from NEO Station to Collinsville Substation in the San
Francisco Bay Area, with a possible third terminal at Cottonwood Area Substation in northern California (DC Segment);
ƒ Voltage support at the interconnecting substations; and
ƒ Remedial actions for project outages.
Avista Corp 2009 Electric IRP – Public Draft 5-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 86 of 729
2009 Electric IRPAvista Corp 5-3
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
ƒ Bonneville Power Administration
(BPA)
ƒ Chelan County PUD
ƒ Grant County PUD
ƒ Idaho Power Company
ƒ NorthWestern Energy
ƒ PacifiCorp
ƒ Pend Oreille County PUD
Figure 5.1: Avista transmission system
In addition to providing enhanced transmission system reliability, network interconnections serve as points of receipt for power from generating facilities outside
Avista’s service area. These interconnections also provide for the interchange of power
with entities within and outside of the Pacific Northwest, including the integration of long
and short-term contract resources. Avista also has interconnections with several government-owned and cooperative utilities at transmission and distribution voltage levels, representing non-network radial points of delivery for service to wholesale loads.
Transmission Changes since the 2007 IRP
Avista has completed a multi-year $130 million transmission upgrade project. Much of
this construction was completed prior to 2007 and was documented in the 2007 IRP. Since the 2007 IRP the Company completed 60 miles of new 230 kV transmission between its Benewah and Shawnee substations to increase capacity between the north
and south portions of its system. The project provides a second 230 kV transmission
line between Avista’s northern and southern load service areas, significantly improving
reliability. Energized in December, 2007, Avista installed a new 200 megavolt- ampere-reactive (MVAR) 230 kV capacitor bank at the Benewah station in October of 2008, and
installed a new 125 MVA 230/115 kV transformer in November of 2008. This work,
Avista Corp 2009 Electric IRP – Public Draft 5-2
Chapter 5 – Transmission & Distribution
known as the West of Hatwai reinforcement, was part of a joint transmission project
between Avista and BPA.
Future Upgrades and Interconnections
Station Upgrades
Several station upgrades are planned for the next 10 years. The final scope of station upgrades has not yet been determined, but four of the Company’s 230 kV station upgrades (Noxon, Moscow, Westside and Pine Creek) are slotted for completion within
the next five to 10 years. A number of 115 kV capacitor banks will also be installed at
various substations throughout the Avista transmission system.
South Spokane 230 kV Reinforcement
Recent transmission studies indicate the need for an additional 230 kV line to the south
and west of Spokane. Avista currently has no 230 kV source southwest of the Spokane
area and relies on its 115 kV system for load service as well as bulk power flow through the area. The project scope is currently being defined; however, preliminary studies indicate the need for the following projects:
ƒ New 230/115 kV station near Garden Springs;
ƒ Tap the Benewah-Boulder 230 kV line southwest of the Liberty Lake area and
construct a new 230 kV switching station (for later development of a 230/115 kV
substation);
ƒ Connection of the Liberty Lake 230 kV station with the Garden Springs 230 kV
station;
ƒ New 230 kV line from Garden Springs to Westside; and
ƒ Origination and termination of the 115 kV lines from the Spokane 230/115 kV line.
The final scope for the South Spokane 230 kV Reinforcement project is scheduled for completion by the end of 2009. Its energization date is expected to be 2018, with staged
in-service dates beginning in 2014.
Canada to California Transmission Project and Devils Gap Interconnection
One of the primary projects under review at the Transmission Coordination Work Group (TCWG, see below) is a new transmission line involving four major projects.
ƒ 500 kV HVAC facilities from Selkirk in southeast British Columbia to the
proposed Northeast Oregon (NEO) Station, with an intermediate interconnection with Avista at a new Devils Gap Substation near Spokane;
ƒ 500 kV HVDC facilities from NEO Station to Collinsville Substation in the San
Francisco Bay Area, with a possible third terminal at Cottonwood Area Substation in northern California (DC Segment);
ƒ Voltage support at the interconnecting substations; and
ƒ Remedial actions for project outages.
Avista Corp 2009 Electric IRP – Public Draft 5-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 87 of 729
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-4 Avista Corp
Chapter 5 – Transmission & Distribution
The proposed north-to-south rating for the two-segment project is 3,000 MW. It will
improve system reliability in the Western Interconnection, as well as provide access to
significant renewable resources. Its target operating date is December 2015. Avista joins Pacific Gas and Electric, PacifiCorp and the British Columbia Transmission
Corporation in this project.
The Avista Devils Gap Interconnection project is comprised of a 500 MW bi-directional 500/230 kV interconnection and 230 kV transmission into the Spokane area 230 kV grid. It (plus additional transmission in the area around the proposed NEO substation)
would provide additional transmission Avista could use to integrate Coyote Springs 2
generation. The Project will allow Avista to enhance its access to incremental renewable
resources in the Pacific Northwest, Canada and, at times, the southwestern U.S. Immediate and future environmental and resource needs of Avista and other Western
Interconnected utilities will be aided by this Project.
Avista’s goal is to also provide market participants with beneficial opportunities to use its facilities. Through its participation in TCWG meetings Avista makes all project information available to group members, including resource developers, load serving
entities, energy marketers and independent transmission owners.
Regional Transmission System
BPA operates over 15,000 miles of transmission facilities throughout the Pacific Northwest. BPA’s system represents a large portion of the region’s high voltage (230 kV or higher) transmission grid. Avista uses the BPA transmission system to transfer output
from its remote generation sources to Avista’s transmission system, including its
Colstrip units, Coyote Springs 2 and its Washington Public Power Supply System
Washington Nuclear Plant No. 3 settlement contract. Avista also contracts with BPA for Network Integration Transmission Service to transfer power to 10 delivery points on the
BPA system to serve portions of the Company’s retail load.
Avista participates in regional and BPA-specific forums to coordinate system reliability issues and manage BPA transmission costs. We participate in BPA transmission and power rate case processes, and in BPA’s Business Practices Technical Forum, to
ensure charges remain reasonable and support system reliability and access. Avista
also works with BPA and other regional utilities to coordinate major transmission facility
outages.
Future generation resource development will require construction of new transmission
assets. BPA recently received $3.5 billion in additional borrowing authority through the
American Recovery and Reinvestment Act of 2009. Increased borrowing capability enhances BPA’s ability to construct new transmission projects. One recent example is the 79-mile long 500 kV McNary-John Day upgrade. This $200 million project had been
on hold since 2002 because of BPA’s inability to finance the project.
Avista Corp 2009 Electric IRP – Public Draft 5-4
Chapter 5 – Transmission & Distribution
FERC Planning Requirements and Processes
FERC provides guidance to regional and local area transmission planning. The
following section describes several requirements and processes important to Avista’s
transmission planning function.
Attachment K
On December 7, 2007, Avista submitted a revised Attachment K to its Open Access
Transmission Tariff (OATT). The revisions to the prior Attachment K met nine
transmission planning principles proposed in FERC Order 890. The principles made the planning process more open to interested stakeholders and formalized coordination between interconnected utilities. In its Attachment K process, Avista established three
levels of planning on the local, sub-regional and regional levels.
At the local level, Avista develops a two-year Local Planning Process culminating with the production of a Local Planning Report (in coordination with Avista's five- and ten-
year Transmission Plans). Avista encourages participation of interconnected neighbors,
transmission customers and other stakeholders in the local planning process. The
Company uses ColumbiaGrid to coordinate planning with sub-regional groups. Regionally, Avista participates in several WECC processes and groups, including
various Regional Review processes, Transmission Expansion Planning Policy
Committee, Planning Coordination Committee and the newly formed Transmission
Coordination Work Group (TCWG). Participation in these efforts supports regional coordination of Avista's transmission projects.
Avista submitted a modified Attachment K to FERC on October 15, 2008 to correct
deficiencies in its 2007 filing. The Attachment K revisions included clarifications that did
not change the substance of the original filing.
Western Electricity Coordinating Council
The Western Electricity Coordinating Council (WECC) coordinates and promotes
electric system reliability in the Western Interconnection. WECC also supports efficient
and competitive power markets, assures open and non-discriminatory transmission access among members, provides a forum for resolving transmission access or
capacity ownership disputes, and provides an environment for coordinating operating
and planning activities as set forth in WECC Bylaws. Avista participates in WECC’s
Planning, Operations, and Market Interface committees, as well as various sub groups and other processes such as the TCWG.
Northwest Power Pool
The Pacific Northwest has a long history of coordinated transmission planning through
Northwest Power Pool (NWPP) workgroups. The NWPP was formed in 1942 when the federal government directed utilities to coordinate operations in support of wartime production. NWPP activities are determined by committees including the Operating
Committee, the PNCA Coordinating Group and the Transmission Planning Committee
(TPC). The TPC, formed in 1990, provides a forum for addressing northwest electric
planning issues and concerns, including a structured interface with outside stakeholders.
Avista Corp 2009 Electric IRP – Public Draft 5-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 88 of 729
2009 Electric IRPAvista Corp 5-5
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
The proposed north-to-south rating for the two-segment project is 3,000 MW. It will
improve system reliability in the Western Interconnection, as well as provide access to
significant renewable resources. Its target operating date is December 2015. Avista joins Pacific Gas and Electric, PacifiCorp and the British Columbia Transmission
Corporation in this project.
The Avista Devils Gap Interconnection project is comprised of a 500 MW bi-directional 500/230 kV interconnection and 230 kV transmission into the Spokane area 230 kV grid. It (plus additional transmission in the area around the proposed NEO substation)
would provide additional transmission Avista could use to integrate Coyote Springs 2
generation. The Project will allow Avista to enhance its access to incremental renewable
resources in the Pacific Northwest, Canada and, at times, the southwestern U.S. Immediate and future environmental and resource needs of Avista and other Western
Interconnected utilities will be aided by this Project.
Avista’s goal is to also provide market participants with beneficial opportunities to use its facilities. Through its participation in TCWG meetings Avista makes all project information available to group members, including resource developers, load serving
entities, energy marketers and independent transmission owners.
Regional Transmission System
BPA operates over 15,000 miles of transmission facilities throughout the Pacific Northwest. BPA’s system represents a large portion of the region’s high voltage (230 kV or higher) transmission grid. Avista uses the BPA transmission system to transfer output
from its remote generation sources to Avista’s transmission system, including its
Colstrip units, Coyote Springs 2 and its Washington Public Power Supply System
Washington Nuclear Plant No. 3 settlement contract. Avista also contracts with BPA for Network Integration Transmission Service to transfer power to 10 delivery points on the
BPA system to serve portions of the Company’s retail load.
Avista participates in regional and BPA-specific forums to coordinate system reliability issues and manage BPA transmission costs. We participate in BPA transmission and power rate case processes, and in BPA’s Business Practices Technical Forum, to
ensure charges remain reasonable and support system reliability and access. Avista
also works with BPA and other regional utilities to coordinate major transmission facility
outages.
Future generation resource development will require construction of new transmission
assets. BPA recently received $3.5 billion in additional borrowing authority through the
American Recovery and Reinvestment Act of 2009. Increased borrowing capability enhances BPA’s ability to construct new transmission projects. One recent example is the 79-mile long 500 kV McNary-John Day upgrade. This $200 million project had been
on hold since 2002 because of BPA’s inability to finance the project.
Avista Corp 2009 Electric IRP – Public Draft 5-4
Chapter 5 – Transmission & Distribution
FERC Planning Requirements and Processes
FERC provides guidance to regional and local area transmission planning. The
following section describes several requirements and processes important to Avista’s
transmission planning function.
Attachment K
On December 7, 2007, Avista submitted a revised Attachment K to its Open Access
Transmission Tariff (OATT). The revisions to the prior Attachment K met nine
transmission planning principles proposed in FERC Order 890. The principles made the planning process more open to interested stakeholders and formalized coordination between interconnected utilities. In its Attachment K process, Avista established three
levels of planning on the local, sub-regional and regional levels.
At the local level, Avista develops a two-year Local Planning Process culminating with the production of a Local Planning Report (in coordination with Avista's five- and ten-
year Transmission Plans). Avista encourages participation of interconnected neighbors,
transmission customers and other stakeholders in the local planning process. The
Company uses ColumbiaGrid to coordinate planning with sub-regional groups. Regionally, Avista participates in several WECC processes and groups, including
various Regional Review processes, Transmission Expansion Planning Policy
Committee, Planning Coordination Committee and the newly formed Transmission
Coordination Work Group (TCWG). Participation in these efforts supports regional coordination of Avista's transmission projects.
Avista submitted a modified Attachment K to FERC on October 15, 2008 to correct
deficiencies in its 2007 filing. The Attachment K revisions included clarifications that did
not change the substance of the original filing.
Western Electricity Coordinating Council
The Western Electricity Coordinating Council (WECC) coordinates and promotes
electric system reliability in the Western Interconnection. WECC also supports efficient
and competitive power markets, assures open and non-discriminatory transmission access among members, provides a forum for resolving transmission access or
capacity ownership disputes, and provides an environment for coordinating operating
and planning activities as set forth in WECC Bylaws. Avista participates in WECC’s
Planning, Operations, and Market Interface committees, as well as various sub groups and other processes such as the TCWG.
Northwest Power Pool
The Pacific Northwest has a long history of coordinated transmission planning through
Northwest Power Pool (NWPP) workgroups. The NWPP was formed in 1942 when the federal government directed utilities to coordinate operations in support of wartime production. NWPP activities are determined by committees including the Operating
Committee, the PNCA Coordinating Group and the Transmission Planning Committee
(TPC). The TPC, formed in 1990, provides a forum for addressing northwest electric
planning issues and concerns, including a structured interface with outside stakeholders.
Avista Corp 2009 Electric IRP – Public Draft 5-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 89 of 729
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-6 Avista Corp
Chapter 5 – Transmission & Distribution
The NWPP serves as a Northwest electricity industry reliability forum. It helps
coordinate present and future industry restructuring. NWPP promotes member
cooperation to achieve reliable system operation, coordinate power system planning and assist transmission planning in the Northwest Interconnected area. NWPP
membership is voluntary and includes major generating utilities serving the
Northwestern U.S., British Columbia and Alberta. Smaller, principally non-generating
utilities, participate indirectly through their member systems.
ColumbiaGrid
ColumbiaGrid was formed on March 31, 2006 to develop sub-regional transmission
plans, assess transmission alternatives (including non-wires alternatives), provide a
decision-making forum, and a cost-allocation methodology for new transmission projects. This group was formed in response to a number of FERC initiatives. Avista joined ColumbiaGrid in early 2007. Other members include BPA, Chelan County PUD,
Grant County PUD, Puget Sound Energy, Seattle City Light and Tacoma Power.
Though not a member, Snohomish PUD participates in a number of functional
agreements. These agreements are used to help different organizations and groups determine areas of transmission work and establish agreements to carry out the plans.
Transmission Coordination Work Group
The TCWG is a joint effort of Avista, BPA, Idaho Power, Pacific Gas and Electric,
PacifiCorp, Portland General Electric, Sea Breeze Pacific-RTS and TransCanada to coordinate transmission project developments expected to interconnect at or near the
proposed NEO station near Boardman, Oregon. These projects are following the WECC
Regional Planning and Project Rating Guidelines. Detailed information on NEO and the
projects that could be integrated at NEO may be found at www.nwpp.org/tcwg .
Avista Transmission Reliability and Operations
Avista plans and operates its transmission system pursuant to applicable criteria
established by the North American Electric Reliability Corporation (NERC), WECC and
the NWPP. Through involvement in WECC and NWPP standing committees and sub-committees, Avista participates in the development of new and revised criteria, and coordinates planning and operation of its transmission system with neighboring
systems. Mandatory reliability standards promulgated through FERC and NERC,
subject Avista to periodic performance audits through these regional organizations. Portions of Avista’s transmission system are fully subscribed for transferring power output of Company generation resources to its retail load centers. Transmission
capacity that is not reserved and scheduled to move power to satisfy long-term (greater
than one year) obligations is marketed on a short-term basis and may be used by Avista
for short-term resource optimization or third parties seeking short-term transmission service pursuant to FERC requirements under Orders 888, 889 and 890.
Transmission Construction Costs
An essential part of the IRP is estimating transmission costs to integrate new generation
resources. Construction-quality estimates were only made for three projects proposed in
the IRP. The other options identified in this IRP are based on engineering judgment.
Avista Corp 2009 Electric IRP – Public Draft 5-6
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 90 of 729
2009 Electric IRPAvista Corp 5-7
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
There is an inverse relationship between transmission project size and the certainty of
the estimates. A 50 MW resource can be integrated in many places on the Company’s
system for a moderate cost compared to its overall installation cost. There are fewer
options available for locating a 500 MW plant on Avista’s system. Larger (750 and 1,000 MW) plants have even fewer location options. Each would require participation in
FERC’s Generation Interconnection Process as well as coordination through the
regional processes described above. These processes would be completed to
determine impacts on Avista and other systems’ transmission grid before a final plant placement decision.
Estimating Transmission and Integration Costs
The following sections provide an overview of Avista’s estimated resource integration
costs for the 2009 IRP. Integration points were roughly divided into locations where
interconnection study work has been completed and additional points where new resources might be interconnected. Rigorous analyses have not been completed for off-system alternatives because of the breadth of study needed for those estimates. Limited
study work has been completed except for projects with existing generation
interconnection requests to Avista’s transmission group. Completing transmission
studies without detailed project parameters is nearly impossible. Approximate worst-case estimates have been assigned based on engineering judgment for neighboring
system impacts. Generation interconnection costs are listed for locations within Avista’s
transmission system. Internal cost estimates are in 2009 dollars and are based on
engineering judgment with a 50 percent margin for error. Construction timelines are defined from the beginning of the permitting process to line energization.
Integration of Resources External to the Avista System
Avista’s load serving entity function (Avista-LSE) is required to submit generation
interconnection and transmission service requests on third party transmission systems. The third party determines transmission system integration and wheeling service costs for delivering new resource power to Avista’s system. Construction cost estimates are
based on $2 million per mile of new 500 kV lines, $700,000 per mile of 230 kV lines and
$350,000 per mile of 115 kV lines.
Eastern Montana Resources
A regional study sponsored by the NWPP and Northwest Transmission Assessment
Committee (NTAC) found that enhancement of existing 500 kV and 230 kV facilities
would be required to integrate additional generation from Montana. Power transfer from
eastern Montana to the Northwest is affected by several constraints. A more detailed study effort focusing on relieving constraints from central and eastern Montana is
underway as a joint effort by Avista, BPA, NorthWestern Energy, PacifiCorp and Puget
Sound Energy. The study is scheduled for completion in 2010 to identify transmission
constraints and engineering-level construction cost estimates to fix the constraints.
Avista Corp 2009 Electric IRP – Public Draft 5-7
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 91 of 729
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-8 Avista Corp
Chapter 5 – Transmission & Distribution
Integration of Resources on the Avista Transmission System
Avista-LSE has requested three generator interconnection studies: one near Reardan,
Washington, a second near Grangeville, Idaho, and a third in Garfield County,
Washington. Each interconnection study request is discussed below.
Reardan, Washington
Avista-LSE submitted a generator interconnection request to Avista Transmission for a
65 MW wind project located south of Reardan, Washington, and has requested a study
of interconnection to Avista’s 115 kV Devil’s Gap – Lind line. The point of interconnection is located approximately six miles south of the Reardan Substation on the Gaffney – Reardan segment of the line. Initial studies indicate that construction of a
new 115 kV transmission line into the Spokane area will be required to accommodate
the full project output. Preliminary cost estimates of interconnecting a wind project at Reardan are under $15 million; however, not all costs associated with the upgrade will be directly assigned to the project because some upgrades are needed whether or nor
the project is completed.
Avista-LSE will submit a transmission service request to determine any required system reinforcements necessary to enable the proposed project to be a designated network
resource serving native load under FERC OATT requirements.
Grangeville, Idaho
Avista-LSE submitted a generator interconnection request to Avista Transmission in 2008 for a proposed 120 MW wind project located near Grangeville, Idaho. The
transmission line from the project to the point of interconnection is approximately 10
miles. Studies indicate the project is feasible based on the preliminary analysis;
however the work also identified thermal violations under certain contingency conditions. The total estimated cost of interconnecting this project at the Grangeville Substation, without mitigating the reactive power consumption of the transmission
system, is estimated to be $12.9 million including reconductoring the local transmission
lines. The cost estimate does not include constructing a radial 115 kV interconnection
transmission line from the project to the point of interconnection at the Grangeville substation.
Garfield County, Washington
Avista-LSE submitted a generator interconnection request for a 200 MW wind project
located approximately three miles east of the Columbia/Garfield (Washington) county line in Garfield County. The project, located near Pomeroy, Washington, would
interconnect to the existing Dry Creek-Talbot 230 kV line via a double-bus, double-
breaker (six breaker station) configured station. The approximate interconnection cost is
$4 million.
Lancaster Integration
Avista is evaluating various alternatives for a new transmission interconnection with
BPA in the Spokane Valley. One interconnection is at BPA’s Lancaster Substation. This
interconnection might allow Avista to eliminate or offset some BPA wheeling charges for moving the Lancaster combustion turbine project to Avista’s system. Avista is working
Avista Corp 2009 Electric IRP – Public Draft 5-8
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 92 of 729
2009 Electric IRPAvista Corp 5-9
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
with BPA to determine what form the interconnection should take. Preliminary studies
indicate that Avista could expand existing BPA facilities, construct an interconnection to
BPA facilities, and build a loop-in to the Avista Boulder-Rathdrum 230 kV line.
This project could benefit Avista and BPA by increasing system reliability,decreasing losses and delaying the need for additional transformation at the BPA Bell Substation. The proposed plan of service might represent the best option for service from Avista’s
sole perspective. Additional studies indicate that looping the Boulder-Rathdrum 230 kV
line into the Lancaster Substation may allow more transfer capability across the
combined transmission infrastructure of Avista and BPA. The preliminary study results are expected by the end of the third quarter of 2009. Construction could be completed
by the end of 2010.
Other Potential Resources
2009 IRP resources could be located on Avista’s or another organizations transmission grid. The following section provides details concerning generic potential resources.
Generator interconnection and transmission service requests would be required to
integrate any new generation resource.
CCCT with Duct Burner
A 150 to 250 MW CCCT could be integrated into Avista’s 230 kV grid at several
locations. The best locations from a transmission siting perspective are near the existing
Rathdrum and Lancaster units near Rathdrum, Idaho or near the Benewah 230/115 kV
station near Benewah, Idaho
Small Cogeneration (<5 MW)
Small cogeneration plants are likely to be near large industrial loads. Because of the
unique nature of these installations, detailed studies must be run to determine
integration costs. These costs cannot be estimated until a generator interconnection request is made.
Hybrid SCCT (LMS 100)
As with the CCCT, a 100 MW SCCT could be integrated into the Avista 230 kV grid in
several locations. The best locations from a transmission siting perspective are near the existing Rathdrum and Lancaster units near Rathdrum, Idaho, or near the Benewah 230/115 kV station near Benewah, Idaho.
Coal
It is unlikely that a coal-fired facility (traditional or gasification) would be built in Avista’s service territory, especially with Washington’s emissions performance standards. If a coal plant is developed, it would probably be integrated on a third party transmission
system.
Geothermal
There are no known geothermal resources in Avista’s service territory, so this resource type would require an interconnection request on another system. The most likely areas
for this type of generation for Avista are located in Nevada or Oregon. Significant
Avista Corp 2009 Electric IRP – Public Draft 5-9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 93 of 729
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-10 Avista Corp
Chapter 5 – Transmission & Distribution
transmission constraints exist between these states and Avista’s system, increasing the
cost of integrating a geothermal resource.
Nuclear
Direct integration of nuclear power into Avista’s transmission system is unlikely because of the significant cost, siting and waste issues associated with this resource. If this type
of resource were constructed, regional studies as well as generator interconnection and
transmission service requests on the transmission provider would be required.
Hydro Upgrades
Spokane River Upgrades
The transmission system serving the Spokane River projects plant is robust so small
upgrades could be integrated with minimal system impacts. Larger upgrade options,
including a second powerhouse at Monroe Street or a Post Falls rebuild, could require
significant upgrades. Generator interconnection and transmission service requests would be necessary prior to work being initiated.
Clark Fork Hydro Upgrades
The Clark Fork area transmission system consists of Avista and BPA 230 kV lines
integrating Western Montana hydro projects. These include the federally-operated Libby and Hungry Horse projects and Avista’s Clark Fork Projects (Cabinet Gorge and Noxon Rapids). Avista coordinates operation of the Clark Fork projects with BPA to maintain
system reliability in the Western Montana area. Additional transmission upgrades are
not anticipated to integrate the planned Clark Fork upgrades. However, the addition of
new units to the Clark Fork project may require transmission upgrades.
Distribution Efficiencies
Avista delivers electrical energy from generators to the customer’s meter through a
network of conductors (links) and stations (nodes). The network system is operated at
various voltages to reduce current losses across the system dependent upon the
distance the energy must travel. A common rule to determine efficient energy delivery is one kV per mile. For example, 115 kV power systems commonly transfer energy over a distance of up to 115 miles while 13 kV power systems generally limit delivery of energy
to 13 miles.
Avista’s energy delivery systems are categorized into two classes: transmission and
distribution. Avista’s transmission system operates at nominal voltages of 230 kV and
115 kV. Distribution is operated at a range of voltages between 4.16 kV and 34.5 kV.
Avista’s distribution system is typically operated at a nominal voltage of 13.2 kV in its urban service centers. In addition to voltages, the transmission system is designed and operated distinctly from the distribution system. For example, the transmission system is
a network linking multiple sources with multiple loads while the distribution system is
configured in radial feeders which link a single source to multiple loads.
Avista Corp 2009 Electric IRP – Public Draft 5-10
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 94 of 729
2009 Electric IRPAvista Corp 5-11
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
System Efficiencies Team
Avista’s System Efficiencies Team of operational, engineering and planning staff
developed a plan to evaluate potential energy savings from transmission and distribution (T&D) system upgrades. The first phase summarized energy savings from
distribution feeder upgrades. The second phase, beginning in the summer of 2009,
combines transmission system topologies with “right sizing” distribution feeders to
reduce system losses, improve system reliability and meet future load growth.
Distribution Feeders
The System Efficiencies Team evaluated energy losses across Avista’s distribution
system. Avista’s distribution system consists of approximately 330 feeders covering
30,000 square miles. The distribution feeders range in length from 3 to 73 miles.
The System Efficiencies Team evaluated several efficiency programs across urban and
rural distribution feeders. The programs consisted of the following system
enhancements:
ƒ Conductor losses;
ƒ Distribution Transformers;
ƒ Secondary Districts; and
ƒ VAR compensation.
The energy loss, capital investment and O&M cost reductions resulting from individual
efficiency programs were combined on a per-feeder basis. This approach provided a
means to rank and compare energy savings and net resource cost for each feeder.
Economic Analysis
Economic analysis determined the net resource costs to upgrade each feeder for the
four program areas listed above. The net resource cost determines the avoided cost of
a new energy resource levelized over the asset’s life-cycle expressed in dollars per
megawatt (MW). This economic value is calculated by estimating the capital investment, energy savings, and avoidance of O&M and interim capital investments resulting from
feeder upgrades. The economic analysis methodology and assumptions are more fully
described in the Avista Distribution System Efficiencies Program document in Appendix G.
The O&M avoided costs for upgrades were determined by modeling existing feeders in the Availability Workbench Program. This program is an expected value model
combining a weighted average time and material cost of equipment failure with the
probability of failure. The distribution feeder’s conductor, transformers and ancillary equipment were used to determine the failure model for each feeder. Customer, material and labor costs incurred by outages from equipment failure are the economic
parameters used to measure the economic risk of a failure. The results were calibrated
to the expected value model using industry indexes and Avista’s actual outage history.
A sensitivity analysis determined the variability of net resource values of different projected O&M time horizons, since O&M avoided costs are based on expected
outcomes. Figure 5.2 illustrates the levelized cost of feeder upgrades.
Avista Corp 2009 Electric IRP – Public Draft 5-11
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 95 of 729
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-12 Avista Corp
Chapter 5 – Transmission & Distribution
Figure 5.2: Levelized Cost of Feeder Upgrades
-50
0
50
100
150
200
0 25 50 75
10
0
12
5
15
0
17
5
20
0
22
5
25
0
27
5
30
0
av
o
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e
d

c
o
s
t

(
$
/
M
W
h
)
40 year 15 year
10 year 5 year
quantity of feeders
Distribution feeders with the highest potential for efficiency gains were included in the
IRP analysis. The five selected feeders are estimated to reduce system losses by 2.7
aMW. Figure 5.3 shows the projected feeder upgrade supply curve of potential for loss
reduction. If all feeders under $100 per MWh using the 40 year levelized cost method were upgraded, nearly 13 aMW could be saved and between 20 and 25 MW of peak
savings could be realized.
Figure 5.3: Estimated Feeder Supply Curve
-150
-100
-50
0
50
100
150
200
- 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0
av
o
i
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e
d

c
o
s
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(
$
/
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W
h
)
5 Year Avoided Cost
40 Year Avoided Cost
aMW of savings
Avista Corp 2009 Electric IRP – Public Draft 5-12
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 96 of 729
2009 Electric IRPAvista Corp 5-13
Chapter 5 - Transmission and DistributionChapter 5 – Transmission & Distribution
Operational Considerations
By implementing feeder efficiency programs, voltage drop across feeders will decrease and will provide an opportunity to deploy a Conservation Voltage Reduction (CVR) program. Although CVR was not evaluated in the system efficiencies program, previous
studies suggest additional energy savings can be achieved by lowering the voltage.
Also, with the implementation of “smart grid” technology, voltage can be regulated to
follow the time-varying load profile along the feeder more accurately. The energy savings associated with CVR can be challenging to forecast since it is dependent upon
system configuration and varying load characteristics. However, a study conducted by
the Northwest Energy Efficiency Alliance in January 2008 determined a general
guideline of 0.7 percent reduction in energy consumption with a 1 percent change in voltage.
Transmission Topologies and Distribution Feeder Sizing
After completion of the distribution analysis, a second-phase analysis will incorporate
transmission topology, station locations and load growth. Avista’s power grid was designed and built to adhere to reliability and capacity guidelines for the least first cost. This approach was reasonable considering the low cost of electrical energy at the time
the system was constructed. With the increasing cost of energy, a life cycle economic
analysis is warranted to evaluate power system losses corresponding to various power
grid configurations.
The comprehensive analysis will review several transmission topologies to determine
the most efficient configuration to move bulk power through and by Avista’s balancing
area. The transmission topologies will consider the efficiency between star network, hub and loop, southern loop and southern source. Avista’s load service will be incorporated in this analysis by determining ideal substation placement and feeder sizes as well as
forecasted load growth. The comprehensive analysis will evaluate many of the items
listed below.
ƒ Develop performance criteria to determine system measures;
ƒ Develop base case to measure existing system performance;
ƒ Develop methodology to determine a full build out load case;
ƒ Identify transmission topologies to be evaluated;
ƒ Identify guidelines for placing substations;
ƒ Identify guidelines for distribution feeder sizes; and
ƒ Bound the analysis to ensure the system remains reliable, compliant and
operationally flexible.
Avista Corp 2009 Electric IRP – Public Draft 5-13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 97 of 729
Chapter 5 - Transmission and Distribution
2009 Electric IRP5-14 Avista Corp
Chapter 5 – Transmission & Distribution
Summary
Avista’s transmission system consists of over 2,200 miles of high voltage transmission lines. Transmission system planning utilizes various local, sub-region and regional
processes providing opportunities for stakeholder input into system expansions and
upgrades. The system can integrate small amounts of generation in many areas for
moderate integration costs; these costs tend to escalate rapidly as generation project size increases. Planning and initial cost estimates have been developed for three wind projects on the Avista system. Integration costs for the interconnection of customer-
owned generation will be developed after a complete generation interconnection
request has been submitted and accepted by Avista’s Transmission Department.
Avista Corp 2009 Electric IRP – Public Draft 5-14
Chapter 6- Generation Resource Options
6. Generation Resource Options
Introduction
There are many generating options to meet future resource deficits. Avista can upgrade
existing resources, build new facilities or contract with other energy companies for future delivery. This section describes the resources considered to meet future resource
needs. Most of the new resources described in this chapter are generic. Actual size,
cost and operating characteristics may differ due to siting or engineering requirements.
This chapter also includes some resource options specific to Avista, including the Reardan wind site and hydro upgrades to our Spokane and Clark Fork River Projects. The costs and characteristics of these resources are based on preliminary studies.
Chapter Highlights
• Only resources with well-defined costs and characteristics were considered in the PRS analysis; other resources were studied in sensitivities.
• Renewable resource economics include federal tax incentives.
• Small hydro upgrades and wood-fired upgrades were considered in this IRP..
Assumptions
For the Preferred Resource Strategy (PRS) analysis, Avista only considers commercially-available resources with well-known cost, availability and generation
profiles. These resources include gas-fired combined cycle combustion turbines (CCCT)
and simple cycle combustion turbines (SCCT), large scale wind, and small hydro upgrades to the Spokane River Projects. Several other resource options described later in the chapter were not included the PRS analysis, but were modeled as sensitivities to
understand potential impacts to the PRS.
Levelized costs referred to throughout this section are assumed to be at the generation
busbar. The nominal discount rate used in the analyses is 7.08 percent; the real
discount rate is 5.09 percent. Nominal levelized costs were computed by discounting nominal cash flows at the nominal interest rate. Real levelized costs were computed by
discounting real 2009 dollar cash flows at the real discount rate.
Renewable resources eligible for either the federal investment tax credit1 (ITC) or production tax credit (PTC) are assumed to use the highest-value credit. The levelized costs shown in this chapter are based on maximum available energy for each year
instead of expected generation. For example, wind generation assumes 33 percent
availability, CCCT generation assumes 90 percent availability and SCCT generation
1 Avista may not be able to take advantage of the full 30 percent tax credit in a single year. The utility may need to find a tax investor or spread the tax credit over multiple years. The Company may be eligible for
treasury credits for projects with construction dates beginning before January 1, 2011.
Avista Corp 2009 Electric IRP- Public Draft 6-1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 98 of 729
2009 Electric IRPAvista Corp 6-1
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
6. Generation Resource Options
Introduction
There are many generating options to meet future resource deficits. Avista can upgrade
existing resources, build new facilities or contract with other energy companies for future delivery. This section describes the resources considered to meet future resource
needs. Most of the new resources described in this chapter are generic. Actual size,
cost and operating characteristics may differ due to siting or engineering requirements.
This chapter also includes some resource options specific to Avista, including the Reardan wind site and hydro upgrades to our Spokane and Clark Fork River Projects. The costs and characteristics of these resources are based on preliminary studies.
Chapter Highlights
• Only resources with well-defined costs and characteristics were considered in the PRS analysis; other resources were studied in sensitivities.
• Renewable resource economics include federal tax incentives.
• Small hydro upgrades and wood-fired upgrades were considered in this IRP..
Assumptions
For the Preferred Resource Strategy (PRS) analysis, Avista only considers commercially-available resources with well-known cost, availability and generation
profiles. These resources include gas-fired combined cycle combustion turbines (CCCT)
and simple cycle combustion turbines (SCCT), large scale wind, and small hydro upgrades to the Spokane River Projects. Several other resource options described later in the chapter were not included the PRS analysis, but were modeled as sensitivities to
understand potential impacts to the PRS.
Levelized costs referred to throughout this section are assumed to be at the generation
busbar. The nominal discount rate used in the analyses is 7.08 percent; the real
discount rate is 5.09 percent. Nominal levelized costs were computed by discounting nominal cash flows at the nominal interest rate. Real levelized costs were computed by
discounting real 2009 dollar cash flows at the real discount rate.
Renewable resources eligible for either the federal investment tax credit1 (ITC) or production tax credit (PTC) are assumed to use the highest-value credit. The levelized costs shown in this chapter are based on maximum available energy for each year
instead of expected generation. For example, wind generation assumes 33 percent
availability, CCCT generation assumes 90 percent availability and SCCT generation
1 Avista may not be able to take advantage of the full 30 percent tax credit in a single year. The utility may need to find a tax investor or spread the tax credit over multiple years. The Company may be eligible for
treasury credits for projects with construction dates beginning before January 1, 2011.
Avista Corp 2009 Electric IRP- Public Draft 6-1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 99 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-2 Avista Corp
Chapter 6- Generation Resource Options
assumes 92 percent availability. The following are definitions of the levelized cost items
used in this chapter:
ƒCapital Recovery and Taxes: includes depreciation, return on capital, income taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
generation asset investment.
ƒInterconnection Capital Recovery:includes depreciation, return on capital,
income taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
transmission asset investments needed to interconnect the generator.
ƒAllowance for Funds Used During Construction (AFUDC): the cost of money for
construction payments before the utility is allowed to recover prudently invested costs.
ƒVariable Operations and Maintenance (O&M): Costs per MWh related to
incremental generation.
ƒFixed O&M: Costs related to plant
operation such as labor, parts, and other maintenance services (pipeline capacity costs are included for CCCT resources)
that are not based on generation levels.
ƒCO2 Emissions Adder: Cost of carbon
dioxide (greenhouse gas) emissions
based on Wood Mackenzie forecast.
ƒNOx and SO2: Cost of nitrous oxide and
sulfur dioxide emissions based on the
Wood Mackenzie forecast.
ƒFuel Costs: The cost of fuels such as
natural gas, coal or wood per the
efficiency of the generator. Further details on fuel prices are included in the Market Analysis chapter.
ƒExcise Taxes and Other Overheads:Includes miscellaneous charges for non-
capital expenses.
Tables at the end of this chapter (Table 6.28 and Table 6.29) show incremental
capacity, heat rates, generation and transmission capital cost estimates before AFUDC,
fixed O&M, variable costs, peak credit2 and levelized costs. All costs shown in this section are in 2009 dollars unless otherwise noted.
2 Peak credit is the amount of capacity a resource contributes at system peak.
Avista Corp 2009 Electric IRP- Public Draft 6-2
Chapter 6- Generation Resource Options
Gas-Fired Combined Cycle Combustion Turbine (CCCT)
The gas-fired CCCT plants were the Northwest resource of choice earlier this decade.
The technology provides a reliable source of both capacity and energy for a relatively
inexpensive upfront investment. The main disadvantage is generation cost volatility due to reliance on natural gas. The Company’s 2007 IRP discussed the potential for buying long-term fixed price contracts or supplies to reduce the price volatility and risk
associated with this technology.
CCCTs were modeled using one-on-one (1x1) configurations with both water- and air-cooling technologies. This configuration consists of a single gas turbine, a single heat
recovery steam generator (HRSG) and a duct burner to gain generation from the
HRSG. These plants are 250 MW to 300 MW each. Plants can be constructed with two
gas turbines and one HRSG (2x1 configuration) up to 600 MW. For modeling purposes, 250 MW and 400 MW plant sizes were included as resource options. Capital cost estimates were based on General Electric (GE) 7FA machine technology. O&M costs
were based on engineering estimates from the Company’s experience with Coyote
Spring 2.
The heat rate modeled for a water-cooled CCCT resource is 6,750 Btu/kWh in 2009.
The CCCT heat rate falls by 0.5 percent annually to reflect anticipated technological
improvements. The plants include seven percent of rated capacity as duct firing at a
heat rate of 8,500 Btu/kWh. Forced outage rates are estimated at 5.0 percent per year and 18 days of maintenance are assumed. Cold startup costs are $35/MWh plus 6.6 Dth per MW per start.
CCCT plants are modeled to back down to 55 percent of nameplate capacity and ramp
from zero to full load in five hours. Carbon emissions are 117 pounds per Dth of fuel. The maximum capability of each plant is highly dependent on ambient temperature and
plant elevation. Figure 6.1 illustrates the average capacity by month for a water-cooled
CCCT located in Rathdrum, Idaho, compared to the same technology at other locations.
The air-cooled technology is shown for illustrative purposes and would be an alternative configuration if an adequate water supply is unavailable. Air-cooled technologies provide less capacity during warmer periods of the year. The figure illustrates how
combined cycle capacity is greatly affected by site elevation. (Rosalia-2,238 feet,
Rathdrum-2,211 feet, Lewiston-745 feet and Boardman-298 feet).
Avista Corp 2009 Electric IRP- Public Draft 6-3
Noxon Rapids turbine upgrade
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 100 of 729
2009 Electric IRPAvista Corp 6-3
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
assumes 92 percent availability. The following are definitions of the levelized cost items
used in this chapter:
ƒCapital Recovery and Taxes: includes depreciation, return on capital, income taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
generation asset investment.
ƒInterconnection Capital Recovery:includes depreciation, return on capital,
income taxes, property taxes, insurance, and miscellaneous charges such as
uncollectible accounts and state taxes for each of these items pertaining to
transmission asset investments needed to interconnect the generator.
ƒAllowance for Funds Used During Construction (AFUDC): the cost of money for
construction payments before the utility is allowed to recover prudently invested costs.
ƒVariable Operations and Maintenance (O&M): Costs per MWh related to
incremental generation.
ƒFixed O&M: Costs related to plant
operation such as labor, parts, and other maintenance services (pipeline capacity costs are included for CCCT resources)
that are not based on generation levels.
ƒCO2 Emissions Adder: Cost of carbon
dioxide (greenhouse gas) emissions
based on Wood Mackenzie forecast.
ƒNOx and SO2: Cost of nitrous oxide and
sulfur dioxide emissions based on the
Wood Mackenzie forecast.
ƒFuel Costs: The cost of fuels such as
natural gas, coal or wood per the
efficiency of the generator. Further details on fuel prices are included in the Market Analysis chapter.
ƒExcise Taxes and Other Overheads:Includes miscellaneous charges for non-
capital expenses.
Tables at the end of this chapter (Table 6.28 and Table 6.29) show incremental
capacity, heat rates, generation and transmission capital cost estimates before AFUDC,
fixed O&M, variable costs, peak credit2 and levelized costs. All costs shown in this section are in 2009 dollars unless otherwise noted.
2 Peak credit is the amount of capacity a resource contributes at system peak.
Avista Corp 2009 Electric IRP- Public Draft 6-2
Chapter 6- Generation Resource Options
Gas-Fired Combined Cycle Combustion Turbine (CCCT)
The gas-fired CCCT plants were the Northwest resource of choice earlier this decade.
The technology provides a reliable source of both capacity and energy for a relatively
inexpensive upfront investment. The main disadvantage is generation cost volatility due to reliance on natural gas. The Company’s 2007 IRP discussed the potential for buying long-term fixed price contracts or supplies to reduce the price volatility and risk
associated with this technology.
CCCTs were modeled using one-on-one (1x1) configurations with both water- and air-cooling technologies. This configuration consists of a single gas turbine, a single heat
recovery steam generator (HRSG) and a duct burner to gain generation from the
HRSG. These plants are 250 MW to 300 MW each. Plants can be constructed with two
gas turbines and one HRSG (2x1 configuration) up to 600 MW. For modeling purposes, 250 MW and 400 MW plant sizes were included as resource options. Capital cost estimates were based on General Electric (GE) 7FA machine technology. O&M costs
were based on engineering estimates from the Company’s experience with Coyote
Spring 2.
The heat rate modeled for a water-cooled CCCT resource is 6,750 Btu/kWh in 2009.
The CCCT heat rate falls by 0.5 percent annually to reflect anticipated technological
improvements. The plants include seven percent of rated capacity as duct firing at a
heat rate of 8,500 Btu/kWh. Forced outage rates are estimated at 5.0 percent per year and 18 days of maintenance are assumed. Cold startup costs are $35/MWh plus 6.6 Dth per MW per start.
CCCT plants are modeled to back down to 55 percent of nameplate capacity and ramp
from zero to full load in five hours. Carbon emissions are 117 pounds per Dth of fuel. The maximum capability of each plant is highly dependent on ambient temperature and
plant elevation. Figure 6.1 illustrates the average capacity by month for a water-cooled
CCCT located in Rathdrum, Idaho, compared to the same technology at other locations.
The air-cooled technology is shown for illustrative purposes and would be an alternative configuration if an adequate water supply is unavailable. Air-cooled technologies provide less capacity during warmer periods of the year. The figure illustrates how
combined cycle capacity is greatly affected by site elevation. (Rosalia-2,238 feet,
Rathdrum-2,211 feet, Lewiston-745 feet and Boardman-298 feet).
Avista Corp 2009 Electric IRP- Public Draft 6-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 101 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-4 Avista Corp
Chapter 6- Generation Resource Options
Figure 6.1: CCCT Output Per 100 MW of Nameplate Capacity
80
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Rathdrum, ID (water)
Rathdrum, ID (air)
Rosalia, WA (water)
Boardman, OR (water)
Lewiston, ID (water)
The capital cost for a CCCT with AFUDC is estimated to be $1,553 per kW. Fixed O&M
costs are expected to be $11 per kW-year. Table 6.1 is the levelized cost for a CCCT
resource in both nominal and 2009 dollars.
Table 6.1: CCCT (Water Cooled) Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 20.91 15.49
Interconnection capital recovery 0.76 0.64
AFUDC 2.60 2.21
Variable O&M 3.88 3.29
Fixed O&M 4.00 3.39
CO2 emissions adder 15.25 12.94
NOx and SO2 emission adder 0.15 0.13
Fuel costs 59.29 50.28
Excise taxes and other overheads 3.57 3.04
Total Cost 110.41 91.40
It is possible to sequester 90 percent of the carbon emissions from a gas-fired resource.
A cost adder of $1,374 per kW was added for sequestration, for a total cost of $2,907
per kW including AFUDC. The fixed O&M is expected to increase to $18.70 per kW-
year. The levelized cost for this resource option is shown in Table 6.2.
Avista Corp 2009 Electric IRP- Public Draft 6-4
Chapter 6- Generation Resource Options
Table 6.2: CCCT with Carbon Sequestration Levelized Costs per MWh
Item Nominal $ Real 2009$
Capital recovery and taxes 43.70 32.38
Interconnection capital recovery 0.57 0.48
AFUDC 7.51 6.37
Variable O&M 5.69 4.83
Fixed O&M 5.86 4.97
CO2 emissions adder 1.98 1.68
NOx & SO2 emission adder 0.00 0.00
Fuel costs 75.51 64.20
Excise taxes and other overheads 3.86 3.28
Total Cost 144.68 118.18
Gas-Fired Simple Cycle Combustion Turbine (SCCT)
Gas-fired combustion turbines provide low-cost capacity and are capable of providing
energy as needed. Technology advances allow some SCCTs the ability to start and
ramp quickly, enabling them to provide regulation services and reserves for varying loads and intermittent resources such as wind.
Two SCCT options were modeled in the IRP: Frame (GE 7EA) and hybrid aero-
derivative (GE LMS 100). The LMS 100 ramps up quickly and has a lower heat rate and lower start-up costs than the 7EA model, but its capital costs are significantly higher. O&M costs are based on engineering and NPCC estimates. The frame machine is
modeled in 60 MW increments and the LMS 100 in 100 MW increments.
Heat rates for SCCT plants are 8,400 Btu/kWh (LMS100) and 10,200 Btu/kWh (7EA) in 2009, decreasing by 0.5 percent per year (real) to reflect anticipated technological improvements. Forced outage rates are estimated at five percent per year, with no
maintenance outages (approximately 10 days per year) because it is assumed to occur
in months when these plants do not typically operate. Cold startup costs are $15 per MW per start for the frame machine and one Dth per MW for the LMS 100. The maximum capabilities of these plants are highly dependent on ambient temperature,
and use the same monthly capacity shape as CCCT plants.
The capital cost for a 2009 SCCT with AFUDC is estimated to be $676 per kW for the frame and $1,342 per kW for the LMS 100. Fixed O&M costs are modeled at $4 per kW-
year for each resource. Tables 6.3 and 6.4 show the levelized cost per MWh for each
resource. The LMS 100 can provide regulation for load and wind; reserves were valued
at $84 per kW-year in the PRS analysis.
Avista Corp 2009 Electric IRP- Public Draft 6-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 102 of 729
2009 Electric IRPAvista Corp 6-5
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Figure 6.1: CCCT Output Per 100 MW of Nameplate Capacity
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Rathdrum, ID (water)
Rathdrum, ID (air)
Rosalia, WA (water)
Boardman, OR (water)
Lewiston, ID (water)
The capital cost for a CCCT with AFUDC is estimated to be $1,553 per kW. Fixed O&M
costs are expected to be $11 per kW-year. Table 6.1 is the levelized cost for a CCCT
resource in both nominal and 2009 dollars.
Table 6.1: CCCT (Water Cooled) Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 20.91 15.49
Interconnection capital recovery 0.76 0.64
AFUDC2.60 2.21
Variable O&M 3.88 3.29
Fixed O&M 4.00 3.39
CO2 emissions adder 15.25 12.94
NOx and SO2 emission adder 0.15 0.13
Fuel costs 59.29 50.28
Excise taxes and other overheads 3.57 3.04
Total Cost 110.41 91.40
It is possible to sequester 90 percent of the carbon emissions from a gas-fired resource.
A cost adder of $1,374 per kW was added for sequestration, for a total cost of $2,907
per kW including AFUDC. The fixed O&M is expected to increase to $18.70 per kW-
year. The levelized cost for this resource option is shown in Table 6.2.
Avista Corp 2009 Electric IRP- Public Draft 6-4
Chapter 6- Generation Resource Options
Table 6.2: CCCT with Carbon Sequestration Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 43.70 32.38
Interconnection capital recovery 0.57 0.48
AFUDC 7.51 6.37
Variable O&M 5.69 4.83
Fixed O&M 5.86 4.97
CO2 emissions adder 1.98 1.68
NOx & SO2 emission adder 0.00 0.00
Fuel costs 75.51 64.20
Excise taxes and other overheads 3.86 3.28
Total Cost 144.68 118.18
Gas-Fired Simple Cycle Combustion Turbine (SCCT)
Gas-fired combustion turbines provide low-cost capacity and are capable of providing
energy as needed. Technology advances allow some SCCTs the ability to start and
ramp quickly, enabling them to provide regulation services and reserves for varying loads and intermittent resources such as wind.
Two SCCT options were modeled in the IRP: Frame (GE 7EA) and hybrid aero-
derivative (GE LMS 100). The LMS 100 ramps up quickly and has a lower heat rate and lower start-up costs than the 7EA model, but its capital costs are significantly higher. O&M costs are based on engineering and NPCC estimates. The frame machine is
modeled in 60 MW increments and the LMS 100 in 100 MW increments.
Heat rates for SCCT plants are 8,400 Btu/kWh (LMS100) and 10,200 Btu/kWh (7EA) in 2009, decreasing by 0.5 percent per year (real) to reflect anticipated technological improvements. Forced outage rates are estimated at five percent per year, with no
maintenance outages (approximately 10 days per year) because it is assumed to occur
in months when these plants do not typically operate. Cold startup costs are $15 per MW per start for the frame machine and one Dth per MW for the LMS 100. The maximum capabilities of these plants are highly dependent on ambient temperature,
and use the same monthly capacity shape as CCCT plants.
The capital cost for a 2009 SCCT with AFUDC is estimated to be $676 per kW for the frame and $1,342 per kW for the LMS 100. Fixed O&M costs are modeled at $4 per kW-
year for each resource. Tables 6.3 and 6.4 show the levelized cost per MWh for each
resource. The LMS 100 can provide regulation for load and wind; reserves were valued
at $84 per kW-year in the PRS analysis.
Avista Corp 2009 Electric IRP- Public Draft 6-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 103 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-6 Avista Corp
Chapter 6- Generation Resource Options
Table 6.3: Frame SCCT Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 9.27 6.87
Interconnection capital recovery 0.74 0.63
AFUDC 0.43 0.36
Variable O&M 5.90 5.00
Fixed O&M 0.58 0.49
CO2 emissions adder 23.04 19.55
NOx & SO2 emission adder 0.23 0.19
Fuel costs 90.09 76.40
Excise taxes and other overheads 5.19 4.40
Total Cost 135.47 113.90
Table 6.4: LMS 100 Levelized Costs per MWh
Item Nominal $ Real 2009$
Capital recovery and taxes 19.31 14.31
Interconnection capital recovery 0.74 0.63
AFUDC 0.89 0.75
Variable O&M 6.49 5.50
Fixed O&M 0.58 0.49
CO2 emissions adder 18.97 16.10
NOx & SO2 emission adder 0.19 0.16
Fuel costs 74.19 62.92
Excise taxes and other overheads 4.35 3.69
Total Cost 125.71 104.55
Wind
Concerns over the environmental impact of carbon-based generation technologies have
increased demand for wind generation. Governments are promoting wind generation
through tax credits, renewable portfolio standards and climate change legislation. The
2009 American Recovery and Reinvestment Act extended the PTC for wind through January 1, 2013 and provided an option for owners to select a 30 percent ITC instead.
Several wind resource locations were studied for this IRP:
ƒ Reardan (up to 50 MW);
ƒ Columbia Basin (50 MW increments);
ƒ Montana (25 MW increments);
ƒ Small scale (less than 1 MW); and
ƒ Offshore (75 MW increments).
Reardan and Columbia Basin locations were the only wind resources considered for the PRS analysis. Other resource locations will be considered if projects are submitted in
response to competitive solicitations.
Avista Corp 2009 Electric IRP- Public Draft 6-6
Chapter 6- Generation Resource Options
Transmission is an issue for many wind projects. Projects often are not close to
transmission, or when they are the existing lines are fully subscribed. New transmission
must often be constructed. For IRP analyses, transmission costs are assumed to be:
ƒReardan: Avista transmission system requiring $15 million in network and project
transmission improvements.
ƒColumbia Basin (Tier 1 and Tier 2): BPA wheel3 and $100 per kW for local
interconnection.
ƒMontana: Northwestern wheel4 and $50 per kW for local interconnection.
ƒSmall Scale: Avista distribution system and $100 per kW for distribution
interconnection and a 10 percent adder for saved transmission and distribution
losses.
ƒOffshore: BPA wheel and $36 per kW for local interconnection (assumes economies of scale).
Wind resources benefit from having no emissions and no fuel costs, but are
disadvantaged by not being dispatchable, and being capital and labor intensive. The costs for capital and fixed O&M, and capacity factors are shown in Table 6.5. Capacity factors are expected (P50) values for each location. A statistical method, based on
regional wind studies, was used to derive a range of capacity factors depending on the
wind regime in each year (see stochastic modeling assumptions for more details). Using
these expected capacity factors and the capital and operating costs, levelized costs are illustrated in Tables 6.6, 6.7 and 6.8.The cost of integrating wind generation is not
shown, but is expected to change over time depending upon the amount of wind
resources on the Avista system. The PRS analysis used a cost of $3.50 per MWh for
integration services.
Table 6.5: Wind Capital and Fixed O&M Costs
Location
Capital 2009$ (includesAFUDC)
Fixed O&M ($ per kW-year)Capacity Factor
Reardan5 2,183 45 30.0%
Columbia Basin (Tier 1) 2,262 50 33.0%
Columbia Basin (Tier 2) 2,262 50 26.4%
Montana 2,262 50 37.0%
Small Scale 3,343 50 20.0%
Off Shore 5,573 95 45.0%
3 $18 per kW-year and losses are 1.9 percent. Tier 2 wind has a 20 percent lower capacity factor than Tier 1 wind. 4 $40.80 per kW-year and losses are 4.0 percent 5 Costs for the Reardan Wind Project are generic based on prices at the time of modeling. Actual costs will vary depending on turbine and balance of plant costs at time of construction. Reardan is assumed to be slightly less expensive than Columbia Basin projects, due to the lack of significant transmission upgrade
costs, no third party development fees and the proximity of the project to Avista’s operations center.
Avista Corp 2009 Electric IRP- Public Draft 6-7
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 104 of 729
2009 Electric IRPAvista Corp 6-7
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.3: Frame SCCT Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 9.27 6.87
Interconnection capital recovery 0.74 0.63
AFUDC0.43 0.36
Variable O&M 5.90 5.00
Fixed O&M 0.58 0.49
CO2 emissions adder 23.04 19.55
NOx & SO2 emission adder 0.23 0.19
Fuel costs 90.09 76.40
Excise taxes and other overheads5.19 4.40
Total Cost 135.47 113.90
Table 6.4: LMS 100 Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 19.31 14.31
Interconnection capital recovery 0.74 0.63
AFUDC0.89 0.75
Variable O&M 6.49 5.50
Fixed O&M 0.58 0.49
CO2 emissions adder 18.97 16.10
NOx & SO2 emission adder 0.19 0.16
Fuel costs 74.19 62.92
Excise taxes and other overheads4.35 3.69
Total Cost 125.71 104.55
Wind
Concerns over the environmental impact of carbon-based generation technologies have
increased demand for wind generation. Governments are promoting wind generation
through tax credits, renewable portfolio standards and climate change legislation. The
2009 American Recovery and Reinvestment Act extended the PTC for wind through January 1, 2013 and provided an option for owners to select a 30 percent ITC instead.
Several wind resource locations were studied for this IRP:
ƒ Reardan (up to 50 MW);
ƒ Columbia Basin (50 MW increments);
ƒ Montana (25 MW increments);
ƒ Small scale (less than 1 MW); and
ƒ Offshore (75 MW increments).
Reardan and Columbia Basin locations were the only wind resources considered for the PRS analysis. Other resource locations will be considered if projects are submitted in
response to competitive solicitations.
Avista Corp 2009 Electric IRP- Public Draft 6-6
Chapter 6- Generation Resource Options
Transmission is an issue for many wind projects. Projects often are not close to
transmission, or when they are the existing lines are fully subscribed. New transmission
must often be constructed. For IRP analyses, transmission costs are assumed to be:
ƒReardan: Avista transmission system requiring $15 million in network and project
transmission improvements.
ƒColumbia Basin (Tier 1 and Tier 2): BPA wheel3 and $100 per kW for local
interconnection.
ƒMontana: Northwestern wheel4 and $50 per kW for local interconnection.
ƒSmall Scale: Avista distribution system and $100 per kW for distribution
interconnection and a 10 percent adder for saved transmission and distribution
losses.
ƒOffshore: BPA wheel and $36 per kW for local interconnection (assumes economies of scale).
Wind resources benefit from having no emissions and no fuel costs, but are
disadvantaged by not being dispatchable, and being capital and labor intensive. The costs for capital and fixed O&M, and capacity factors are shown in Table 6.5. Capacity factors are expected (P50) values for each location. A statistical method, based on
regional wind studies, was used to derive a range of capacity factors depending on the
wind regime in each year (see stochastic modeling assumptions for more details). Using
these expected capacity factors and the capital and operating costs, levelized costs are illustrated in Tables 6.6, 6.7 and 6.8.The cost of integrating wind generation is not
shown, but is expected to change over time depending upon the amount of wind
resources on the Avista system. The PRS analysis used a cost of $3.50 per MWh for
integration services.
Table 6.5: Wind Capital and Fixed O&M Costs
Location
Capital 2009$ (includesAFUDC)
Fixed O&M ($ per kW-year)Capacity Factor
Reardan5 2,183 45 30.0%
Columbia Basin (Tier 1) 2,262 50 33.0%
Columbia Basin (Tier 2) 2,262 50 26.4%
Montana 2,262 50 37.0%
Small Scale 3,343 50 20.0%
Off Shore 5,573 95 45.0%
3 $18 per kW-year and losses are 1.9 percent. Tier 2 wind has a 20 percent lower capacity factor than Tier 1 wind. 4 $40.80 per kW-year and losses are 4.0 percent 5 Costs for the Reardan Wind Project are generic based on prices at the time of modeling. Actual costs will vary depending on turbine and balance of plant costs at time of construction. Reardan is assumed to be slightly less expensive than Columbia Basin projects, due to the lack of significant transmission upgrade
costs, no third party development fees and the proximity of the project to Avista’s operations center.
Avista Corp 2009 Electric IRP- Public Draft 6-7
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 105 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-8 Avista Corp
Chapter 6- Generation Resource Options
Table 6.6: Columbia Basin Wind Project Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 56.63 48.01
Interconnection capital recovery 4.40 3.73
AFUDC 4.60 3.90
Variable O&M 3.54 3.00
Fixed O&M 20.79 17.63
CO2 emissions adder 0.00 0.00
NOx & SO2 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Integration 4.05 3.50
Excise taxes and other overheads 1.05 0.89
Total Cost 95.06 80.66
Table 6.7: Small Scale Project Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 125.01 105.97
Interconnection capital recovery 0.00 0.00
AFUDC 10.14 8.60
Variable O&M 3.54 3.00
Fixed O&M 30.60 25.94
CO2 emissions adder 0.00 0.00
NOx and SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Integration 4.05 3.50
Excise taxes and other overheads 1.48 1.25
Total Cost 174.82 148.27
Table 6.8: Offshore Wind Project Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 103.83 88.02
Interconnection capital recovery 1.16 0.99
AFUDC 11.16 9.46
Variable O&M 5.90 5.00
Fixed O&M 28.97 24.57
CO2 emissions adder 0.00 0.00
NOx and SO2 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Integration 4.05 3.50
Excise taxes and other overheads 1.51 1.28
Total Cost 156.58 132.81
Avista Corp 2009 Electric IRP- Public Draft 6-8
Chapter 6- Generation Resource Options
Coal
Pulverized and integrated gasification combined cycle (IGCC) coal plants were included
as resource options for the IRP. Pulverized coal options included sub-critical, super-
critical, ultra-critical and circulating fluidized bed (CFB) technologies. These different technologies have different boiler temperatures and pressures, resulting in different capital cost and operating efficiencies. The ultra-critical plant was modeled for sensitivity
analysis.
IGCC plants gasify coal, thereby lowering carbon emissions and removing toxic substances before combustion. This technology has the potential to sequester 90
percent of carbon emissions, effectively reducing CO2 emissions from 205 pounds per
MMBtu to 20.5 pounds per MMBtu.
The Washington State legislature passed Senate Bill 6001 in 2007, effectively prohibiting local electric utilities from developing coal-fired facilities that do not
sequester emissions. A coal facility could legally be constructed to serve Idaho loads,
where no emissions performance standard exists, but Avista is not considering a
pulverized coal facility for the 2009 IRP and believes such a facility is unlikely to be approved. IGCC facilities were modeled in 200 MW increments in the PRS analysis
beginning in 2022 for IGCC plants without sequestration and 2025 for an IGCC plants
with sequestration.
Capital and fixed O&M costs, and heat rates, are shown in Table 6.9. Levelized costs per MWh are shown in Tables 6.10, 6.11 and 6.12. IGCC resources currently may
qualify for the federal PTC; but the levelized costs in the tables below do not reflect the
incentive as it is expected to expire before an IGCC resource could be built in 2022.
IGCC coal plants are assumed to be located in Montana with transmission provided by upgrades to Northwestern’s system.
Table 6.9: Coal Capital Costs (2009$)
Technology
Capital Cost ($/kW includes
AFUDC)
Fixed O&M
($/kW/Yr)
Heat Rate
(btu/kWh)
Ultra Critical Pulverized Coal $3,594 $38 8,825
IGCC $4,305 $41 8,130
IGCC with Sequestration $6,013 $50 9,595
Avista Corp 2009 Electric IRP- Public Draft 6-9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 106 of 729
2009 Electric IRPAvista Corp 6-9
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.6: Columbia Basin Wind Project Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 56.63 48.01
Interconnection capital recovery 4.40 3.73
AFUDC4.60 3.90
Variable O&M 3.54 3.00
Fixed O&M 20.79 17.63
CO2 emissions adder 0.00 0.00
NOx & SO2 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Integration4.05 3.50
Excise taxes and other overheads1.05 0.89
Total Cost 95.06 80.66
Table 6.7: Small Scale Project Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 125.01 105.97
Interconnection capital recovery 0.00 0.00
AFUDC10.14 8.60
Variable O&M 3.54 3.00
Fixed O&M 30.60 25.94
CO2 emissions adder 0.00 0.00
NOx and SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Integration4.05 3.50
Excise taxes and other overheads1.48 1.25
Total Cost 174.82 148.27
Table 6.8: Offshore Wind Project Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 103.83 88.02
Interconnection capital recovery 1.16 0.99
AFUDC11.16 9.46
Variable O&M 5.90 5.00
Fixed O&M 28.97 24.57
CO2 emissions adder 0.00 0.00
NOx and SO2 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Integration4.05 3.50
Excise taxes and other overheads1.51 1.28
Total Cost 156.58 132.81
Avista Corp 2009 Electric IRP- Public Draft 6-8
Chapter 6- Generation Resource Options
Coal
Pulverized and integrated gasification combined cycle (IGCC) coal plants were included
as resource options for the IRP. Pulverized coal options included sub-critical, super-
critical, ultra-critical and circulating fluidized bed (CFB) technologies. These different technologies have different boiler temperatures and pressures, resulting in different capital cost and operating efficiencies. The ultra-critical plant was modeled for sensitivity
analysis.
IGCC plants gasify coal, thereby lowering carbon emissions and removing toxic substances before combustion. This technology has the potential to sequester 90
percent of carbon emissions, effectively reducing CO2 emissions from 205 pounds per
MMBtu to 20.5 pounds per MMBtu.
The Washington State legislature passed Senate Bill 6001 in 2007, effectively prohibiting local electric utilities from developing coal-fired facilities that do not
sequester emissions. A coal facility could legally be constructed to serve Idaho loads,
where no emissions performance standard exists, but Avista is not considering a
pulverized coal facility for the 2009 IRP and believes such a facility is unlikely to be approved. IGCC facilities were modeled in 200 MW increments in the PRS analysis
beginning in 2022 for IGCC plants without sequestration and 2025 for an IGCC plants
with sequestration.
Capital and fixed O&M costs, and heat rates, are shown in Table 6.9. Levelized costs per MWh are shown in Tables 6.10, 6.11 and 6.12. IGCC resources currently may
qualify for the federal PTC; but the levelized costs in the tables below do not reflect the
incentive as it is expected to expire before an IGCC resource could be built in 2022.
IGCC coal plants are assumed to be located in Montana with transmission provided by upgrades to Northwestern’s system.
Table 6.9: Coal Capital Costs (2009$)
Technology
Capital Cost ($/kW includes
AFUDC)
Fixed O&M
($/kW/Yr)
Heat Rate
(btu/kWh)
Ultra Critical Pulverized Coal $3,594 $38 8,825
IGCC $4,305 $41 8,130
IGCC with Sequestration $6,013 $50 9,595
Avista Corp 2009 Electric IRP- Public Draft 6-9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 107 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-10 Avista Corp
Chapter 6- Generation Resource Options
Table 6.10: Ultra Critical Pulverized Coal Project Levelized Cost per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 49.96 37.02
Interconnection capital recovery 0.60 0.57
AFUDC 9.29 7.87
Variable O&M 1.53 1.30
Fixed O&M 5.98 5.07
CO2 emissions adder 34.92 29.63
NOx and SO2 emission adder 1.30 1.26
Fuel costs 11.37 9.64
Excise taxes and other overheads 2.39 2.03
Total Cost 117.34 94.32
Table 6.11: IGCC Coal Project Levelized Cost per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 59.95 44.42
Interconnection capital recovery 0.60 0.51
AFUDC 11.14 9.45
Variable O&M 4.72 4.00
Fixed O&M 6.45 5.47
CO2 emissions adder 32.17 27.30
NOx and SO2 emission adder 0.59 0.54
Fuel costs 10.47 8.88
Excise taxes and other overheads 2.36 2.00
Total Cost 128.45 102.56
Table 6.12: IGCC with Carbon Sequestration Coal Project Levelized Cost ($/MWh)
Item Nominal $Real 2009$
Capital recovery and taxes 84.71 62.77
Interconnection capital recovery 0.61 0.51
AFUDC 15.75 13.35
Variable O&M 5.19 4.40
Fixed O&M 7.94 6.73
CO2 emissions adder 3.80 3.22
NOx and SO2 emission adder 0.18 0.15
Fuel costs 12.36 10.48
Excise taxes and other overheads 1.28 1.08
Total Cost 131.82 102.70
Avista Corp 2009 Electric IRP- Public Draft 6-10
Chapter 6- Generation Resource Options
Hydroelectric Project Upgrades
Avista has a long history of owning, maintaining and operating hydroelectric projects.
We continue to programmatically upgrade many of our hydroelectric facilities. Our latest
hydro upgrades add 7 MW at Noxon Rapids Unit 1 and 17 MW at Cabinet Gorge Unit 4. The Company is planning to upgrade units 2, 3 and 4 at Noxon Rapids (2010, 2011 and 2012 respectively), and units 1 and 2 at Nine Mile in 2012.
Avista designed and studied other larger potential upgrades at Long Lake and Cabinet
Gorge. These upgrades were too costly in previous studies, but increasing market prices, growing capacity needs, renewable energy incentives and carbon emission
costs may make these resources financially more attractive now. Upgrade options
include a second powerhouse at Long Lake, a fifth unit at Long Lake and Cabinet Gorge
Unit 5. These upgrades are not included as PRS options, but they were evaluated for sensitivity analysis. See Table 6.13 for more information on these hydro upgrades.
Avista engineers also developed preliminary plans to replace the powerhouse at Post
Falls, doubling its capacity. These large hydro upgrade options have attracted attention
during this IRP cycle and will be further studied between now and the 2011 IRP. The estimated levelized costs of hydro upgrades are included in Table 6.14 and Table 6.15.
Table 6.13: Hydro Upgrade Project Characteristics
Project
CapitalCost(2009$)
(includesAFUDC) YearAvailable Capacity (MW)Capacity Factor
Little Falls Unit 1 2,787 2014 1.0 32%
Little Falls Unit 2 1,929 2015 1.0 32%
Little Falls Unit 3 3,430 2016 1.0 32%
Little Falls Unit 4 1,393 2017 1.0 32%
Post Falls Unit 6 5,359 2018 0.2 32%
Upper Falls 3,870 2019 2.0 49%
Long Lake Unit 5 2,882 2020 24.0 34%
Long Lake 2nd Powerhouse 2,454 2020 60.0 30%
Cabinet Gorge Unit 5 1,660 2015 60.0 17%
Avista Corp 2009 Electric IRP- Public Draft 6-11
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 108 of 729
2009 Electric IRPAvista Corp 6-11
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.10: Ultra Critical Pulverized Coal Project Levelized Cost per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 49.96 37.02
Interconnection capital recovery 0.60 0.57
AFUDC9.29 7.87
Variable O&M 1.53 1.30
Fixed O&M 5.98 5.07
CO2 emissions adder 34.92 29.63
NOx and SO2 emission adder 1.30 1.26
Fuel costs 11.37 9.64
Excise taxes and other overheads2.39 2.03
Total Cost 117.34 94.32
Table 6.11: IGCC Coal Project Levelized Cost per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 59.95 44.42
Interconnection capital recovery 0.60 0.51
AFUDC11.14 9.45
Variable O&M 4.72 4.00
Fixed O&M 6.45 5.47
CO2 emissions adder 32.17 27.30
NOx and SO2 emission adder 0.59 0.54
Fuel costs 10.47 8.88
Excise taxes and other overheads2.36 2.00
Total Cost 128.45 102.56
Table 6.12: IGCC with Carbon Sequestration Coal Project Levelized Cost ($/MWh)
ItemNominal $ Real 2009$
Capital recovery and taxes 84.71 62.77
Interconnection capital recovery 0.61 0.51
AFUDC15.75 13.35
Variable O&M 5.19 4.40
Fixed O&M 7.94 6.73
CO2 emissions adder 3.80 3.22
NOx and SO2 emission adder 0.18 0.15
Fuel costs 12.36 10.48
Excise taxes and other overheads 1.28 1.08
Total Cost 131.82 102.70
Avista Corp 2009 Electric IRP- Public Draft 6-10
Chapter 6- Generation Resource Options
Hydroelectric Project Upgrades
Avista has a long history of owning, maintaining and operating hydroelectric projects.
We continue to programmatically upgrade many of our hydroelectric facilities. Our latest
hydro upgrades add 7 MW at Noxon Rapids Unit 1 and 17 MW at Cabinet Gorge Unit 4. The Company is planning to upgrade units 2, 3 and 4 at Noxon Rapids (2010, 2011 and 2012 respectively), and units 1 and 2 at Nine Mile in 2012.
Avista designed and studied other larger potential upgrades at Long Lake and Cabinet
Gorge. These upgrades were too costly in previous studies, but increasing market prices, growing capacity needs, renewable energy incentives and carbon emission
costs may make these resources financially more attractive now. Upgrade options
include a second powerhouse at Long Lake, a fifth unit at Long Lake and Cabinet Gorge
Unit 5. These upgrades are not included as PRS options, but they were evaluated for sensitivity analysis. See Table 6.13 for more information on these hydro upgrades.
Avista engineers also developed preliminary plans to replace the powerhouse at Post
Falls, doubling its capacity. These large hydro upgrade options have attracted attention
during this IRP cycle and will be further studied between now and the 2011 IRP. The estimated levelized costs of hydro upgrades are included in Table 6.14 and Table 6.15.
Table 6.13: Hydro Upgrade Project Characteristics
Project
CapitalCost(2009$)
(includesAFUDC) YearAvailable Capacity (MW)Capacity Factor
Little Falls Unit 1 2,787 2014 1.0 32%
Little Falls Unit 2 1,929 2015 1.0 32%
Little Falls Unit 3 3,430 2016 1.0 32%
Little Falls Unit 4 1,393 2017 1.0 32%
Post Falls Unit 6 5,359 2018 0.2 32%
Upper Falls 3,870 2019 2.0 49%
Long Lake Unit 5 2,882 2020 24.0 34%
Long Lake 2nd Powerhouse 2,454 2020 60.0 30%
Cabinet Gorge Unit 5 1,660 2015 60.0 17%
Avista Corp 2009 Electric IRP- Public Draft 6-11
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 109 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-12 Avista Corp
Chapter 6- Generation Resource Options
Table 6.14: Hydro Upgrade Nominal Levelized Costs per MWh
Project
Generation
CapitalRecovery & Taxes
Transmission
CapitalRecovery & Taxes AFUDC FixedO&M TotalCost
Little Falls Unit 1 81.07 0.00 5.82 0.00 86.89
Little Falls Unit 2 56.13 0.00 4.03 0.00 60.16
Little Falls Unit 3 99.78 0.00 7.16 0.00 106.94
Little Falls Unit 4 40.54 0.00 2.91 0.00 43.45
Post Falls Unit 6 155.91 0.00 11.19 0.00 167.10
Upper Falls 71.27 0.00 7.54 0.00 78.81
Long Lake Unit 5 63.58 14.38 10.93 0.40 89.29
Long Lake 2nd Powerhouse 66.52 6.51 10.56 0.90 84.49
Cabinet Gorge Unit 5 83.15 0.00 14.29 1.58 99.02
Table 6.15: Hydro Upgrade 2009$ Levelized Costs per MWh
Project
GenerationCapital
Recovery &
Taxes
TransmissionCapital
Recovery &
Taxes AFUDC
Fixed
O&M
Total
Cost
Little Falls Unit 1 68.72 0.00 4.93 0.00 73.66
Little Falls Unit 2 47.58 0.00 3.42 0.00 50.99
Little Falls Unit 3 84.58 0.00 6.07 0.00 90.66
Little Falls Unit 4 34.36 0.00 2.47 0.00 36.83
Post Falls Unit 6 132.16 0.00 9.49 0.00 141.65
Upper Falls 60.42 0.00 6.39 0.00 66.80
Long Lake Unit 5 53.90 12.19 9.26 0.34 75.71
Long Lake 2nd PH 56.39 5.52 8.95 0.76 71.65
Cabinet Gorge Unit 5 70.49 0.00 12.12 1.34 84.00
Other Resource Options
A thorough IRP considers resources that may not be commercially or economically ready for utility-scale development. This is particularly true for some emerging technologies that are attractive from an environmental perspective. These resources are
analyzed to ensure that the Company does not overlook resource options with changing
economic characteristics. Avista analyzed solar, tidal (wave), biomass, geothermal, co-
generation, nuclear, pumped storage, hydrokinetics and large scale hydro.
Solar
Solar technology has advanced in the last several years with help from renewable
portfolio standards, the federal ITC and state incentives. Solar still struggles economically against other resources because of its low capacity factor and high capital cost. To its credit, solar provides predictable on-peak generation that complements the
loads of summer-peaking utilities.
Avista Corp 2009 Electric IRP- Public Draft 6-12
Chapter 6- Generation Resource Options
The Northwest is not a prime location for photovoltaic solar relative to the Southwest. A
well placed utility scale photovoltaic system located in the Pacific Northwest would
achieve a capacity factor of less than 20 percent. Three solar technologies were studied
for this IRP: utility scale photovoltaic, solar-thermal, and roof-top photovoltaic. Each option has certain advantages. Utility scale photovoltaic can be optimally located for the
best solar radiation, solar thermal has the ability to produce a higher capacity factor (up
to 30 percent) and store energy for several hours, and roof-top solar is located at the
source of the load reducing system losses. Capital costs, including AFUDC, for these technologies are expected to be:
ƒ Utility Scale Photovoltaic: $7,900 per kW;
ƒ Solar or Concentrating Thermal: $4,541 per kW; and
ƒ Roof Top Solar: $8,283 per kW.
The levelized costs of these resources, including federal incentives,6 are shown in
Tables 6.16 and 6.17.
Table 6.16: Solar Nominal Levelized Cost ($/MWh)
Item
Utility Scale
Photovoltaic
Solar
Thermal
Roof-Top
Solar
Capital recovery and taxes 312.51 130.82 444.46
Interconnection capital recovery 0.00 4.86 0.00
AFUDC 11.06 12.84 15.73
Variable O&M 0.00 0.00 0.00
Fixed O&M 19.58 29.73 24.48
CO2 emissions adder 0.00 0.00 0.00
NOx and SO2 emissions adder 0.00 0.00 0.00
Fuel costs 0.00 0.00 0.00
Excise taxes and other overheads 0.85 1.29 1.06
Total Cost 344.00 179.54 485.73
6 Washington has small renewable energy incentives for up to $2,000 per year, depending upon location
of manufacturing, through June of 2014. These incentives are not included in this analysis.
Avista Corp 2009 Electric IRP- Public Draft 6-13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 110 of 729
2009 Electric IRPAvista Corp 6-13
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.14: Hydro Upgrade Nominal Levelized Costs per MWh
Project
Generation
CapitalRecovery & Taxes
Transmission
CapitalRecovery & TaxesAFUDC FixedO&M TotalCost
Little Falls Unit 181.070.00 5.82 0.0086.89
Little Falls Unit 256.130.00 4.03 0.0060.16
Little Falls Unit 3 99.780.00 7.16 0.00106.94
Little Falls Unit 440.540.00 2.91 0.0043.45
Post Falls Unit 6 155.910.00 11.19 0.00167.10
Upper Falls 71.270.00 7.54 0.0078.81
Long Lake Unit 5 63.58 14.38 10.93 0.4089.29
Long Lake 2nd Powerhouse 66.526.51 10.56 0.90 84.49
Cabinet Gorge Unit 5 83.150.00 14.29 1.5899.02
Table 6.15: Hydro Upgrade 2009$ Levelized Costs per MWh
Project
GenerationCapitalRecovery &
Taxes
TransmissionCapitalRecovery &
TaxesAFUDC
Fixed
O&M
Total
Cost
Little Falls Unit 168.720.00 4.93 0.0073.66
Little Falls Unit 247.580.00 3.42 0.0050.99
Little Falls Unit 3 84.580.00 6.07 0.0090.66
Little Falls Unit 434.360.00 2.47 0.0036.83
Post Falls Unit 6 132.160.00 9.49 0.00141.65
Upper Falls 60.420.00 6.39 0.0066.80
Long Lake Unit 5 53.90 12.19 9.26 0.3475.71
Long Lake 2nd PH 56.395.52 8.95 0.7671.65
Cabinet Gorge Unit 5 70.490.00 12.12 1.3484.00
Other Resource Options
A thorough IRP considers resources that may not be commercially or economically ready for utility-scale development. This is particularly true for some emerging technologies that are attractive from an environmental perspective. These resources are
analyzed to ensure that the Company does not overlook resource options with changing
economic characteristics. Avista analyzed solar, tidal (wave), biomass, geothermal, co-
generation, nuclear, pumped storage, hydrokinetics and large scale hydro.
Solar
Solar technology has advanced in the last several years with help from renewable
portfolio standards, the federal ITC and state incentives. Solar still struggles economically against other resources because of its low capacity factor and high capital cost. To its credit, solar provides predictable on-peak generation that complements the
loads of summer-peaking utilities.
Avista Corp 2009 Electric IRP- Public Draft 6-12
Chapter 6- Generation Resource Options
The Northwest is not a prime location for photovoltaic solar relative to the Southwest. A
well placed utility scale photovoltaic system located in the Pacific Northwest would
achieve a capacity factor of less than 20 percent. Three solar technologies were studied
for this IRP: utility scale photovoltaic, solar-thermal, and roof-top photovoltaic. Each option has certain advantages. Utility scale photovoltaic can be optimally located for the
best solar radiation, solar thermal has the ability to produce a higher capacity factor (up
to 30 percent) and store energy for several hours, and roof-top solar is located at the
source of the load reducing system losses. Capital costs, including AFUDC, for these technologies are expected to be:
ƒ Utility Scale Photovoltaic: $7,900 per kW;
ƒ Solar or Concentrating Thermal: $4,541 per kW; and
ƒ Roof Top Solar: $8,283 per kW.
The levelized costs of these resources, including federal incentives,6 are shown in
Tables 6.16 and 6.17.
Table 6.16: Solar Nominal Levelized Cost ($/MWh)
Item
Utility Scale
Photovoltaic
Solar
Thermal
Roof-Top
Solar
Capital recovery and taxes 312.51 130.82 444.46
Interconnection capital recovery 0.00 4.86 0.00
AFUDC 11.06 12.84 15.73
Variable O&M 0.00 0.00 0.00
Fixed O&M 19.58 29.73 24.48
CO2 emissions adder 0.00 0.00 0.00
NOx and SO2 emissions adder 0.00 0.00 0.00
Fuel costs 0.00 0.00 0.00
Excise taxes and other overheads 0.85 1.29 1.06
Total Cost 344.00 179.54 485.73
6 Washington has small renewable energy incentives for up to $2,000 per year, depending upon location
of manufacturing, through June of 2014. These incentives are not included in this analysis.
Avista Corp 2009 Electric IRP- Public Draft 6-13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 111 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-14 Avista Corp
Chapter 6- Generation Resource Options
Table 6.17: Solar 2009$ Levelized Cost ($/MWh)
Item
Utility Scale
Photovoltaic
Solar
Thermal
Roof-Top
Solar
Capital recovery and taxes 264.93 110.90 376.79
Interconnection capital recovery 0.00 4.11 0.00
AFUDC 9.38 10.88 13.34
Variable O&M 0.00 0.00 0.00
Fixed O&M 16.60 25.21 20.76
CO2 emissions adder 0.00 0.00 0.00
NOx and SO2 emissions adder 0.00 0.00 0.00
Fuel costs 0.00 0.00 0.00
Excise taxes and other overheads 0.72 1.09 0.90
Total Cost 291.63 152.20 411.78
Biomass and Wood Generation
Avista is an industry leader in biomass generation. In 1983, the Company built one of
the largest biomass generation facilities in North America, the 50 MW Kettle Falls Generating Station. Eastern Washington and Northern Idaho have the potential for new biomass facilities. As part of the 2007 IRP Action Plan to study biomass potential, the
Company targeted its biomass focus on wood generation. Several unique options were
evaluated for this IRP.
The first option is to use the utility’s existing steam turbine capacity at Coyote Spring 2
by augmenting with wood; this option is the CCCT Wood Boiler and would require new
facilities at Coyote Springs 2 for wood handling. It would also require fuel deliveries from
locations remote from the plant, increasing its fuel costs. This option could add 10 MW of capacity to Coyote Springs 2 when the gas-fired portion of the plant is online.
A second option is to add a wood gasifier to the Kettle Falls Combustion Turbine. It
would utilize existing facilities and infrastructure, and increase winter peak generating capacity7 by 7.8 MW. The IRP analysis also includes generic biomass resources, including a new large biomass generation facility using wood gasification technology
and generic biomass resources fueled with manure, landfill gas, wood, and other bio-
waste fuels, including open- and closed-loop technologies. Assumed capital and
operating costs are shown in Table 6.18. The levelized costs are shown in Table 6.19 and Table 6.20. The costs include production tax credits that were extended through January 1, 2014; closed loop technologies receive double the federal credits. No fuel
costs were included for non-wood biomass resources because the fuel cost will depend
on the type of fuel source. For example, a digester resource located at a dairy will have free fuel.
7 The Kettle Falls CT is currently unavailable for winter peak generation due to limited fuel transportation.
Increasing fuel capacity to the northern service area is currently being examined.
Avista Corp 2009 Electric IRP- Public Draft 6-14
Chapter 6- Generation Resource Options
Table 6.18: Biomass Capital Costs
Project
Capital Cost
(2009$) (includesAFUDC)
FixedO&M
($/kW/Yr)
CCCT Wood Boiler 2,745 121
KFCT Wood Gasifier 4,645 85
Wood Gasifer Combined Cycle 3,476 85
Biomass Open-Loop 5,406 85
Biomass Closed-Loop 8,649 150
Table 6.19: Biomass Nominal Levelized Costs per MWh
Item
CCCT
WoodBoiler
KFCT
WoodGasifier
Wood
GasifierCC
Biomass
Open-Loop
Biomass
Closed-Loop
Capital recovery and taxes 24.67 43.03 32.49 48.16 77.07
Interconnection capital recovery 0.00 0.00 0.28 0.28 0.28
AFUDC 2.42 2.30 1.73 3.91 6.25
Variable O&M 7.08 9.08 9.08 3.54 11.79
Fixed O&M 18.09 12.68 12.68 12.40 21.89
CO2 emissions adder 0.00 0.00 0.00 0.00 0.00
NOx and SO2 emission adder 2.12 0.00 0.00 0.00 0.00
Fuel costs 82.50 40.46 40.46 0.00 0.00
Excise taxes and other overheads 4.75 2.69 2.69 0.69 1.46
Total Cost 141.63 110.24 99.41 68.98 118.74
Table 6.20: Biomass 2009 Dollar Levelized Cost per MWh
Item
CCCT
Wood
Boiler
KFCT
Wood
Gasifier
Wood
Gasifier
CC
Biomass
Open-
Loop
Biomass
Closed-
Loop
Capital recovery and taxes 20.91 36.48 27.55 40.83 65.33
Interconnection capital recovery 0.00 0.00 0.24 0.24 0.24
AFUDC 2.05 1.95 1.47 3.31 5.30
Variable O&M 6.00 7.70 7.70 3.00 10.00
Fixed O&M 15.34 10.75 10.75 10.52 18.56
CO2 emissions adder 0.00 0.00 0.00 0.00 0.00
NOx and SO2 emission adder 1.83 0.00 0.00 0.00 0.00
Fuel costs 69.95 34.31 34.31 0.00 0.00
Excise taxes and other overheads 4.03 2.28 2.28 0.59 1.24
Total Cost 120.12 93.47 84.30 58.48 100.66
Avista Corp 2009 Electric IRP- Public Draft 6-15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 112 of 729
2009 Electric IRPAvista Corp 6-15
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Table 6.17: Solar 2009$ Levelized Cost ($/MWh)
Item
Utility Scale
Photovoltaic
Solar
Thermal
Roof-Top
Solar
Capital recovery and taxes 264.93 110.90 376.79
Interconnection capital recovery 0.00 4.11 0.00
AFUDC9.38 10.88 13.34
Variable O&M 0.00 0.00 0.00
Fixed O&M 16.60 25.21 20.76
CO2 emissions adder 0.00 0.00 0.00
NOx and SO2 emissions adder 0.00 0.00 0.00
Fuel costs 0.00 0.00 0.00
Excise taxes and other overheads 0.72 1.09 0.90
Total Cost 291.63 152.20 411.78
Biomass and Wood Generation
Avista is an industry leader in biomass generation. In 1983, the Company built one of
the largest biomass generation facilities in North America, the 50 MW Kettle Falls Generating Station. Eastern Washington and Northern Idaho have the potential for new biomass facilities. As part of the 2007 IRP Action Plan to study biomass potential, the
Company targeted its biomass focus on wood generation. Several unique options were
evaluated for this IRP.
The first option is to use the utility’s existing steam turbine capacity at Coyote Spring 2
by augmenting with wood; this option is the CCCT Wood Boiler and would require new
facilities at Coyote Springs 2 for wood handling. It would also require fuel deliveries from
locations remote from the plant, increasing its fuel costs. This option could add 10 MW of capacity to Coyote Springs 2 when the gas-fired portion of the plant is online.
A second option is to add a wood gasifier to the Kettle Falls Combustion Turbine. It
would utilize existing facilities and infrastructure, and increase winter peak generating capacity7 by 7.8 MW. The IRP analysis also includes generic biomass resources, including a new large biomass generation facility using wood gasification technology
and generic biomass resources fueled with manure, landfill gas, wood, and other bio-
waste fuels, including open- and closed-loop technologies. Assumed capital and
operating costs are shown in Table 6.18. The levelized costs are shown in Table 6.19 and Table 6.20. The costs include production tax credits that were extended through January 1, 2014; closed loop technologies receive double the federal credits. No fuel
costs were included for non-wood biomass resources because the fuel cost will depend
on the type of fuel source. For example, a digester resource located at a dairy will have free fuel.
7 The Kettle Falls CT is currently unavailable for winter peak generation due to limited fuel transportation.
Increasing fuel capacity to the northern service area is currently being examined.
Avista Corp 2009 Electric IRP- Public Draft 6-14
Chapter 6- Generation Resource Options
Table 6.18: Biomass Capital Costs
Project
Capital Cost
(2009$) (includesAFUDC)
FixedO&M
($/kW/Yr)
CCCT Wood Boiler 2,745 121
KFCT Wood Gasifier 4,645 85
Wood Gasifer Combined Cycle 3,476 85
Biomass Open-Loop 5,406 85
Biomass Closed-Loop 8,649 150
Table 6.19: Biomass Nominal Levelized Costs per MWh
Item
CCCT
WoodBoiler
KFCT
WoodGasifier
Wood
GasifierCC
Biomass
Open-Loop
Biomass
Closed-Loop
Capital recovery and taxes 24.67 43.03 32.49 48.16 77.07
Interconnection capital recovery 0.00 0.00 0.28 0.28 0.28
AFUDC 2.42 2.30 1.73 3.91 6.25
Variable O&M 7.08 9.08 9.08 3.54 11.79
Fixed O&M 18.09 12.68 12.68 12.40 21.89
CO2 emissions adder 0.00 0.00 0.00 0.00 0.00
NOx and SO2 emission adder 2.12 0.00 0.00 0.00 0.00
Fuel costs 82.50 40.46 40.46 0.00 0.00
Excise taxes and other overheads 4.75 2.69 2.69 0.69 1.46
Total Cost 141.63 110.24 99.41 68.98 118.74
Table 6.20: Biomass 2009 Dollar Levelized Cost per MWh
Item
CCCT
Wood
Boiler
KFCT
Wood
Gasifier
Wood
Gasifier
CC
Biomass
Open-
Loop
Biomass
Closed-
Loop
Capital recovery and taxes 20.91 36.48 27.55 40.83 65.33
Interconnection capital recovery 0.00 0.00 0.24 0.24 0.24
AFUDC 2.05 1.95 1.47 3.31 5.30
Variable O&M 6.00 7.70 7.70 3.00 10.00
Fixed O&M 15.34 10.75 10.75 10.52 18.56
CO2 emissions adder 0.00 0.00 0.00 0.00 0.00
NOx and SO2 emission adder 1.83 0.00 0.00 0.00 0.00
Fuel costs 69.95 34.31 34.31 0.00 0.00
Excise taxes and other overheads 4.03 2.28 2.28 0.59 1.24
Total Cost 120.12 93.47 84.30 58.48 100.66
Avista Corp 2009 Electric IRP- Public Draft 6-15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 113 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-16 Avista Corp
Chapter 6- Generation Resource Options
Geothermal
Northwest utilities have developed increased interest in geothermal energy over the
past two years. Geothermal energy provides a stable renewable source that can provide
capacity and energy with minimal carbon dioxide emissions (zero to 200 pounds per MWh). The federal government has also extended production tax credits to this
technology through January 1, 2014. Geothermal energy is disadvantaged by a risky
development process involving drilling several thousand feet below the earth’s crust;
each hole can cost over $3 million. Capital costs are assumed to be $5,698 per kW, including AFUDC, with fixed operating costs of $75 per kW-year. Table 6.21 presents the levelized cost for geothermal generation. Geothermal costs appear attractive once a
viable location has been found, but the risk capital required to find a viable site is
significant and cannot be underestimated. The values below do not account for dry-hole
costs.
Table 6.21: Geothermal Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 49.05 41.58
Interconnection capital recovery 0.28 0.24
AFUDC 6.85 5.81
Variable O&M 5.90 5.00
Fixed O&M 11.14 9.45
CO2 emissions adder 1.93 1.64
NOx and SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 0.82 0.70
Total Cost 75.97 64.41
Tidal and Wave
Tidal and wave power are in the early stages of development. It has varying generation,
but is more predictable than wind. Questions remain surrounding corrosion, bio-fouling by barnacles and other marine organisms, environmental issues and siting concerns. Depending upon its application, tidal power can generate in two time periods daily, but
the generation pattern follows the lunar cycle. A 30 percent capacity factor was
assumed for the IRP analysis.
Given its early development stage, tidal power was not considered for the PRS. The costs of tidal power are uncertain at this time and were estimated using a variety of
sources and engineering estimates. Capital costs including AFUDC are expected to be
$10,389 per kW. Costs presented in Table 6.22 are estimated costs for an experimental project.
Avista Corp 2009 Electric IRP- Public Draft 6-16
Chapter 6- Generation Resource Options
Table 6.22: Tidal/Wave Levelized Costs per MWh
Item Nominal $ Real 2009$
Capital recovery and taxes 305.57 259.04
Interconnection capital recovery 0.00 0.00
AFUDC 11.90 10.09
Variable O&M 0.00 0.00
Fixed O&M 448.74 379.52
CO2 emissions adder 0.00 0.00
NOx & SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 19.42 16.47
Total 785.63 665.12
Small Cogeneration Avista has few industrial customers capable of developing a cogeneration project. If an
interested customer was inclined to proceed, it could provide benefits including reduced
transmission and distribution losses, shared fuel/capital/emissions costs, and credit towards Washington’s I-937 targets. This resource was excluded from the PRS, because Avista is not aware of any cogeneration plans by its customers. If a customer
wanted to pursue this resource, Avista would consider it along with other generation
options. The expected levelized costs for cogeneration are shown in Table 6.23.
Table 6.23: Small Cogeneration Levelized Costs per MWh
Item Nominal $ Real 2009$
Capital recovery and taxes 28.09 20.81
Interconnection capital recovery 0.00 0.00
AFUDC 1.29 1.10
Variable O&M 5.90 5.00
Fixed O&M 2.43 2.06
CO2 emissions adder 12.87 10.92
NOx and SO2 emission adder 0.13 0.11
Fuel costs 49.18 41.70
Excise taxes and other overheads 3.05 2.59
Total 102.94 84.29
NuclearNuclear plants are not currently considered a viable resource option for Avista given the
uncertainty of their economics, the apparent lack of political support for the technology
in the region. Like coal plants, nuclear resources need to be studied because other
utilities in the Western Interconnect may be able to incorporate nuclear power into their resource mixes. The viability of nuclear power could change as national policy priorities focus attention on de-carbonizing the nation’s energy supply. Nuclear capital costs are
difficult to forecast, as no new nuclear facility has been built in the United States since
the 1980s, so costs were obtained from industry studies and plant license proposals. Capital cost sensitivity analyses were performed to compensate for the difficulties
Avista Corp 2009 Electric IRP- Public Draft 6-17
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 114 of 729
2009 Electric IRPAvista Corp 6-17
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Geothermal
Northwest utilities have developed increased interest in geothermal energy over the
past two years. Geothermal energy provides a stable renewable source that can provide
capacity and energy with minimal carbon dioxide emissions (zero to 200 pounds per MWh). The federal government has also extended production tax credits to this
technology through January 1, 2014. Geothermal energy is disadvantaged by a risky
development process involving drilling several thousand feet below the earth’s crust;
each hole can cost over $3 million. Capital costs are assumed to be $5,698 per kW, including AFUDC, with fixed operating costs of $75 per kW-year. Table 6.21 presents the levelized cost for geothermal generation. Geothermal costs appear attractive once a
viable location has been found, but the risk capital required to find a viable site is
significant and cannot be underestimated. The values below do not account for dry-hole
costs.
Table 6.21: Geothermal Levelized Costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 49.05 41.58
Interconnection capital recovery 0.280.24
AFUDC6.855.81
Variable O&M 5.905.00
Fixed O&M 11.149.45
CO2 emissions adder 1.931.64
NOx and SO2 emission adder 0.000.00
Fuel costs 0.000.00
Excise taxes and other overheads0.820.70
Total Cost 75.97 64.41
Tidal and Wave
Tidal and wave power are in the early stages of development. It has varying generation,
but is more predictable than wind. Questions remain surrounding corrosion, bio-fouling by barnacles and other marine organisms, environmental issues and siting concerns. Depending upon its application, tidal power can generate in two time periods daily, but
the generation pattern follows the lunar cycle. A 30 percent capacity factor was
assumed for the IRP analysis.
Given its early development stage, tidal power was not considered for the PRS. The costs of tidal power are uncertain at this time and were estimated using a variety of
sources and engineering estimates. Capital costs including AFUDC are expected to be
$10,389 per kW. Costs presented in Table 6.22 are estimated costs for an experimental project.
Avista Corp 2009 Electric IRP- Public Draft 6-16
Chapter 6- Generation Resource Options
Table 6.22: Tidal/Wave Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 305.57 259.04
Interconnection capital recovery 0.00 0.00
AFUDC 11.90 10.09
Variable O&M 0.00 0.00
Fixed O&M 448.74 379.52
CO2 emissions adder 0.00 0.00
NOx & SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 19.42 16.47
Total 785.63 665.12
Small Cogeneration Avista has few industrial customers capable of developing a cogeneration project. If an
interested customer was inclined to proceed, it could provide benefits including reduced
transmission and distribution losses, shared fuel/capital/emissions costs, and credit towards Washington’s I-937 targets. This resource was excluded from the PRS, because Avista is not aware of any cogeneration plans by its customers. If a customer
wanted to pursue this resource, Avista would consider it along with other generation
options. The expected levelized costs for cogeneration are shown in Table 6.23.
Table 6.23: Small Cogeneration Levelized Costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 28.09 20.81
Interconnection capital recovery 0.00 0.00
AFUDC 1.29 1.10
Variable O&M 5.90 5.00
Fixed O&M 2.43 2.06
CO2 emissions adder 12.87 10.92
NOx and SO2 emission adder 0.13 0.11
Fuel costs 49.18 41.70
Excise taxes and other overheads 3.05 2.59
Total 102.94 84.29
NuclearNuclear plants are not currently considered a viable resource option for Avista given the
uncertainty of their economics, the apparent lack of political support for the technology
in the region. Like coal plants, nuclear resources need to be studied because other
utilities in the Western Interconnect may be able to incorporate nuclear power into their resource mixes. The viability of nuclear power could change as national policy priorities focus attention on de-carbonizing the nation’s energy supply. Nuclear capital costs are
difficult to forecast, as no new nuclear facility has been built in the United States since
the 1980s, so costs were obtained from industry studies and plant license proposals. Capital cost sensitivity analyses were performed to compensate for the difficulties
Avista Corp 2009 Electric IRP- Public Draft 6-17
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 115 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-18 Avista Corp
Chapter 6- Generation Resource Options
obtaining reliable capital costs for nuclear plants. The starting point for capital costs was
$7,168 per kW, including AFUDC. Levelized costs are shown in Table 6.24.
Table 6.24: Nuclear Levelized costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 91.79 77.81
Interconnection capital recovery 0.60 0.51
AFUDC 27.23 23.09
Variable O&M 0.65 0.55
Fixed O&M 15.29 12.96
CO2 emissions adder 0.00 0.00
NOx and SO2 emission adder 0.00 0.00
Fuel costs 12.06 10.22
Excise taxes and other overheads 0.55 0.47
Total 148.17 125.61
Hydrokinetics Hydrokinetics projects consist of small turbines placed in rivers that generate based on the amount of water flow in the system. Avista has identified potential locations for this
technology and has developed preliminary cost estimates shown in Table 6.25. Capital
costs for this low-impact hydro resource is expected to be $4,212 per kW including AFUDC and fixed O&M is $3 per kW-year.
Table 6.25: Hydrokinetics Levelized costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 138.89 117.75
Interconnection capital recovery 0.00 0.00
AFUDC 7.38 6.25
Variable O&M 0.00 0.00
Fixed O&M 1.53 1.30
CO2 emissions adder 0.00 0.00
NOx and SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 0.07 0.06
Total Cost 147.87 125.35
Pumped Storage
Increasing wind generation levels in the Northwest has renewed interest in pumped
storage. Few studies have been conducted for the Northwest market. The most likely
storage options are water or battery technologies. Either option faces significant re-charging penalties illustrated by the high variable O&M charge. The expected capital
cost is $4,151 per kW, including AFUDC, with $5 per kW-year for fixed O&M. Levelized
costs estimates are shown in Table 6.26. The reserve value, estimated to be $84 per
kW-year is not shown in the table.
Avista Corp 2009 Electric IRP- Public Draft 6-18
Chapter 6- Generation Resource Options
Table 6.26: Pumped Storage Levelized costs per MWh
Item Nominal $ Real 2009$
Capital recovery and taxes 90.71 88.61
Interconnection capital recovery 2.59 2.20
AFUDC 16.86 14.29
Variable O&M 92.86 78.76
Fixed O&M 1.22 1.04
CO2 emissions adder 0.00 0.00
NOx and SO2 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 4.07 3.45
Total 208.31 188.35
Large Scale Hydro New large hydro projects are not likely to be built in the Pacific Northwest because of
environmental and cost hurdles. British Columbia has projects in the design phases.
Avista may be able to contract with a Canadian firm for delivery of this energy. However, the resource was not considered for the PRS analyses because of the uncertainty surrounding large hydro, and the lack of transmission from British Columbia
to Avista’s service territory. The expected capital costs, including AFUDC, are estimated
at $5,273 per kW; fixed O&M is estimated at $2 per kW-year. The levelized cost
analysis shown in Table 6.27 includes BPA and British Columbia Transmission Corporation transmission wheels.
Table 6.27: Large Scale Hydro Levelized costs per MWh
Item Nominal $ Real 2009$
Capital recovery and taxes 232.41 197.01
Interconnection capital recovery 1.86 1.58
AFUDC 39.95 39.09
Variable O&M 0.00 0.00
Fixed O&M 0.98 0.83
CO2 emissions adder 0.00 0.00
NOx and SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 0.04 0.04
Total 275.24 238.54
Avista Corp 2009 Electric IRP- Public Draft 6-19
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 116 of 729
2009 Electric IRPAvista Corp 6-19
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
obtaining reliable capital costs for nuclear plants. The starting point for capital costs was
$7,168 per kW, including AFUDC. Levelized costs are shown in Table 6.24.
Table 6.24: Nuclear Levelized costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 91.79 77.81
Interconnection capital recovery 0.60 0.51
AFUDC27.23 23.09
Variable O&M 0.65 0.55
Fixed O&M 15.29 12.96
CO2 emissions adder 0.00 0.00
NOx and SO2 emission adder 0.00 0.00
Fuel costs 12.06 10.22
Excise taxes and other overheads 0.55 0.47
Total148.17 125.61
Hydrokinetics Hydrokinetics projects consist of small turbines placed in rivers that generate based on the amount of water flow in the system. Avista has identified potential locations for this
technology and has developed preliminary cost estimates shown in Table 6.25. Capital
costs for this low-impact hydro resource is expected to be $4,212 per kW including AFUDC and fixed O&M is $3 per kW-year.
Table 6.25: Hydrokinetics Levelized costs per MWh
ItemNominal $ Real 2009$
Capital recovery and taxes 138.89 117.75
Interconnection capital recovery 0.00 0.00
AFUDC7.38 6.25
Variable O&M 0.00 0.00
Fixed O&M 1.53 1.30
CO2 emissions adder 0.00 0.00
NOx and SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads0.07 0.06
Total Cost 147.87 125.35
Pumped Storage
Increasing wind generation levels in the Northwest has renewed interest in pumped
storage. Few studies have been conducted for the Northwest market. The most likely
storage options are water or battery technologies. Either option faces significant re-charging penalties illustrated by the high variable O&M charge. The expected capital
cost is $4,151 per kW, including AFUDC, with $5 per kW-year for fixed O&M. Levelized
costs estimates are shown in Table 6.26. The reserve value, estimated to be $84 per
kW-year is not shown in the table.
Avista Corp 2009 Electric IRP- Public Draft 6-18
Chapter 6- Generation Resource Options
Table 6.26: Pumped Storage Levelized costs per MWh
Item Nominal $Real 2009$
Capital recovery and taxes 90.71 88.61
Interconnection capital recovery 2.59 2.20
AFUDC 16.86 14.29
Variable O&M 92.86 78.76
Fixed O&M 1.22 1.04
CO2 emissions adder 0.00 0.00
NOx and SO2 emissions adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 4.07 3.45
Total 208.31 188.35
Large Scale Hydro New large hydro projects are not likely to be built in the Pacific Northwest because of
environmental and cost hurdles. British Columbia has projects in the design phases.
Avista may be able to contract with a Canadian firm for delivery of this energy. However, the resource was not considered for the PRS analyses because of the uncertainty surrounding large hydro, and the lack of transmission from British Columbia
to Avista’s service territory. The expected capital costs, including AFUDC, are estimated
at $5,273 per kW; fixed O&M is estimated at $2 per kW-year. The levelized cost
analysis shown in Table 6.27 includes BPA and British Columbia Transmission Corporation transmission wheels.
Table 6.27: Large Scale Hydro Levelized costs per MWh
Item Nominal $ Real 2009$
Capital recovery and taxes 232.41 197.01
Interconnection capital recovery 1.86 1.58
AFUDC 39.95 39.09
Variable O&M 0.00 0.00
Fixed O&M 0.98 0.83
CO2 emissions adder 0.00 0.00
NOx and SO2 emission adder 0.00 0.00
Fuel costs 0.00 0.00
Excise taxes and other overheads 0.04 0.04
Total 275.24 238.54
Avista Corp 2009 Electric IRP- Public Draft 6-19
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 117 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-20 Avista Corp
Chapter 6- Generation Resource Options
Avista Corp 2009 Electric IRP- Public Draft 6-20
Summary
Avista has several resource alternatives to select from for this IRP. Each provides
different benefits, costs and risks. This IRP identifies relevant characteristics and
chooses a set of resources that are actionable, meet customer’s energy and capacity needs, balances renewable requirements and keeps customer costs minimized. Table
6.28 is a summary of resource costs and plant characteristics used in the PRS
analyses. All other resources are shown in Table 6.29. The PRS chapter discusses
resource choices and provides “tipping-point” analyses to explain how resource costs would need to change to be included in the PRS. [Note: capital costs do not include AFUDC.]
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 118 of 729
2009 Electric IRPAvista Corp 6-21
Chapter 6 - Generation Resource OptionsChapter 6- Generation Resource Options
Avista Corp 2009 Electric IRP- Public Draft 6-20
Summary
Avista has several resource alternatives to select from for this IRP. Each provides
different benefits, costs and risks. This IRP identifies relevant characteristics and
chooses a set of resources that are actionable, meet customer’s energy and capacity needs, balances renewable requirements and keeps customer costs minimized. Table
6.28 is a summary of resource costs and plant characteristics used in the PRS
analyses. All other resources are shown in Table 6.29. The PRS chapter discusses
resource choices and provides “tipping-point” analyses to explain how resource costs would need to change to be included in the PRS. [Note: capital costs do not include AFUDC.]
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 119 of 729
Chapter 6 - Generation Resource Options
2009 Electric IRP6-22 Avista Corp
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Chapter 7- Market Analysis
7. Market Analysis
Introduction
This section discusses the market environment that Avista expects to face in the future.
The analytical foundation for the 2009 IRP is a fundamentals-based electricity model of the entire Western Interconnect. The market analysis compares potential resource
options on their value in the wholesale marketplace, rather than on overall costs.
Resource net market values are used in the Preferred Resource Strategy (PRS)
analyses. Understanding market conditions in the different geographic areas of the Western Interconnect is important, because regional markets are highly correlated because of large transmission linkages between load centers. This IRP builds on prior
analytical work by maintaining the relationships between the various sub-markets within
the Western Interconnect and the changing value of company-owned and contracted-for
resources. The backbone of the analysis is AURORAxmp, an electric market model that dispatches resources to loads across the Western Interconnect with given fuel prices,
hydro conditions, and transmission and resource constraints. The model’s primary
outputs are electricity prices at key market hubs (e.g., Mid-Columbia), resource dispatch
costs and values and greenhouse gas emissions.
Marketplace
AURORAxmp is a modeling tool used to simulate the Western Interconnect. The
Western Interconnect includes the states west of the Rocky Mountains, the Canadian
provinces of British Columbia and Alberta and the Baja region of Mexico as shown in
Figure 7.1. The modeled area has an installed resource base of approximately 200,000 MW, and an average load of approximately half that level.
Avista Corp 2009 Electric IRP – Public Draft 7-1
Chapter Highlights
• Mid-Columbia electricity and Malin natural gas prices are 27 and 20 percent
higher than the 2007 IRP, primarily due to carbon legislation impacts.
• Mid-Columbia electricity prices are expected to average $79.56 per megawatt-
hour (levelized) over the next 20 years.
• Mid-Columbia electricity prices are forecast to be one-third higher, than they otherwise would be, due to projected carbon legislation.
• Average Malin natural gas prices are expected to be $7.36 per decatherm (levelized) over the next 20 years.
• Gas-fired resources continue to serve most new loads and take the place of
coal generation to reduce greenhouse gas emissions
• Society’s mandates to acquire new renewable resources help reduce carbon
emmisions, but force utilities to invest in twice as much generation infrastructure.
• New environment-driven investment, combined with higher market prices will lead to higher retail rates, absent federal initiatives to limit rate increases.
• Carbon legislation is expected to increase 20-year cost (NPV, 2009 dollars) for
electricity generation by $25.7 billion (10 percent) in the Western Interconnect.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 120 of 729
2009 Electric IRPAvista Corp 7-1
Chapter 7 - Market AnalysisChapter 7- Market Analysis
7. Market Analysis
Introduction
This section discusses the market environment that Avista expects to face in the future.
The analytical foundation for the 2009 IRP is a fundamentals-based electricity model of the entire Western Interconnect. The market analysis compares potential resource
options on their value in the wholesale marketplace, rather than on overall costs.
Resource net market values are used in the Preferred Resource Strategy (PRS)
analyses. Understanding market conditions in the different geographic areas of the Western Interconnect is important, because regional markets are highly correlated because of large transmission linkages between load centers. This IRP builds on prior
analytical work by maintaining the relationships between the various sub-markets within
the Western Interconnect and the changing value of company-owned and contracted-for
resources. The backbone of the analysis is AURORAxmp, an electric market model that dispatches resources to loads across the Western Interconnect with given fuel prices,
hydro conditions, and transmission and resource constraints. The model’s primary
outputs are electricity prices at key market hubs (e.g., Mid-Columbia), resource dispatch
costs and values and greenhouse gas emissions.
Marketplace
AURORAxmp is a modeling tool used to simulate the Western Interconnect. The
Western Interconnect includes the states west of the Rocky Mountains, the Canadian
provinces of British Columbia and Alberta and the Baja region of Mexico as shown in
Figure 7.1. The modeled area has an installed resource base of approximately 200,000 MW, and an average load of approximately half that level.
Avista Corp 2009 Electric IRP – Public Draft 7-1
Chapter Highlights
• Mid-Columbia electricity and Malin natural gas prices are 27 and 20 percent
higher than the 2007 IRP, primarily due to carbon legislation impacts.
• Mid-Columbia electricity prices are expected to average $79.56 per megawatt-
hour (levelized) over the next 20 years.
• Mid-Columbia electricity prices are forecast to be one-third higher, than they otherwise would be, due to projected carbon legislation.
• Average Malin natural gas prices are expected to be $7.36 per decatherm (levelized) over the next 20 years.
• Gas-fired resources continue to serve most new loads and take the place of
coal generation to reduce greenhouse gas emissions
• Society’s mandates to acquire new renewable resources help reduce carbon
emmisions, but force utilities to invest in twice as much generation infrastructure.
• New environment-driven investment, combined with higher market prices will lead to higher retail rates, absent federal initiatives to limit rate increases.
• Carbon legislation is expected to increase 20-year cost (NPV, 2009 dollars) for
electricity generation by $25.7 billion (10 percent) in the Western Interconnect.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 121 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-2 Avista Corp
Chapter 7- Market Analysis
Figure 7.1: NERC Interconnection Map
The Western Interconnect is separated from the Eastern Interconnect and ERCOT
systems except by eight inverter stations. The Western Interconnect follows operation
and reliability guidelines administered by the Western Electricity Coordinating Council
(WECC).
The Western Interconnect electric system is divided into 16 AURORAxmp modeling
zones based on load concentrations and transmission constraints. After extensive
study, Avista found that the Northwest is best modeled as a single zone. The single zone more accurately dispatches resources relative to splitting the Northwest into multiple areas. The regional topology in this IRP differs from the previous plan by
reverting to a single zone.
Fundamentals-based electricity models range in their abilities to emulate power system operations. Some account for every bus and transmission line while others utilize regions or zones. An IRP requires regional price and plant dispatch information. The
specific zones modeled are described in Table 7.1.
Avista Corp 2009 Electric IRP – Public Draft 7-2
Chapter 7- Market Analysis
Table 7.1: AURORAXMP Zones
Northwest- OR/WA/ID/MT Southern Idaho
Eastern Montana Wyoming
Northern California Southern California
Central California Arizona
Colorado New Mexico
British Columbia Alberta
North Nevada South Nevada
Utah Baja, Mexico
Western Interconnect Loads A load forecast was developed for each area of the Western Interconnect. Avista relied on external sources to quantify load growth across the west. These sources included
the integrated resource plans for Northwest utilities and Wood Mackenzie for the
remaining areas. Carbon legislation and associated price increases are expected to
reduce loads over time from their present trajectory. Wood Mackenzie forecasts loads to be one percent lower in 2020 and 4.6 percent lower in 2026 compared to projected
loads without carbon legislation.
Specific regional load growth levels are presented in Table 7.2. Overall Western Interconnect loads are forecast to rise by an average level of 1.6 percent over the next 20 years, from 106,727 aMW in 2010 to 146,579 aMW in 2029. A planning margin was
added to the load forecast to account for unplanned events. Regional planning margins
are assumed to be 25 percent in the winter in the Northwest, 17 percent for California,
and 15 percent for all other zones. Higher Northwest planning margins are needed to account for hydroelectric variability. Additional details about planning margins are in the
Loads and Resources chapter.
Table 7.2: 20-Year Annual Average Peak & Energy Load Growth Rates
Northwest Areas Growth Rate Other Areas Growth Rate
Eastern Oregon 0.01% California 1.51%
Eastern WA/North Idaho 1.39%Baja, Mexico 1.51%
Northwest Washington 1.69% Arizona 1.97%
Seattle Metro Area 1.69%South Nevada 1.97%
Portland Metro Area 1.74%North Nevada 2.18%
SW Washington 1.69%New Mexico 1.83%
Western Oregon 0.01% Colorado 1.48%
Central Washington 2.53% Wyoming 3.59%
South Idaho 1.31% Utah 1.91%
Western Montana 0.61% Alberta 2.00%
British Columbia 1.26%Eastern Montana 0.61%
Avista Corp 2009 Electric IRP – Public Draft 7-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 122 of 729
2009 Electric IRPAvista Corp 7-3
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.1: NERC Interconnection Map
The Western Interconnect is separated from the Eastern Interconnect and ERCOT
systems except by eight inverter stations. The Western Interconnect follows operation
and reliability guidelines administered by the Western Electricity Coordinating Council
(WECC).
The Western Interconnect electric system is divided into 16 AURORAxmp modeling
zones based on load concentrations and transmission constraints. After extensive
study, Avista found that the Northwest is best modeled as a single zone. The single zone more accurately dispatches resources relative to splitting the Northwest into multiple areas. The regional topology in this IRP differs from the previous plan by
reverting to a single zone.
Fundamentals-based electricity models range in their abilities to emulate power system operations. Some account for every bus and transmission line while others utilize regions or zones. An IRP requires regional price and plant dispatch information. The
specific zones modeled are described in Table 7.1.
Avista Corp 2009 Electric IRP – Public Draft 7-2
Chapter 7- Market Analysis
Table 7.1: AURORAXMP Zones
Northwest- OR/WA/ID/MT Southern Idaho
Eastern Montana Wyoming
Northern California Southern California
Central California Arizona
Colorado New Mexico
British Columbia Alberta
North Nevada South Nevada
Utah Baja, Mexico
Western Interconnect Loads A load forecast was developed for each area of the Western Interconnect. Avista relied on external sources to quantify load growth across the west. These sources included
the integrated resource plans for Northwest utilities and Wood Mackenzie for the
remaining areas. Carbon legislation and associated price increases are expected to
reduce loads over time from their present trajectory. Wood Mackenzie forecasts loads to be one percent lower in 2020 and 4.6 percent lower in 2026 compared to projected
loads without carbon legislation.
Specific regional load growth levels are presented in Table 7.2. Overall Western Interconnect loads are forecast to rise by an average level of 1.6 percent over the next 20 years, from 106,727 aMW in 2010 to 146,579 aMW in 2029. A planning margin was
added to the load forecast to account for unplanned events. Regional planning margins
are assumed to be 25 percent in the winter in the Northwest, 17 percent for California,
and 15 percent for all other zones. Higher Northwest planning margins are needed to account for hydroelectric variability. Additional details about planning margins are in the
Loads and Resources chapter.
Table 7.2: 20-Year Annual Average Peak & Energy Load Growth Rates
Northwest Areas Growth Rate Other Areas Growth Rate
Eastern Oregon 0.01% California 1.51%
Eastern WA/North Idaho 1.39%Baja, Mexico 1.51%
Northwest Washington 1.69% Arizona 1.97%
Seattle Metro Area 1.69%South Nevada 1.97%
Portland Metro Area 1.74%North Nevada 2.18%
SW Washington 1.69%New Mexico 1.83%
Western Oregon 0.01% Colorado 1.48%
Central Washington 2.53% Wyoming 3.59%
South Idaho 1.31% Utah 1.91%
Western Montana 0.61% Alberta 2.00%
British Columbia 1.26%Eastern Montana 0.61%
Avista Corp 2009 Electric IRP – Public Draft 7-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 123 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-4 Avista Corp
Chapter 7- Market Analysis
Transmission
Several regional transmission projects have been announced in the last two years.
Many of these projects will move renewable resources to load centers for renewable
portfolio standards (RPS) obligations. The AURORAxmp model was updated to reflect the 26,600 MW of transmission upgrades shown in Table 7.3. The transmission expansion represents the most likely upgrades at the time the price forecast was
developed (Dec 2008). Transmission upgrades within AURORAxmp zones were not
included in the model, as they do not impact power transactions between zones.
Table 7.3: Western Interconnect Transmission Upgrades Included in Analysis
Project From To
Year
Available
Capacity
MW
Canada – PNW Project British Columbia Northwest 2018 3,000
PNW – California Project Northwest California 2018 3,500
Eastern Nevada Intertie North Nevada South Nevada 2015 1,600
Colstrip Transmission Montana Northwest 2012 500
Gateway South Utah Nevada 2014 600
Gateway South Wyoming Utah 2015 3,000
Gateway Central Idaho Utah 2016 1,500
Sunzia/Navajo Transmission Arizona New Mexico 2013 3,000
Wyoming- Colorado Intertie Wyoming Colorado 2013 900
Gateway South Wyoming Utah 2015 3,000
Gateway West Wyoming Idaho 2016 3,000
Hemingway to Boardman Idaho Northwest 2015 1,500
Hemingway to Captain Jack Idaho Southern Oregon 2015 1,500
Total 26,600
Regional Renewable Portfolio Standards
In an effort to curb greenhouse gas emissions and diversify energy sources, many
states have created RPS requirements. RPS legislation requires utilities to meet a portion of their load with qualified renewable resources. Each state defines RPS
obligations differently. AURORAxmp does not have the ability to target RPS levels, so
RPS requirements were input into the model to ensure that renewable resource levels
satisfy state laws.
Avista Corp 2009 Electric IRP – Public Draft 7-4
Wind, the predominant renewable resource, does not add capacity to the electric
system. Wind plants are not likely to be able to recover all of their life-cycle costs from
the wholesale electricity marketplace. Renewable resource portfolios to meet Western
Interconnect RPS obligations were developed by the Northwest Power and Conservation Council (NPCC); these percentages were applied to estimated RPS
shortfalls in each state. California has the most aggressive RPS goal (33 percent by
2020). The 2009 IRP adopts the NPCC resource mix assumptions. Figure 7.2 illustrates
projected renewable resource additions to the Western Interconnect. Renewable resources were manually added only to meet RPS requirements, not exceed it.
Chapter 7- Market Analysis
AURORAxmp could have added additional renewable resources where they were found
to be economical as part of its optimization routine, but it did not.
Figure 7.2 illustrates the difference between nameplate capacity and the delivered energy of the RPS additions. Most renewable energy requirements are met by wind,
with a smaller contribution from solar. Geothermal, biomass and hydro resources fill
remaining RPS needs. The renewable resource choices differ by state consistent with
their respective laws. The Southwest will meet requirements with solar and wind; the Northwest will use wind and hydro; and the Rocky Mountain states will predominately use wind to meet RPS needs.
Figure 7.2: Renewable Resource Additions to Meet RPS
0
10
20
30
40
50
60
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
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1
9
20
2
0
20
2
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20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
gi
g
a
w
a
t
t
s
Solar
Hydro
Geothermal
Biomass
Wind
Energy (aGW)
Resource Deficits
Assumptions are made on when, where and how many of each new resource type will be added to meet peak demand in order to forecast electricity market prices. New renewable resources meet energy needs, but add a much smaller level of capacity to
the system so that each megawatt of additional wind requires an additional resource to
provide dependable capacity. In line with the NPCC assumptions, wind is assumed to
provide five percent of its nameplate capacity to meet regional peak demand periods in the IRP price forecast analysis.
Avista Corp 2009 Electric IRP – Public Draft 7-5
The Northwest historically has depended on hydro system flexibility to meet peak
demand, but new wind regulation obligations and increased fisheries obligations have constrained the system. The hydro system can flex for a few hours during a cold day, but may not have the energy to meet a cold or hot weather event lasting several days.
AURORAxmp adds resources to meet one hour system peaks. To simulate a sustained
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 124 of 729
2009 Electric IRPAvista Corp 7-5
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Transmission
Several regional transmission projects have been announced in the last two years.
Many of these projects will move renewable resources to load centers for renewable
portfolio standards (RPS) obligations. The AURORAxmp model was updated to reflect the 26,600 MW of transmission upgrades shown in Table 7.3. The transmission expansion represents the most likely upgrades at the time the price forecast was
developed (Dec 2008). Transmission upgrades within AURORAxmp zones were not
included in the model, as they do not impact power transactions between zones.
Table 7.3: Western Interconnect Transmission Upgrades Included in Analysis
ProjectFromTo
Year
Available
Capacity
MW
Canada – PNW Project British Columbia Northwest2018 3,000
PNW – California Project Northwest California2018 3,500
Eastern Nevada Intertie North Nevada South Nevada 2015 1,600
Colstrip Transmission MontanaNorthwest2012 500
Gateway South UtahNevada2014600
Gateway South Wyoming Utah2015 3,000
Gateway Central IdahoUtah2016 1,500
Sunzia/Navajo Transmission ArizonaNew Mexico 2013 3,000
Wyoming- Colorado Intertie Wyoming Colorado2013 900
Gateway South Wyoming Utah2015 3,000
Gateway West Wyoming Idaho2016 3,000
Hemingway to Boardman IdahoNorthwest2015 1,500
Hemingway to Captain Jack IdahoSouthern Oregon 2015 1,500
Total26,600
Regional Renewable Portfolio Standards
In an effort to curb greenhouse gas emissions and diversify energy sources, many
states have created RPS requirements. RPS legislation requires utilities to meet a portion of their load with qualified renewable resources. Each state defines RPS
obligations differently. AURORAxmp does not have the ability to target RPS levels, so
RPS requirements were input into the model to ensure that renewable resource levels
satisfy state laws.
Avista Corp 2009 Electric IRP – Public Draft 7-4
Wind, the predominant renewable resource, does not add capacity to the electric
system. Wind plants are not likely to be able to recover all of their life-cycle costs from
the wholesale electricity marketplace. Renewable resource portfolios to meet Western
Interconnect RPS obligations were developed by the Northwest Power and Conservation Council (NPCC); these percentages were applied to estimated RPS
shortfalls in each state. California has the most aggressive RPS goal (33 percent by
2020). The 2009 IRP adopts the NPCC resource mix assumptions. Figure 7.2 illustrates
projected renewable resource additions to the Western Interconnect. Renewable resources were manually added only to meet RPS requirements, not exceed it.
Chapter 7- Market Analysis
AURORAxmp could have added additional renewable resources where they were found
to be economical as part of its optimization routine, but it did not.
Figure 7.2 illustrates the difference between nameplate capacity and the delivered energy of the RPS additions. Most renewable energy requirements are met by wind,
with a smaller contribution from solar. Geothermal, biomass and hydro resources fill
remaining RPS needs. The renewable resource choices differ by state consistent with
their respective laws. The Southwest will meet requirements with solar and wind; the Northwest will use wind and hydro; and the Rocky Mountain states will predominately use wind to meet RPS needs.
Figure 7.2: Renewable Resource Additions to Meet RPS
0
10
20
30
40
50
60
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
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20
2
2
20
2
3
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2
4
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2
5
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2
6
20
2
7
20
2
8
20
2
9
gi
g
a
w
a
t
t
s
Solar
Hydro
Geothermal
Biomass
Wind
Energy (aGW)
Resource Deficits
Assumptions are made on when, where and how many of each new resource type will be added to meet peak demand in order to forecast electricity market prices. New renewable resources meet energy needs, but add a much smaller level of capacity to
the system so that each megawatt of additional wind requires an additional resource to
provide dependable capacity. In line with the NPCC assumptions, wind is assumed to
provide five percent of its nameplate capacity to meet regional peak demand periods in the IRP price forecast analysis.
Avista Corp 2009 Electric IRP – Public Draft 7-5
The Northwest historically has depended on hydro system flexibility to meet peak
demand, but new wind regulation obligations and increased fisheries obligations have constrained the system. The hydro system can flex for a few hours during a cold day, but may not have the energy to meet a cold or hot weather event lasting several days.
AURORAxmp adds resources to meet one hour system peaks. To simulate a sustained
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 125 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-6 Avista Corp
Chapter 7- Market Analysis
peaking event exceeding one hour, the amount of hydro available to meet system peaks was decreased by approximately one-third. Figure 7.3 illustrates the Northwest resource shortfall. Blue bars represent the capacity contributions of hydro, thermal and other
resources. The black line represents forecasted winter peak load plus net firm transfers
from outside the region (net load). The red line is the net load with a 25 percent
planning margin. Based on these assumptions, the Northwest region is deficit beginning in 2015; individual utility needs may differ. Avista’s resource position was described in Chapter Two.
Figure 7.3: Northwest Peak Load/Resource Balance
20
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Resource Capacity
Peak Load w/ Planning Margin
Peak Load
Outside the Northwest, resources and loads are more closely aligned with deficits in some areas beginning in 2010. Figure 7.4 sums capacity deficits for the entire Western
Interconnect; nearly 10 gigawatts (GW) of capacity are needed in 2010, 38 GW are
needed in 2020 and 62 GW are needed in 2029.
Avista Corp 2009 Electric IRP – Public Draft 7-6
Chapter 7- Market Analysis
Figure 7.4: Total Western Interconnect Capacity Deficits
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New Resource Options
The resource deficits shown in Figure 7.4 must be met by resources with dependable
capacity, including gas-fired CCCT or SCCT, coal IGCC, coal with carbon sequestration, solar, nuclear and traditional pulverized coal plants. Table 7.4 shows resource options available to fill deficits in different regions.
Table 7.4: New Resources Available to Meet Resource Deficits
Region
CCCT/
SCCT Wind Solar Nuclear
Pulv.
Coal
IGCC
Coal
IGCCCoal w/
CO2 Seq.
Northwest Unlimited Tier 2 Unlimited 2022 n/a n/a 2025
California Unlimited Tier 2 Unlimited n/a n/a n/a 2025
Desert SW Unlimited Tier 2 Unlimited 2022 n/a n/a 2025
Rocky Mountains Unlimited Tier 1 Unlimited 2022 n/a 2015 2025
Canada Unlimited Tier 1 Unlimited 2022 2015 2015 2025
Fuel Prices and Conditions
Avista Corp 2009 Electric IRP – Public Draft 7-7
Some of the most important drivers of resource costs and values are fuel and
availability. Some resources, including geothermal and biomass, have limited fuel
options or sources, while coal and natural gas have more fuel sources. Hydro and wind
use free fuel sources, but are highly dependent on weather.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 126 of 729
2009 Electric IRPAvista Corp 7-7
Chapter 7 - Market Analysis
Chapter 7- Market Analysis
peaking event exceeding one hour, the amount of hydro available to meet system peaks was decreased by approximately one-third. Figure 7.3 illustrates the Northwest resource shortfall. Blue bars represent the capacity contributions of hydro, thermal and other
resources. The black line represents forecasted winter peak load plus net firm transfers
from outside the region (net load). The red line is the net load with a 25 percent
planning margin. Based on these assumptions, the Northwest region is deficit beginning in 2015; individual utility needs may differ. Avista’s resource position was described in Chapter Two.
Figure 7.3: Northwest Peak Load/Resource Balance
20
25
30
35
40
45
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Resource Capacity
Peak Load w/ Planning Margin
Peak Load
Outside the Northwest, resources and loads are more closely aligned with deficits in some areas beginning in 2010. Figure 7.4 sums capacity deficits for the entire Western
Interconnect; nearly 10 gigawatts (GW) of capacity are needed in 2010, 38 GW are
needed in 2020 and 62 GW are needed in 2029.
Avista Corp 2009 Electric IRP – Public Draft 7-6
Chapter 7- Market Analysis
Figure 7.4: Total Western Interconnect Capacity Deficits
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New Resource Options
The resource deficits shown in Figure 7.4 must be met by resources with dependable
capacity, including gas-fired CCCT or SCCT, coal IGCC, coal with carbon sequestration, solar, nuclear and traditional pulverized coal plants. Table 7.4 shows resource options available to fill deficits in different regions.
Table 7.4: New Resources Available to Meet Resource Deficits
Region
CCCT/
SCCT Wind Solar Nuclear
Pulv.
Coal
IGCC
Coal
IGCCCoal w/
CO2 Seq.
Northwest Unlimited Tier 2 Unlimited 2022 n/a n/a 2025
California Unlimited Tier 2 Unlimited n/a n/a n/a 2025
Desert SW Unlimited Tier 2 Unlimited 2022 n/a n/a 2025
Rocky Mountains Unlimited Tier 1 Unlimited 2022 n/a 2015 2025
Canada Unlimited Tier 1 Unlimited 2022 2015 2015 2025
Fuel Prices and Conditions
Avista Corp 2009 Electric IRP – Public Draft 7-7
Some of the most important drivers of resource costs and values are fuel and
availability. Some resources, including geothermal and biomass, have limited fuel
options or sources, while coal and natural gas have more fuel sources. Hydro and wind
use free fuel sources, but are highly dependent on weather.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 127 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-8 Avista Corp
Chapter 7- Market Analysis
Natural Gas
The fuel of choice for new base load and peaking resources continues to be natural
gas. The largest drawback to natural gas is its high price volatility. Avista used forward market prices and a combination of independent sources including the Energy
Information Administration (EIA), the New York Mercantile Exchange and Wood
Mackenzie through 2011. Wood Mackenzie prices were used from 2013 through 2029.
2012 prices used the average of 2011 and 2013.
The natural gas price forecast was completed in December 2008. It was adjusted for the
expected impacts of carbon legislation. Such legislation will cause the demand for
natural gas to increase as generation shifts from coal. The increase is estimated to be
$0.50 per Dth in 2013 and $1.00 per Dth after 2018 (2009 dollars).
Economic recovery should absorb excess productive capacity for natural gas and increase
overall demand growth by 2014. Carbon legislation also will spur incremental demand for a
multi-year cycle of gas-fired generation construction. This increased demand, combined with low investments in drilling in prior years, should push prices higher. The Frontier Gas Pipeline (1 bcfd) from Alberta to Chicago should also be operational by the end of the next
decade. Figure 7.5 shows the price forecast for Henry Hub; the levelized nominal price is
$9.05 per Dth and the real levelized cost is $7.67 per Dth.
Figure 7.5: Henry Hub Natural Gas Price Forecast
5.0
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Nominal
2009 Dollars
Avista Corp 2009 Electric IRP – Public Draft 7-8
Prices differences across North America depend on demand at various trading hubs
and the pipeline constraints between trading hubs. Many pipeline projects have been
Chapter 7- Market Analysis
announced to access cheaper gas supplies located in the Rocky Mountains. Table 7.5
presents western gas basin differentials from Henry Hub and the levelized price of gas
at each basin. Prices converge as new pipelines are built and new sources of gas come
online. To illustrate the seasonality of natural gas prices, the monthly Malin price shape is provided in Table 7.6 for select years.
Table 7.5: Natural Gas Price Basin Differentials from Henry Hub (Nominal Dollars)
Basin 2010 2015 2020 2025
NominalLevelizedCost
2009$LevelizedCosts
Henry Hub $9.05 $7.67
Opal -2.46 -0.61 -0.68 -0.58 $8.11 $6.88
San Juan -0.26 -0.10 -0.08 0.39 $9.08 $7.70
Southern CA -0.32 -0.15 -0.19 1.42 $9.11 $7.73
Malin -0.51 -0.24 -0.32 -0.49 $8.64 $7.33
Sumas -0.51 -0.20 -0.26 -0.36 $8.70 $7.38
AECO -0.61 -0.31 -0.42 -0.67 $8.54 $7.24
Table 7.6: Monthly Price Differentials for Malin
Month 2010 2015 2020 2025
Jan 103.7% 99.8% 105.0% 106.9%
Feb 104.7% 104.9% 109.4% 107.6%
Mar 100.7% 103.7% 104.6% 101.8%
Apr 92.3% 90.6% 94.7% 93.4%
May 92.5% 94.2% 95.4% 94.1%
Jun 94.1% 93.6% 96.0% 94.8%
Jul 95.0% 96.4% 97.8% 95.9%
Aug 95.9% 97.1% 97.8% 96.4%
Sep 97.5% 97.7% 95.2% 97.4%
Oct 98.1% 98.8% 95.3% 97.6%
Nov 112.6% 111.0% 104.1% 106.7%
Dec 113.0% 112.0% 104.7% 107.4%
Coal
Coal transportation prices for existing facilities are based on estimates contained in the AURORAxmp database. For new projects, coal mine costs are based on data provided by the EIA for Wyoming mine-mouth coal. Transportation costs were added based on
assumed transportation rates and each existing or proposed plant’s distance from the
coal supply source. The IRP includes three representative coal plant delivery distances for all new plants: mine mouth, short haul (250 miles) and long haul (1,000 miles). Coal details are in Table 7.7.
Avista Corp 2009 Electric IRP – Public Draft 7-9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 128 of 729
2009 Electric IRPAvista Corp 7-9
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Natural Gas
The fuel of choice for new base load and peaking resources continues to be natural
gas. The largest drawback to natural gas is its high price volatility. Avista used forward market prices and a combination of independent sources including the Energy
Information Administration (EIA), the New York Mercantile Exchange and Wood
Mackenzie through 2011. Wood Mackenzie prices were used from 2013 through 2029.
2012 prices used the average of 2011 and 2013.
The natural gas price forecast was completed in December 2008. It was adjusted for the
expected impacts of carbon legislation. Such legislation will cause the demand for
natural gas to increase as generation shifts from coal. The increase is estimated to be
$0.50 per Dth in 2013 and $1.00 per Dth after 2018 (2009 dollars).
Economic recovery should absorb excess productive capacity for natural gas and increase
overall demand growth by 2014. Carbon legislation also will spur incremental demand for a
multi-year cycle of gas-fired generation construction. This increased demand, combined with low investments in drilling in prior years, should push prices higher. The Frontier Gas Pipeline (1 bcfd) from Alberta to Chicago should also be operational by the end of the next
decade. Figure 7.5 shows the price forecast for Henry Hub; the levelized nominal price is
$9.05 per Dth and the real levelized cost is $7.67 per Dth.
Figure 7.5: Henry Hub Natural Gas Price Forecast
5.0
6.0
7.0
8.0
9.0
10.0
11.0
12.0
13.0
14.0
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Nominal
2009 Dollars
Avista Corp 2009 Electric IRP – Public Draft 7-8
Prices differences across North America depend on demand at various trading hubs
and the pipeline constraints between trading hubs. Many pipeline projects have been
Chapter 7- Market Analysis
announced to access cheaper gas supplies located in the Rocky Mountains. Table 7.5
presents western gas basin differentials from Henry Hub and the levelized price of gas
at each basin. Prices converge as new pipelines are built and new sources of gas come
online. To illustrate the seasonality of natural gas prices, the monthly Malin price shape is provided in Table 7.6 for select years.
Table 7.5: Natural Gas Price Basin Differentials from Henry Hub (Nominal Dollars)
Basin 2010 2015 2020 2025
NominalLevelizedCost
2009$LevelizedCosts
Henry Hub $9.05 $7.67
Opal -2.46 -0.61 -0.68 -0.58 $8.11 $6.88
San Juan -0.26 -0.10 -0.08 0.39 $9.08 $7.70
Southern CA -0.32 -0.15 -0.19 1.42 $9.11 $7.73
Malin -0.51 -0.24 -0.32 -0.49 $8.64 $7.33
Sumas -0.51 -0.20 -0.26 -0.36 $8.70 $7.38
AECO -0.61 -0.31 -0.42 -0.67 $8.54 $7.24
Table 7.6: Monthly Price Differentials for Malin
Month 2010 2015 2020 2025
Jan 103.7% 99.8% 105.0% 106.9%
Feb 104.7% 104.9% 109.4% 107.6%
Mar 100.7% 103.7% 104.6% 101.8%
Apr 92.3% 90.6% 94.7% 93.4%
May 92.5% 94.2% 95.4% 94.1%
Jun 94.1% 93.6% 96.0% 94.8%
Jul 95.0% 96.4% 97.8% 95.9%
Aug 95.9% 97.1% 97.8% 96.4%
Sep 97.5% 97.7% 95.2% 97.4%
Oct 98.1% 98.8% 95.3% 97.6%
Nov 112.6% 111.0% 104.1% 106.7%
Dec 113.0% 112.0% 104.7% 107.4%
Coal
Coal transportation prices for existing facilities are based on estimates contained in the AURORAxmp database. For new projects, coal mine costs are based on data provided by the EIA for Wyoming mine-mouth coal. Transportation costs were added based on
assumed transportation rates and each existing or proposed plant’s distance from the
coal supply source. The IRP includes three representative coal plant delivery distances for all new plants: mine mouth, short haul (250 miles) and long haul (1,000 miles). Coal details are in Table 7.7.
Avista Corp 2009 Electric IRP – Public Draft 7-9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 129 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-10 Avista Corp
Chapter 7- Market Analysis
Table 7.7: Western Interconnect Coal Prices (2009$)
Coal type $/MMBtu $/short ton
Mine mouth $0.73 $12.41
Short haul $1.26 $21.34
Long haul $2.83 $48.11
Wood/Hog Fuel Avista has operated the Kettle Falls wood-fired generator for 25 years. When Kettle
Falls was constructed, hog fuel was a waste product from area sawmills at low or no
cost. The future price and availability of hog fuel are critical to understanding the viability
of new wood-fired facilities. Hog fuel costs for new plants are forecasted for two locations. The first is fuel in Avista’s service territory, forecast at $30 per ton or $3.30
per MMBtu in real 2009 dollars. The second fuel forecast is for the Boardman, Oregon
area for a Coyote Spring 2 wood addition, where the price is estimated to be $60 per
ton or $6.60 per MMBtu (2009$). Hog fuel availability is highly dependent on lumber demand. The Kettle Falls plant had surplus fuel in the mid-2000s, but the plant has struggled to find enough economically priced fuel over the past two years.
Hydro
The Northwest and British Columbia have substantial hydroelectric generation capacity. A favorable characteristic of hydro power is its ability to provide short periods of near-
instantaneous generation. This characteristic is particularly valuable for meeting peak
load demands, following general intra-day load trends, shaping energy for sale during
higher-valued peak hours and integrating wind generation. The key drawback to hydro is its lack of predictable energy on a year-to-year or seasonal basis. Hydro is constrained by weather patterns and subsequent stream flows. The amount of energy
available at a particular plant depends on river system characteristics.
The IRP uses the Northwest Power Pool’s (NWPP) 2007-08 Headwater Benefit Study to model regional hydro availability. The NWPP study provides energy levels for each
hydroelectric plant by month from 1928 to 1999. British Columbia plants are modeled
using data from the Canadian government.
Many of the analyses in this IRP use an average of the 70-year hydroelectric record; whereas stochastic studies randomly draw from the 70-year record (see Risk Analysis
later in this chapter). Hydroelectric plants are divided into geographic regions and
represented as a single plant in each zone. The Company models its own projects
individually to provide greater detail about its resources. Table 7.8 shows average assumed hydro capacity factors for the Northwest hydroelectric plants.
Avista Corp 2009 Electric IRP – Public Draft 7-10
Chapter 7- Market Analysis
Table 7.8: Northwest Hydro Capacity Factors
Area
Annual Average
Capacity Factor
Eastern Oregon 42%
Eastern WA/North Idaho 43%
Northwest Washington 40%
Portland Metro Area 41%
SW Washington 38%
Western Oregon 31%
Central Washington 46%
South Idaho 44%
Western Montana 42%
British Columbia 64%
AURORAxmp represents hydroelectric plants using annual and monthly capacity
factors, minimum and maximum generation levels, and sustained peaking generation
capabilities. The model’s objective, subject to constraints, is to move hydroelectric generation into peak hours to follow daily load changes. This objective maximizes the value of the system consistent with actual operations.
Wind and Solar
As additional wind and solar capacity is added to the electric system to satisfy renewable portfolio standards, there will be significant competition for higher quality
wind and solar sites. The capacity factors in Table 7.9 present average generation for
the entire area, not specific projects. The Rocky Mountain area is the best location for
wind generation and the desert Southwest is best for solar generation.
Table 7.9: Western Interconnect Wind Capacity Factors
Area WindCF (%)
Solar
CF(%) Area
Wind
CF(%) SolarCF (%)
Montana 37.36 19.63 Colorado 34.32 25.23
Canada 36.29 16.82 New Mexico 33.09 25.23
Wyoming 36.13 19.63 South Nevada 33.05 28.04
South Idaho 34.91 22.43 Northwest 32.77 19.63
Utah 34.85 22.43 South California 31.20 25.23
Arizona 32.39 25.23 North California 28.97 19.63
North Nevada 34.56 22.43 Baja, Mexico 31.20 28.04
Greenhouse Gas Emissions
Avista Corp 2009 Electric IRP – Public Draft 7-11
Greenhouse gas or CO2 legislation is one the greatest fundamental risks facing the
electricity marketplace today. Reducing CO2 emissions from power plants will change
the resource mix over time as society moves away from traditional resources and shifts
to an increased reliance on renewable resources. There is currently no federal regulation of carbon emissions, but national legislation is expected to pass in the next
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 130 of 729
2009 Electric IRPAvista Corp 7-11
Chapter 7 - Market Analysis
Chapter 7- Market Analysis
Table 7.7: Western Interconnect Coal Prices (2009$)
Coal type $/MMBtu$/short ton
Mine mouth $0.73 $12.41
Short haul $1.26 $21.34
Long haul $2.83 $48.11
Wood/Hog Fuel Avista has operated the Kettle Falls wood-fired generator for 25 years. When Kettle
Falls was constructed, hog fuel was a waste product from area sawmills at low or no
cost. The future price and availability of hog fuel are critical to understanding the viability
of new wood-fired facilities. Hog fuel costs for new plants are forecasted for two locations. The first is fuel in Avista’s service territory, forecast at $30 per ton or $3.30
per MMBtu in real 2009 dollars. The second fuel forecast is for the Boardman, Oregon
area for a Coyote Spring 2 wood addition, where the price is estimated to be $60 per
ton or $6.60 per MMBtu (2009$). Hog fuel availability is highly dependent on lumber demand. The Kettle Falls plant had surplus fuel in the mid-2000s, but the plant has struggled to find enough economically priced fuel over the past two years.
Hydro
The Northwest and British Columbia have substantial hydroelectric generation capacity. A favorable characteristic of hydro power is its ability to provide short periods of near-
instantaneous generation. This characteristic is particularly valuable for meeting peak
load demands, following general intra-day load trends, shaping energy for sale during
higher-valued peak hours and integrating wind generation. The key drawback to hydro is its lack of predictable energy on a year-to-year or seasonal basis. Hydro is constrained by weather patterns and subsequent stream flows. The amount of energy
available at a particular plant depends on river system characteristics.
The IRP uses the Northwest Power Pool’s (NWPP) 2007-08 Headwater Benefit Study to model regional hydro availability. The NWPP study provides energy levels for each
hydroelectric plant by month from 1928 to 1999. British Columbia plants are modeled
using data from the Canadian government.
Many of the analyses in this IRP use an average of the 70-year hydroelectric record; whereas stochastic studies randomly draw from the 70-year record (see Risk Analysis
later in this chapter). Hydroelectric plants are divided into geographic regions and
represented as a single plant in each zone. The Company models its own projects
individually to provide greater detail about its resources. Table 7.8 shows average assumed hydro capacity factors for the Northwest hydroelectric plants.
Avista Corp 2009 Electric IRP – Public Draft 7-10
Chapter 7- Market Analysis
Table 7.8: Northwest Hydro Capacity Factors
Area
Annual Average
Capacity Factor
Eastern Oregon 42%
Eastern WA/North Idaho 43%
Northwest Washington 40%
Portland Metro Area 41%
SW Washington 38%
Western Oregon 31%
Central Washington 46%
South Idaho 44%
Western Montana 42%
British Columbia 64%
AURORAxmp represents hydroelectric plants using annual and monthly capacity
factors, minimum and maximum generation levels, and sustained peaking generation
capabilities. The model’s objective, subject to constraints, is to move hydroelectric generation into peak hours to follow daily load changes. This objective maximizes the value of the system consistent with actual operations.
Wind and Solar
As additional wind and solar capacity is added to the electric system to satisfy renewable portfolio standards, there will be significant competition for higher quality
wind and solar sites. The capacity factors in Table 7.9 present average generation for
the entire area, not specific projects. The Rocky Mountain area is the best location for
wind generation and the desert Southwest is best for solar generation.
Table 7.9: Western Interconnect Wind Capacity Factors
Area WindCF (%)
Solar
CF(%) Area
Wind
CF(%) SolarCF (%)
Montana 37.36 19.63 Colorado 34.32 25.23
Canada 36.29 16.82 New Mexico 33.09 25.23
Wyoming 36.13 19.63 South Nevada 33.05 28.04
South Idaho 34.91 22.43 Northwest 32.77 19.63
Utah 34.85 22.43 South California 31.20 25.23
Arizona 32.39 25.23 North California 28.97 19.63
North Nevada 34.56 22.43 Baja, Mexico 31.20 28.04
Greenhouse Gas Emissions
Avista Corp 2009 Electric IRP – Public Draft 7-11
Greenhouse gas or CO2 legislation is one the greatest fundamental risks facing the
electricity marketplace today. Reducing CO2 emissions from power plants will change
the resource mix over time as society moves away from traditional resources and shifts
to an increased reliance on renewable resources. There is currently no federal regulation of carbon emissions, but national legislation is expected to pass in the next
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 131 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-12 Avista Corp
Chapter 7- Market Analysis
few years. In the interim, several western states and provinces are promoting the
Western Climate Initiative to develop a multi-jurisdictional greenhouse gas reduction
program. Whether or not a federal system will ultimately supersede these efforts is not
known.
The Wood Mackenzie carbon price forecast was used in this IRP. Wood Mackenzie
considered this forecast as it developed its other commodity price forecasts. Carbon
prices ultimately will depend on greenhouse gas reduction goals, the supply and cost of allowances and offsets, and the price of natural gas. The only way to greatly reduce power plant carbon emissions is to price carbon at a level high enough to greatly reduce
the dispatch of coal-fired plants.
Wood Mackenzie based its carbon price forecast on November 2008 legislation sponsored by Representatives Dingell and Boucher. Their macro-economic models were balanced by identifying a carbon price forecast adequate to meet federal emission
goals. The analysis included new nuclear and carbon sequestration resources to meet
future load growth in the 2020’s. Figure 7.6 shows the carbon price forecast. The IRP assumes carbon will have a cost starting in 2012. The price trajectory increases greatly in 2018 as the next major step in carbon reduction goals begins. The 20-year levelized
cost of carbon is $46.14 (nominal) and $33.37 (2009 dollars). When natural gas prices
rise or fall, the cost of carbon is expected to change to balance the relative
competitiveness of gas and coal.
The only way to reduce carbon emissions from electric generation below existing levels
under a cap-and-trade model is to increase carbon prices to a level making the marginal
cost of a coal plant higher than a natural gas-fired resource. For example, a natural gas plant facing a $7.50 per Dth natural gas price will require a carbon price of approximately $60 per short ton to make its dispatch attractive relative to a coal plant
with $1.00 per MMBtu fuel. Figure 7.7 illustrates carbon price levels that would be
necessary at various natural gas and coal prices to allow natural gas generation to displace coal. The crossover points between the “dashed” coal and “solid” natural gas marginal cost estimates represent the price of carbon that makes the two resources
equal in dispatch cost.
Avista Corp 2009 Electric IRP – Public Draft 7-12
Chapter 7- Market Analysis
Figure 7.6: Price of Carbon Credits
$0
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$40
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$80
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$120
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Nominal
2009 Dollars
Figure 7.7: Cost of Carbon Credits
Avista Corp 2009 Electric IRP – Public Draft 7-13
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
$0
$1
0
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ca
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Coal- $1.00
Coal- $3.00
CCCT- $7.50 Gas
CCCT- $5.00 Gas
CCCT- $10.00 Gas
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 132 of 729
2009 Electric IRPAvista Corp 7-13
Chapter 7 - Market Analysis
Chapter 7- Market Analysis
few years. In the interim, several western states and provinces are promoting the
Western Climate Initiative to develop a multi-jurisdictional greenhouse gas reduction
program. Whether or not a federal system will ultimately supersede these efforts is not
known.
The Wood Mackenzie carbon price forecast was used in this IRP. Wood Mackenzie
considered this forecast as it developed its other commodity price forecasts. Carbon
prices ultimately will depend on greenhouse gas reduction goals, the supply and cost of allowances and offsets, and the price of natural gas. The only way to greatly reduce power plant carbon emissions is to price carbon at a level high enough to greatly reduce
the dispatch of coal-fired plants.
Wood Mackenzie based its carbon price forecast on November 2008 legislation sponsored by Representatives Dingell and Boucher. Their macro-economic models were balanced by identifying a carbon price forecast adequate to meet federal emission
goals. The analysis included new nuclear and carbon sequestration resources to meet
future load growth in the 2020’s. Figure 7.6 shows the carbon price forecast. The IRP assumes carbon will have a cost starting in 2012. The price trajectory increases greatly in 2018 as the next major step in carbon reduction goals begins. The 20-year levelized
cost of carbon is $46.14 (nominal) and $33.37 (2009 dollars). When natural gas prices
rise or fall, the cost of carbon is expected to change to balance the relative
competitiveness of gas and coal.
The only way to reduce carbon emissions from electric generation below existing levels
under a cap-and-trade model is to increase carbon prices to a level making the marginal
cost of a coal plant higher than a natural gas-fired resource. For example, a natural gas plant facing a $7.50 per Dth natural gas price will require a carbon price of approximately $60 per short ton to make its dispatch attractive relative to a coal plant
with $1.00 per MMBtu fuel. Figure 7.7 illustrates carbon price levels that would be
necessary at various natural gas and coal prices to allow natural gas generation to displace coal. The crossover points between the “dashed” coal and “solid” natural gas marginal cost estimates represent the price of carbon that makes the two resources
equal in dispatch cost.
Avista Corp 2009 Electric IRP – Public Draft 7-12
Chapter 7- Market Analysis
Figure 7.6: Price of Carbon Credits
$0
$20
$40
$60
$80
$100
$120
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Nominal
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Figure 7.7: Cost of Carbon Credits
Avista Corp 2009 Electric IRP – Public Draft 7-13
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
$0
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Coal- $1.00
Coal- $3.00
CCCT- $7.50 Gas
CCCT- $5.00 Gas
CCCT- $10.00 Gas
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 133 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-14 Avista Corp
Chapter 7- Market Analysis
Risk Analysis
Base assumptions in this chapter were modeled stochastically to reflect that we do not
know what future conditions will actually be. All Base Case assumptions discussed
earlier in this chapter represent expected values, not their expected ranges over time. Some market drivers are correlated. For example, higher natural gas prices will likely require higher carbon prices to ensure that carbon reduction goals are met. The
increased costs will cause a subsequent load decrease and affect other fuel prices
(e.g., hog fuel price might increase as generators chose to burn more of this fuel to
avoid higher carbon prices). Table 7.10 illustrates correlations between variables in the IRP. The relationships between variables were developed to show expected levels of
cause and effect, not on the results of statistical analysis. Market data does not exist for
many of these relationships, so Avista made the assumptions shown in Table 7.10.
Table 7.10: Stochastic Study Correlation Matrix
Natural
Gas
Prices
GHG
Prices
New
Coal
Prices
Hog
Fuel
Prices
Load
Growth
Gas Prices 1
GHG Prices 0.50 1
New Coal Prices -0.25 1
Hog Fuel Prices 0.50 0.50 1
Load Growth -0.25 -0.25 -0.5 1
Wind, hydro and forced outages are not necessarily correlated to other market drivers.
The stochastic study portion of the IRP includes 250 combinations of these variables;
500 combinations were studied, but no difference in the mean and standard deviation of the results was found.
Greenhouse (GHG) Prices
Without established federal legislation, and no formal rules for western carbon markets, the expected price of GHG emissions is difficult to determine without macroeconomic models capable of determining financial impacts outside of the electric industry. Even
with rules in place, carbon prices will be determined based on the tradeoff and
interaction between natural gas and coal prices. The lack of certainty means that a
range of potential prices needs to be modeled. This IRP utilized ten EPA scenarios as possible legislative outcomes. The EPA scenarios were developed for the Lieberman-Warner bill, the leading federal greenhouse gas legislation at the time the modeling for
this IRP was developed. Each scenario was given a weighting (see Table 7.11) by
members of Avista’s Climate Change Committee. For the scholastic price forecast, the assigned weight will be the probability of a certain base price level.
Avista Corp 2009 Electric IRP – Public Draft 7-14
Chapter 7- Market Analysis
Table 7.11: EPA Carbon Study (Nominal Price per Short/Ton)
Study Weight 2012 2020 2025
ADAGE 10% 28.60 50.89 72.40
IGEM 3% 40.50 70.15 98.04
ADAGE - Low Intl Action 15% 26.20 48.14 66.36
IGEM Unlimited Offsets 10% 8.70 20.63 28.66
IGEM with No Offsets 2% 80.80 134.79 190.04
ADAGE Scenario 6 3% 39.70 67.39 95.02
ADAGE Scenario 7 2% 57.20 94.90 132.73
Alt. Ref. ADAGE 35% 21.00 38.51 54.30
Alt. Ref. IGEM 5% 35.00 61.89 85.97
1766 ADAGE 15% 10.20 20.63 28.66
Weighted Average 100% 23.46 42.76 59.91
The EPA and Wood Mackenzie studies differ in many aspects, but the major difference
between the two is their assumed natural gas price forecast. To adjust for these differences, 10 price scenarios were developed for the stochastic portion of the IRP. See Table 7.12 for the 10 base carbon scenarios modeled for this IRP.
Table 7.12: Ten Cost Scenarios Based on Wood Mackenzie and EPA Studies
(Nominal Price per Short Ton)
Scenario Weight 2012 2020 2025
1 10% 8.01 68.28 96.89
2 3% 11.31 94.12 131.21
3 15% 7.32 64.59 88.82
4 10% 2.42 27.68 38.35
5 2% 22.56 180.86 254.34
6 3% 11.09 90.43 127.17
7 2% 15.97 127.34 177.63
8 35% 5.86 51.67 72.67
9 5% 9.77 83.05 115.06
10 15% 2.85 27.68 38.35
Weighted Average 100% 6.55 57.37 80.18
The carbon price is determined in a two-step process. The first step draws the carbon
price regime; the second step adjusts natural gas prices and other variables. The
adjustment keeps prices correlated so the market effect is consistent. See Figure 7.8 for the carbon price distribution for the 250 iterations in 2012. Carbon prices range from $1 to $35 per short ton, with an average of $6.55 per short ton. The standard deviations of
carbon prices in 2012, 2014, 2016 and beyond are 50 percent, 25 percent and ten
percent respectively.
Avista Corp 2009 Electric IRP – Public Draft 7-15
The correlation between carbon and natural gas is likely to be high because gas-fired
resources set the marginal price of electricity in most markets. A 50-percent correlation
between carbon and natural gas is used for this IRP. A 90-percent correlation scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 134 of 729
2009 Electric IRPAvista Corp 7-15
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Risk Analysis
Base assumptions in this chapter were modeled stochastically to reflect that we do not
know what future conditions will actually be. All Base Case assumptions discussed
earlier in this chapter represent expected values, not their expected ranges over time. Some market drivers are correlated. For example, higher natural gas prices will likely require higher carbon prices to ensure that carbon reduction goals are met. The
increased costs will cause a subsequent load decrease and affect other fuel prices
(e.g., hog fuel price might increase as generators chose to burn more of this fuel to
avoid higher carbon prices). Table 7.10 illustrates correlations between variables in the IRP. The relationships between variables were developed to show expected levels of
cause and effect, not on the results of statistical analysis. Market data does not exist for
many of these relationships, so Avista made the assumptions shown in Table 7.10.
Table 7.10: Stochastic Study Correlation Matrix
Natural
Gas
Prices
GHG
Prices
New
Coal
Prices
Hog
Fuel
Prices
Load
Growth
Gas Prices 1
GHG Prices 0.501
New Coal Prices -0.251
Hog Fuel Prices 0.50 0.501
Load Growth -0.25 -0.25-0.51
Wind, hydro and forced outages are not necessarily correlated to other market drivers.
The stochastic study portion of the IRP includes 250 combinations of these variables;
500 combinations were studied, but no difference in the mean and standard deviation of the results was found.
Greenhouse (GHG) Prices
Without established federal legislation, and no formal rules for western carbon markets, the expected price of GHG emissions is difficult to determine without macroeconomic models capable of determining financial impacts outside of the electric industry. Even
with rules in place, carbon prices will be determined based on the tradeoff and
interaction between natural gas and coal prices. The lack of certainty means that a
range of potential prices needs to be modeled. This IRP utilized ten EPA scenarios as possible legislative outcomes. The EPA scenarios were developed for the Lieberman-Warner bill, the leading federal greenhouse gas legislation at the time the modeling for
this IRP was developed. Each scenario was given a weighting (see Table 7.11) by
members of Avista’s Climate Change Committee. For the scholastic price forecast, the assigned weight will be the probability of a certain base price level.
Avista Corp 2009 Electric IRP – Public Draft 7-14
Chapter 7- Market Analysis
Table 7.11: EPA Carbon Study (Nominal Price per Short/Ton)
Study Weight 2012 2020 2025
ADAGE 10% 28.60 50.89 72.40
IGEM 3% 40.50 70.15 98.04
ADAGE - Low Intl Action 15% 26.20 48.14 66.36
IGEM Unlimited Offsets 10% 8.70 20.63 28.66
IGEM with No Offsets 2% 80.80 134.79 190.04
ADAGE Scenario 6 3% 39.70 67.39 95.02
ADAGE Scenario 7 2% 57.20 94.90 132.73
Alt. Ref. ADAGE 35% 21.00 38.51 54.30
Alt. Ref. IGEM 5% 35.00 61.89 85.97
1766 ADAGE 15% 10.20 20.63 28.66
Weighted Average 100% 23.46 42.76 59.91
The EPA and Wood Mackenzie studies differ in many aspects, but the major difference
between the two is their assumed natural gas price forecast. To adjust for these differences, 10 price scenarios were developed for the stochastic portion of the IRP. See Table 7.12 for the 10 base carbon scenarios modeled for this IRP.
Table 7.12: Ten Cost Scenarios Based on Wood Mackenzie and EPA Studies
(Nominal Price per Short Ton)
Scenario Weight 2012 2020 2025
1 10% 8.01 68.28 96.89
2 3% 11.31 94.12 131.21
3 15% 7.32 64.59 88.82
4 10% 2.42 27.68 38.35
5 2% 22.56 180.86 254.34
6 3% 11.09 90.43 127.17
7 2% 15.97 127.34 177.63
8 35% 5.86 51.67 72.67
9 5% 9.77 83.05 115.06
10 15% 2.85 27.68 38.35
Weighted Average 100% 6.55 57.37 80.18
The carbon price is determined in a two-step process. The first step draws the carbon
price regime; the second step adjusts natural gas prices and other variables. The
adjustment keeps prices correlated so the market effect is consistent. See Figure 7.8 for the carbon price distribution for the 250 iterations in 2012. Carbon prices range from $1 to $35 per short ton, with an average of $6.55 per short ton. The standard deviations of
carbon prices in 2012, 2014, 2016 and beyond are 50 percent, 25 percent and ten
percent respectively.
Avista Corp 2009 Electric IRP – Public Draft 7-15
The correlation between carbon and natural gas is likely to be high because gas-fired
resources set the marginal price of electricity in most markets. A 50-percent correlation
between carbon and natural gas is used for this IRP. A 90-percent correlation scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 135 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-16 Avista Corp
Chapter 7- Market Analysis
found no material impact on the results. The method for obtaining carbon prices and
their correlation to other market drivers will be an ongoing IRP process task.
Figure 7.8: Distribution of Annual Average Carbon Prices for 2012
0%
2%
4%
6%
8%
10%
12%
14%
$0 $3 $6 $9
$1
2
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5
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8
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Natural Gas Natural gas prices are highly volatile. Daily prices at AECO were as high as $12.92 and as low as $0.78 per Dth between 2002 and 2009. To represent future natural gas price
uncertainty, volatility is modeled to increase over the study horizon. The standard
deviation is set to 35 percent in 2012, 40 percent in 2015, 45 percent in 2020 and 50
percent in 2025 in a lognormal distribution. Prices will be determined by the development and timing of new gas supplies and changes in demand. The IRP risk
analysis is an attempt to capture the range of potential outcomes in this uncertain
future. The 2012 distribution for average prices is in Figure 7.9. Mean prices in 2012 are
expected to be $6.76 per Dth and the median level is $6.24 per Dth. The lognormal distribution skews prices upward. The 95 percent confidence level is $11.56 per Dth and the TailVar90, or average of the highest 10 percent of the iterations, is $12.37 per Dth.
Figure 7.10 illustrates the range of gas prices. The gas prices discussed earlier in this
section are shown as white diamonds. The red lines represent median values from the stochastic draws and bars represent the 80 percent confidence interval band. The
triangles are the 95 percent confidence level prices. The range of prices increase as
time goes on, consistent with the standard deviation assumptions discussed above.
Avista Corp 2009 Electric IRP – Public Draft 7-16
Chapter 7- Market Analysis
Figure 7.9: Distribution of Annual Average Natural Gas Prices for 2012
0%
2%
4%
6%
8%
10%
12%
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Figure 7.10: Henry Hub Natural Gas Distributions
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Avista Corp 2009 Electric IRP – Public Draft 7-17
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 136 of 729
2009 Electric IRPAvista Corp 7-17
Chapter 7 - Market AnalysisChapter 7- Market Analysis
found no material impact on the results. The method for obtaining carbon prices and
their correlation to other market drivers will be an ongoing IRP process task.
Figure 7.8: Distribution of Annual Average Carbon Prices for 2012
0%
2%
4%
6%
8%
10%
12%
14%
$0$3$6$9
$1
2
$1
5
$1
8
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1
$2
4
$2
7
$3
0
$3
3
$3
6
$3
9
carbon price per short ton
pe
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a
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Natural Gas Natural gas prices are highly volatile. Daily prices at AECO were as high as $12.92 and as low as $0.78 per Dth between 2002 and 2009. To represent future natural gas price
uncertainty, volatility is modeled to increase over the study horizon. The standard
deviation is set to 35 percent in 2012, 40 percent in 2015, 45 percent in 2020 and 50
percent in 2025 in a lognormal distribution. Prices will be determined by the development and timing of new gas supplies and changes in demand. The IRP risk
analysis is an attempt to capture the range of potential outcomes in this uncertain
future. The 2012 distribution for average prices is in Figure 7.9. Mean prices in 2012 are
expected to be $6.76 per Dth and the median level is $6.24 per Dth. The lognormal distribution skews prices upward. The 95 percent confidence level is $11.56 per Dth and the TailVar90, or average of the highest 10 percent of the iterations, is $12.37 per Dth.
Figure 7.10 illustrates the range of gas prices. The gas prices discussed earlier in this
section are shown as white diamonds. The red lines represent median values from the stochastic draws and bars represent the 80 percent confidence interval band. The
triangles are the 95 percent confidence level prices. The range of prices increase as
time goes on, consistent with the standard deviation assumptions discussed above.
Avista Corp 2009 Electric IRP – Public Draft 7-16
Chapter 7- Market Analysis
Figure 7.9: Distribution of Annual Average Natural Gas Prices for 2012
0%
2%
4%
6%
8%
10%
12%
$2
.
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.
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Figure 7.10: Henry Hub Natural Gas Distributions
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Avista Corp 2009 Electric IRP – Public Draft 7-17
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 137 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-18 Avista Corp
Chapter 7- Market Analysis
High carbon prices generally lead to higher natural gas prices due to the 50 percent
assumed correlation between the two variables. In the later half of the study horizon,
extremely high carbon and natural gas prices are possible due to the vast uncertainty of
future price levels. In past IRPs, the year-to-year prices of a draw were correlated, but Avista no longer believes there is enough statistical evidence to support this assumption.
Figure 7.11 shows the randomness of annual prices from one year to the next.
Figure 7.11: Random Draws from the Henry Hub Price Distribution
0
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Load
Load variability is driven by several factors. The largest driver is weather because
extreme weather variations can move loads up or down compared to overall expected levels. The recent economic downturn has decreased electric demand relative to the long-term average, while earlier economic expansions increased loads. Loads are
modeled to increase at the levels discussed earlier in the chapter, but the risk analysis
varied economic and weather conditions. The economic adjustments are inversely
correlated to natural gas and carbon prices using a lag function. This means that if carbon prices were high in the previous year, then the probability of lower loads is likely
the following year (25 percent probability) due to price elasticity responses.
The standard deviation for load growth is estimated at 50 percent. If a load area was forecast to have a 2 percent average annual load growth rate, the load in any given year would be between one and three percent at one standard deviation; two-thirds of all
random draws should fall within this range. Figure 7.12 illustrates the annual load
growth trajectory for the Western Interconnect in 10 selected iterations.
Avista Corp 2009 Electric IRP – Public Draft 7-18
Chapter 7- Market Analysis
Figure 7.12: Random Draws Load Forecast with Year 2009 at 100
100
105
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The Western Interconnect has many diverse areas and economies. The long-term load-growth correlation between each area is assumed to be 20 percent. Low correlation means each area within the Western Interconnect acts in a relatively independent
manner. As with many risk assumptions, the Company will continue to assess the
correlations and variation for major drivers of the electricity market. A study of historical
weather-adjusted load growth will be examined for Western Interconnect areas for the next IRP.
The method Avista adopted for its 2003 IRP continues to be used to reflect weather
patterns across the Western Interconnect. FERC Form 714 data was collected for 2002 to 2007. Correlations between Northwest and other Western Interconnect load areas were calculated and represented as stochastic weather adjustments to the load model.
Correlating area loads avoids oversimplifying the Western Interconnect load picture.
Absent correlations, stochastic models would offset load changes in one zone with load
changes in another, thereby virtually eliminating the possibility of modeling the West-wide load excursions we witness in today’s marketplace. Given the high degree of
interdependency across the Western Interconnect (e.g., the Northwest and California),
this additional accuracy is crucial for understanding variation in wholesale electricity
market prices and the value of resources used to meet such variation (i.e., peaking generation). For example, without regional correlation the volatility would be measured, but would not adequately represent heat waves and cold snaps occurring across the
Western Interconnect.
Avista Corp 2009 Electric IRP – Public Draft 7-19
Tables 7.13 and 7.14 illustrate the correlations used in the IRP. The correlation statistics are relative to the Northwest load area (Oregon, Washington, and North Idaho).
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 138 of 729
2009 Electric IRPAvista Corp 7-19
Chapter 7 - Market AnalysisChapter 7- Market Analysis
High carbon prices generally lead to higher natural gas prices due to the 50 percent
assumed correlation between the two variables. In the later half of the study horizon,
extremely high carbon and natural gas prices are possible due to the vast uncertainty of
future price levels. In past IRPs, the year-to-year prices of a draw were correlated, but Avista no longer believes there is enough statistical evidence to support this assumption.
Figure 7.11 shows the randomness of annual prices from one year to the next.
Figure 7.11: Random Draws from the Henry Hub Price Distribution
0
10
20
30
40
50
60
70
80
90
100
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Load
Load variability is driven by several factors. The largest driver is weather because
extreme weather variations can move loads up or down compared to overall expected levels. The recent economic downturn has decreased electric demand relative to the long-term average, while earlier economic expansions increased loads. Loads are
modeled to increase at the levels discussed earlier in the chapter, but the risk analysis
varied economic and weather conditions. The economic adjustments are inversely
correlated to natural gas and carbon prices using a lag function. This means that if carbon prices were high in the previous year, then the probability of lower loads is likely
the following year (25 percent probability) due to price elasticity responses.
The standard deviation for load growth is estimated at 50 percent. If a load area was forecast to have a 2 percent average annual load growth rate, the load in any given year would be between one and three percent at one standard deviation; two-thirds of all
random draws should fall within this range. Figure 7.12 illustrates the annual load
growth trajectory for the Western Interconnect in 10 selected iterations.
Avista Corp 2009 Electric IRP – Public Draft 7-18
Chapter 7- Market Analysis
Figure 7.12: Random Draws Load Forecast with Year 2009 at 100
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The Western Interconnect has many diverse areas and economies. The long-term load-growth correlation between each area is assumed to be 20 percent. Low correlation means each area within the Western Interconnect acts in a relatively independent
manner. As with many risk assumptions, the Company will continue to assess the
correlations and variation for major drivers of the electricity market. A study of historical
weather-adjusted load growth will be examined for Western Interconnect areas for the next IRP.
The method Avista adopted for its 2003 IRP continues to be used to reflect weather
patterns across the Western Interconnect. FERC Form 714 data was collected for 2002 to 2007. Correlations between Northwest and other Western Interconnect load areas were calculated and represented as stochastic weather adjustments to the load model.
Correlating area loads avoids oversimplifying the Western Interconnect load picture.
Absent correlations, stochastic models would offset load changes in one zone with load
changes in another, thereby virtually eliminating the possibility of modeling the West-wide load excursions we witness in today’s marketplace. Given the high degree of
interdependency across the Western Interconnect (e.g., the Northwest and California),
this additional accuracy is crucial for understanding variation in wholesale electricity
market prices and the value of resources used to meet such variation (i.e., peaking generation). For example, without regional correlation the volatility would be measured, but would not adequately represent heat waves and cold snaps occurring across the
Western Interconnect.
Avista Corp 2009 Electric IRP – Public Draft 7-19
Tables 7.13 and 7.14 illustrate the correlations used in the IRP. The correlation statistics are relative to the Northwest load area (Oregon, Washington, and North Idaho).
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 139 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-20 Avista Corp
Chapter 7- Market Analysis
“NotSig” indicates no statistically valid correlation was found in the evaluated data. “Mix”
indicates the relationship was not consistent across time and was not used in this
analysis. Tables 7.15 and 7.16 provide the coefficient of determination (standard
deviation divided by the average) values for each zone. The weather adjustments are fairly consistent for each area, except for shoulder months where loads diverge from
one another.
Table 7.13: January through June Area Correlations
Jan Feb Mar Apr May Jun
Alberta 0.674 0.631 0.494 0.679 0.593 0.771
Avista 0.934 0.886 0.848 0.706 0.819 0.691
Arizona 0.236 0.162 0.077 Mix Not Sig 0.312
Baja 0.530 0.584 Mix 0.076 Mix 0.692
British Columbia 0.753 0.765 0.763 0.693 0.552 0.552
Colorado 0.653 0.425 Not Sig 0.402 0.493 0.503
Idaho South 0.847 0.743 0.797 0.075 0.237 0.585
Montana 0.831 0.836 0.655 0.338 0.533 0.726
New Mexico 0.570 0.413 0.349 0.469 0.737 0.622
Nevada North 0.690 0.725 0.658 0.683 0.685 0.830
Nevada South 0.785 0.779 0.075 Mix 0.242 0.726
California South 0.499 0.334 Mix Mix Not Sig 0.164
Utah 0.482 Not Sig 0.259 Mix 0.077 0.425
Wyoming 0.486 Not Sig 0.167 Mix Not Sig 0.386
California North 0.750 0.728 0.603 Mix 0.327 0.543
Table 7.14: July through December Area Correlations
Jul Aug Sep Oct Nov Dec
Alberta 0.767 0.777 0.821 0.733 0.673 0.786
Avista 0.909 0.776 0.594 0.873 0.909 0.878
Arizona 0.368 Not Sig Mix Mix Not Sig Not Sig
Baja 0.689 0.757 Mix Mix 0.072 0.456
British Columbia 0.677 Mix 0.247 0.666 0.743 0.732
Colorado 0.505 0.686 0.663 0.672 0.694 0.774
Idaho South 0.747 0.760 Mix 0.426 0.873 0.870
Montana 0.782 0.673 0.635 0.775 0.882 0.833
New Mexico 0.596 Mix 0.664 0.525 0.420 0.689
Nevada North 0.780 0.818 0.626 0.447 0.756 0.793
Nevada South 0.689 0.608 0.418 Mix 0.543 0.821
California South 0.487 0.249 Mix Mix Not Sig Mix
Utah 0.400 Mix 0.243 0.161 0.076 Not Sig
Wyoming 0.240 Mix Mix Mix 0.072 Not Sig
California North 0.707 0.503 Mix Mix 0.560 0.764
Avista Corp 2009 Electric IRP – Public Draft 7-20
Chapter 7- Market Analysis
Table 7.15: Area Load Coefficient of Determination (Std Dev/Mean)
Jan Feb Mar Apr May Jun
Alberta 2.8% 2.4% 3.0% 2.9% 2.7% 3.6%
Arizona 5.8% 4.7% 4.3% 6.4% 11.0% 7.6%
Avista 6.7% 5.8% 6.3% 5.4% 5.5% 6.9%
Baja 9.5% 7.9% 8.5% 9.2% 10.5% 7.6%
British Columbia 5.4% 3.8% 5.0% 4.9% 4.3% 4.1%
California North 5.3% 5.5% 5.4% 6.0% 8.6% 9.4%
Colorado 5.2% 5.4% 5.5% 5.2% 6.6% 7.6%
Idaho South 5.2% 5.9% 6.8% 6.0% 10.3% 10.9%
Montana 5.0% 4.7% 4.7% 4.5% 4.7% 5.8%
Nevada North 2.8% 2.8% 3.2% 3.3% 4.9% 5.0%
Nevada South 4.2% 3.7% 3.8% 6.6% 13.8% 9.2%
New Mexico 4.6% 4.4% 4.3% 4.6% 6.8% 5.9%
Oregon Washington Idaho 7.0% 5.6% 6.3% 5.4% 5.0% 5.1%
Southern California 6.7% 6.4% 6.6% 7.4% 9.0% 8.1%
Utah 4.9% 5.3% 5.3% 5.0% 6.7% 8.1%
Wyoming 5.0% 5.4% 5.3% 5.0% 6.5% 8.2%
Table 7.16: Area Load Coefficient of Determination (Std Dev/Mean)
Jul Aug Sep Oct Nov Dec
Alberta 3.5% 3.2% 2.7% 2.9% 2.5% 3.0%
Arizona 7.3% 7.1% 10.5% 10.4% 4.9% 6.1%
Avista 7.8% 6.8% 5.7% 5.9% 6.7% 5.7%
Baja 6.4% 6.3% 11.6% 9.9% 7.6% 10.2%
British Columbia 4.8% 4.4% 4.4% 5.2% 5.9% 4.6%
California North 9.5% 8.0% 9.0% 6.0% 5.9% 5.8%
Colorado 7.2% 7.3% 7.3% 5.2% 5.5% 5.6%
Idaho South 6.2% 6.9% 9.8% 4.5% 6.6% 6.1%
Montana 5.9% 5.4% 4.2% 4.5% 5.4% 4.4%
Nevada North 5.0% 4.4% 5.0% 2.9% 3.4% 3.5%
Nevada South 7.1% 7.2% 12.7% 8.5% 4.0% 4.3%
New Mexico 5.9% 5.4% 5.8% 5.3% 5.0% 5.2%
Oregon Washington Idaho 6.3% 5.1% 4.8% 5.7% 7.0% 5.8%
Southern California 8.8% 8.0% 10.4% 7.6% 7.4% 6.8%
Utah 5.7% 5.6% 7.2% 4.5% 5.4% 5.4%
Wyoming 5.8% 5.6% 7.0% 4.5% 5.4% 5.5%
Avista Corp 2009 Electric IRP – Public Draft 7-21
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 140 of 729
2009 Electric IRPAvista Corp 7-21
Chapter 7 - Market AnalysisChapter 7- Market Analysis
“NotSig” indicates no statistically valid correlation was found in the evaluated data. “Mix”
indicates the relationship was not consistent across time and was not used in this
analysis. Tables 7.15 and 7.16 provide the coefficient of determination (standard
deviation divided by the average) values for each zone. The weather adjustments are fairly consistent for each area, except for shoulder months where loads diverge from
one another.
Table 7.13: January through June Area Correlations
Jan Feb Mar Apr May Jun
Alberta0.674 0.631 0.494 0.679 0.593 0.771
Avista 0.934 0.886 0.848 0.706 0.819 0.691
Arizona 0.236 0.162 0.077 Mix Not Sig 0.312
Baja 0.530 0.584 Mix 0.076 Mix 0.692
British Columbia 0.753 0.765 0.763 0.693 0.552 0.552
Colorado 0.653 0.425 Not Sig 0.402 0.493 0.503
Idaho South 0.847 0.743 0.797 0.075 0.237 0.585
Montana 0.831 0.836 0.655 0.338 0.533 0.726
New Mexico 0.570 0.413 0.349 0.469 0.737 0.622
Nevada North 0.690 0.725 0.658 0.683 0.685 0.830
Nevada South 0.785 0.779 0.075 Mix 0.242 0.726
California South 0.499 0.334 Mix Mix Not Sig 0.164
Utah 0.482 Not Sig 0.259 Mix 0.077 0.425
Wyoming 0.486 Not Sig 0.167 Mix Not Sig 0.386
California North 0.750 0.728 0.603 Mix 0.327 0.543
Table 7.14: July through December Area Correlations
Jul Aug Sep Oct Nov Dec
Alberta 0.767 0.777 0.821 0.733 0.673 0.786
Avista 0.909 0.776 0.594 0.873 0.909 0.878
Arizona 0.368 Not Sig Mix Mix Not Sig Not Sig
Baja 0.689 0.757 Mix Mix 0.072 0.456
British Columbia 0.677 Mix 0.247 0.666 0.743 0.732
Colorado 0.505 0.686 0.663 0.672 0.694 0.774
Idaho South 0.747 0.760 Mix 0.426 0.873 0.870
Montana 0.782 0.673 0.635 0.775 0.882 0.833
New Mexico 0.596 Mix 0.664 0.525 0.420 0.689
Nevada North 0.780 0.818 0.626 0.447 0.756 0.793
Nevada South 0.689 0.608 0.418 Mix 0.543 0.821
California South 0.487 0.249 Mix Mix Not Sig Mix
Utah 0.400 Mix 0.243 0.161 0.076 Not Sig
Wyoming 0.240 Mix Mix Mix 0.072 Not Sig
California North 0.707 0.503 Mix Mix 0.560 0.764
Avista Corp 2009 Electric IRP – Public Draft 7-20
Chapter 7- Market Analysis
Table 7.15: Area Load Coefficient of Determination (Std Dev/Mean)
Jan Feb Mar Apr May Jun
Alberta 2.8% 2.4% 3.0% 2.9% 2.7% 3.6%
Arizona 5.8% 4.7% 4.3% 6.4% 11.0% 7.6%
Avista 6.7% 5.8% 6.3% 5.4% 5.5% 6.9%
Baja 9.5% 7.9% 8.5% 9.2% 10.5% 7.6%
British Columbia 5.4% 3.8% 5.0% 4.9% 4.3% 4.1%
California North 5.3% 5.5% 5.4% 6.0% 8.6% 9.4%
Colorado 5.2% 5.4% 5.5% 5.2% 6.6% 7.6%
Idaho South 5.2% 5.9% 6.8% 6.0% 10.3% 10.9%
Montana 5.0% 4.7% 4.7% 4.5% 4.7% 5.8%
Nevada North 2.8% 2.8% 3.2% 3.3% 4.9% 5.0%
Nevada South 4.2% 3.7% 3.8% 6.6% 13.8% 9.2%
New Mexico 4.6% 4.4% 4.3% 4.6% 6.8% 5.9%
Oregon Washington Idaho 7.0% 5.6% 6.3% 5.4% 5.0% 5.1%
Southern California 6.7% 6.4% 6.6% 7.4% 9.0% 8.1%
Utah 4.9% 5.3% 5.3% 5.0% 6.7% 8.1%
Wyoming 5.0% 5.4% 5.3% 5.0% 6.5% 8.2%
Table 7.16: Area Load Coefficient of Determination (Std Dev/Mean)
Jul Aug Sep Oct Nov Dec
Alberta 3.5% 3.2% 2.7% 2.9% 2.5% 3.0%
Arizona 7.3% 7.1% 10.5% 10.4% 4.9% 6.1%
Avista 7.8% 6.8% 5.7% 5.9% 6.7% 5.7%
Baja 6.4% 6.3% 11.6% 9.9% 7.6% 10.2%
British Columbia 4.8% 4.4% 4.4% 5.2% 5.9% 4.6%
California North 9.5% 8.0% 9.0% 6.0% 5.9% 5.8%
Colorado 7.2% 7.3% 7.3% 5.2% 5.5% 5.6%
Idaho South 6.2% 6.9% 9.8% 4.5% 6.6% 6.1%
Montana 5.9% 5.4% 4.2% 4.5% 5.4% 4.4%
Nevada North 5.0% 4.4% 5.0% 2.9% 3.4% 3.5%
Nevada South 7.1% 7.2% 12.7% 8.5% 4.0% 4.3%
New Mexico 5.9% 5.4% 5.8% 5.3% 5.0% 5.2%
Oregon Washington Idaho 6.3% 5.1% 4.8% 5.7% 7.0% 5.8%
Southern California 8.8% 8.0% 10.4% 7.6% 7.4% 6.8%
Utah 5.7% 5.6% 7.2% 4.5% 5.4% 5.4%
Wyoming 5.8% 5.6% 7.0% 4.5% 5.4% 5.5%
Avista Corp 2009 Electric IRP – Public Draft 7-21
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 141 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-22 Avista Corp
Chapter 7- Market Analysis
Coal Prices
Coal prices are not modeled stochastically for existing plants. Coal prices are typically
contractually based for long time periods. As coal project contracts expire and plants
begin to rely on new fuel sources, prices change with coal supply and demand and transportation. Coal prices were modeled stochastically using a 10 percent standard
deviation for new coal projects options considered in Avista’s PRS Analysis. Prices are
inversely correlated to carbon, as higher carbon prices are expected to decrease coal
demand. It is possible that increased international demand for U.S. domestic coal will cause prices to increase. Lower coal demand could reduce the number of suppliers and cause prices to increase. Transportation cost increases arising from factors besides
carbon reduction also could raise the cost of coal.
Wood/Hog FuelThe price of wood, or hog fuel, is modeled stochastically for new resource options
available to the PRS. Avista’s experience with woody biomass generation indicates
consistent price increases for a fuel that used to be free. The price and availability of
hog fuel varies with the economy. The IRP stochastic analysis assumes a standard deviation of 10 percent. Further demand for wood residues will increase with aggressive greenhouse gas and renewable portfolio standard legislation. These environmental
concerns will encourage more woody-biomass generation or the co-firing of existing
coal and other boiler-fired plants with wood pellets. The correlation between wood and
carbon prices is therefore assumed to be 50 percent. Hog fuel is also correlated 50 percent to natural gas prices because most commercial wood residue is displacing
natural gas.
Hydro The hydro risk analysis uses the 70-year record (1928 to 1999) from the 2008-09 Headwater Benefits Study completed by the Northwest Power Pool. Each water year is
drawn randomly for each iteration of the stochastic analysis. Hydro is not correlated to
any other variable in this study. Some preliminary studies indicate that there might be modest correlation between hydroelectric and wind generation over a calendar year or certain seasons. However, Avista is not aware of any comprehensive study of
correlation between the two resources. This relationship will be studied as more wind
data becomes available. Figure 7.13 shows the distribution of annual hydro capacity
factors for Avista’s hydro fleet over the 70-year record. Expected hydro output is 538 aMW and median output is 543 aMW.
Avista Corp 2009 Electric IRP – Public Draft 7-22
Chapter 7- Market Analysis
Figure 7.13: Distribution of Avista’s Hydro Generation
0%
2%
4%
6%
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10%
12%
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16%
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350 400 450 500 550 600 650 700 750
average megawatts
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WindWind is one of the most volatile generating resources available to utilities. Storage,
apart from some integration with hydro, is not a financially viable option based on
current technologies. This makes it necessary to capture wind volatility in the power
supply model to determine its impacts on the overall market, as well as the value of any wind project acquisition. Accurately modeling wind resources requires hourly generation
shapes. Variability is modeled similar to how AURORAxmp models hydroelectric
resources for regional analyses. A single wind generation shape is developed for each
area. This generation shape is smoother than individual plant characteristics, but closely represents how a large number of wind farms across a geographical area would operate together.
This simplified wind methodology works well for forecasting electricity prices across a
large market, but does not represent well the volatility of specific wind resources the Company might select. A different wind shape was used for each Avista resource option
in each of the 250 stochastic iterations. This analysis used historical wind speed data
for potential wind sites at Reardan, Washington, the Columbia Basin and Montana.
Avista Corp 2009 Electric IRP – Public Draft 7-23
The first step in developing the wind randomization model was to create a distribution of hourly output. Figure 7.14 shows the distribution for a Northwest wind site. In this
example, generation is zero for 13 percent of the on-peak hours and zero for 6 percent
of the off-peak hours. The resource is near full output only 5 percent of the time. The
second step links next-hour generation to present generation levels. The next hour has
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 142 of 729
2009 Electric IRPAvista Corp 7-23
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Coal Prices
Coal prices are not modeled stochastically for existing plants. Coal prices are typically
contractually based for long time periods. As coal project contracts expire and plants
begin to rely on new fuel sources, prices change with coal supply and demand and transportation. Coal prices were modeled stochastically using a 10 percent standard
deviation for new coal projects options considered in Avista’s PRS Analysis. Prices are
inversely correlated to carbon, as higher carbon prices are expected to decrease coal
demand. It is possible that increased international demand for U.S. domestic coal will cause prices to increase. Lower coal demand could reduce the number of suppliers and cause prices to increase. Transportation cost increases arising from factors besides
carbon reduction also could raise the cost of coal.
Wood/Hog FuelThe price of wood, or hog fuel, is modeled stochastically for new resource options
available to the PRS. Avista’s experience with woody biomass generation indicates
consistent price increases for a fuel that used to be free. The price and availability of
hog fuel varies with the economy. The IRP stochastic analysis assumes a standard deviation of 10 percent. Further demand for wood residues will increase with aggressive greenhouse gas and renewable portfolio standard legislation. These environmental
concerns will encourage more woody-biomass generation or the co-firing of existing
coal and other boiler-fired plants with wood pellets. The correlation between wood and
carbon prices is therefore assumed to be 50 percent. Hog fuel is also correlated 50 percent to natural gas prices because most commercial wood residue is displacing
natural gas.
Hydro The hydro risk analysis uses the 70-year record (1928 to 1999) from the 2008-09 Headwater Benefits Study completed by the Northwest Power Pool. Each water year is
drawn randomly for each iteration of the stochastic analysis. Hydro is not correlated to
any other variable in this study. Some preliminary studies indicate that there might be modest correlation between hydroelectric and wind generation over a calendar year or certain seasons. However, Avista is not aware of any comprehensive study of
correlation between the two resources. This relationship will be studied as more wind
data becomes available. Figure 7.13 shows the distribution of annual hydro capacity
factors for Avista’s hydro fleet over the 70-year record. Expected hydro output is 538 aMW and median output is 543 aMW.
Avista Corp 2009 Electric IRP – Public Draft 7-22
Chapter 7- Market Analysis
Figure 7.13: Distribution of Avista’s Hydro Generation
0%
2%
4%
6%
8%
10%
12%
14%
16%
18%
350 400 450 500 550 600 650 700 750
average megawatts
pe
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P
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c
e
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t
i
l
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)
WindWind is one of the most volatile generating resources available to utilities. Storage,
apart from some integration with hydro, is not a financially viable option based on
current technologies. This makes it necessary to capture wind volatility in the power
supply model to determine its impacts on the overall market, as well as the value of any wind project acquisition. Accurately modeling wind resources requires hourly generation
shapes. Variability is modeled similar to how AURORAxmp models hydroelectric
resources for regional analyses. A single wind generation shape is developed for each
area. This generation shape is smoother than individual plant characteristics, but closely represents how a large number of wind farms across a geographical area would operate together.
This simplified wind methodology works well for forecasting electricity prices across a
large market, but does not represent well the volatility of specific wind resources the Company might select. A different wind shape was used for each Avista resource option
in each of the 250 stochastic iterations. This analysis used historical wind speed data
for potential wind sites at Reardan, Washington, the Columbia Basin and Montana.
Avista Corp 2009 Electric IRP – Public Draft 7-23
The first step in developing the wind randomization model was to create a distribution of hourly output. Figure 7.14 shows the distribution for a Northwest wind site. In this
example, generation is zero for 13 percent of the on-peak hours and zero for 6 percent
of the off-peak hours. The resource is near full output only 5 percent of the time. The
second step links next-hour generation to present generation levels. The next hour has
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 143 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-24 Avista Corp
Chapter 7- Market Analysis
a 95 percent probability of being within two percent of the last hour’s generation level. The model also correlates wind locations: Reardan is 75 percent correlated to
Northwest resources and Montana is 25 percent correlated to Northwest wind
resources.
Figure 7.14: Wind Output Distribution
0%
20%
40%
60%
80%
100%
0%
10
%
20
%
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%
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%
60
%
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%
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%
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percent of time
ca
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On-Peak
Off-Peak
Forced Outages Forced outages at CCCT, coal and nuclear plants were included in the risk analysis.
The forced outage logic in the AURORAxmp algorithm is based on a mean time to
repair and a forced outage rate. The model randomly forces a unit out of service and
brings it back online at different intervals throughout the year based on its mean time to repair. Operating performance varies from iteration to iteration.
Market Forecast
An optimal resource portfolio must account for the extrinsic value inherent in the
resource choices. The 2009 IRP simulation was conducted by comparing each resource’s expected hourly output at a forecasted Mid-Columbia hourly price. This exercise was repeated for 250 iterations of Monte Carlo-style stochastic analysis.
Resources generating during on-peak hours generally contribute higher margins to
Avista’s resource portfolio than resources with intermediate and unpredictable output.
Avista Corp 2009 Electric IRP – Public Draft 7-24
Assumptions used to develop the electricity price forecast were discussed earlier in this
chapter. In general, hourly electricity price is set by the operating cost of the marginal
unit in the Northwest or the economic cost to move power into or out of the Northwest.
To create an electricity market price projection, a forecast of available future resources must be determined. The IRP uses regional planning margins to set minimum capacity
Chapter 7- Market Analysis
requirements, instead of using the summation of capacity needs of each utility in the region. Western regions can have resource surpluses even where some individual
utilities may be in a deficit situation. This imbalance can be due to ownership of regional
generation by independent power producers or differences in planning methodologies used by the deficit utilities.
AURORAxmp assigns market values to each resource alternative available to the
Preferred Resource Strategy (PRS), but it does not select PRS resources. Several
market price forecasts are used to determine the value and volatility of a resource portfolio. As Avista does not know what will happen in the future with any degree of certainty, it relies on risk analysis to help determine an optimal resource strategy. Risk
analysis uses several market price forecasts with different assumptions than the Base
Case or changes the underlying statistics of a study. These alternate cases are split into stochastic and deterministic studies.
A stochastic study uses Monte Carlo analysis to quantify variability in future market
prices. These analyses include 250 iterations of varying gas prices, loads, hydro,
thermal outages, wind shapes and emissions prices. Two stochastic studies were developed for this IRP, one with and one without carbon legislation. The remaining studies were deterministic scenario analyses.
Resource Selection New resource options were discussed earlier in this chapter, along with the amount of capacity necessary to meet capacity targets. New resources for the Western
Interconnect will primarily be natural gas-fired. Renewable resources added to meet
renewable portfolio standards help fill system energy needs, but fail to provide
equivalent capacity for system reliability. Figure 7.15 shows the new resources selected to meet capacity needs and RPS requirements for the Western Interconnect. The model
retires a number of coal and high heat rate natural gas plants for economic reasons.
Using the same scale, the amount of potential energy is shown in the black line with
diamonds. In 2020, 78 GW of nameplate capacity is added, but only 48 GW of energy is available from these resources. Mandates to acquire new renewable resources help reduce carbon emissions, but force utilities to invest in more infrastructure.
The Northwest is expected to need new capacity in 2015, as described earlier in this
chapter. The predominant resource selected after renewables to meet Northwest loads is combined cycle combustion turbines. 8,100 MW of CCCT are forecast to be added in
the Northwest between 2015 and 2029.
Avista Corp 2009 Electric IRP – Public Draft 7-25
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 144 of 729
2009 Electric IRPAvista Corp 7-25
Chapter 7 - Market AnalysisChapter 7- Market Analysis
a 95 percent probability of being within two percent of the last hour’s generation level. The model also correlates wind locations: Reardan is 75 percent correlated to
Northwest resources and Montana is 25 percent correlated to Northwest wind
resources.
Figure 7.14: Wind Output Distribution
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Forced Outages Forced outages at CCCT, coal and nuclear plants were included in the risk analysis.
The forced outage logic in the AURORAxmp algorithm is based on a mean time to
repair and a forced outage rate. The model randomly forces a unit out of service and
brings it back online at different intervals throughout the year based on its mean time to repair. Operating performance varies from iteration to iteration.
Market Forecast
An optimal resource portfolio must account for the extrinsic value inherent in the
resource choices. The 2009 IRP simulation was conducted by comparing each resource’s expected hourly output at a forecasted Mid-Columbia hourly price. This exercise was repeated for 250 iterations of Monte Carlo-style stochastic analysis.
Resources generating during on-peak hours generally contribute higher margins to
Avista’s resource portfolio than resources with intermediate and unpredictable output.
Avista Corp 2009 Electric IRP – Public Draft 7-24
Assumptions used to develop the electricity price forecast were discussed earlier in this
chapter. In general, hourly electricity price is set by the operating cost of the marginal
unit in the Northwest or the economic cost to move power into or out of the Northwest.
To create an electricity market price projection, a forecast of available future resources must be determined. The IRP uses regional planning margins to set minimum capacity
Chapter 7- Market Analysis
requirements, instead of using the summation of capacity needs of each utility in the region. Western regions can have resource surpluses even where some individual
utilities may be in a deficit situation. This imbalance can be due to ownership of regional
generation by independent power producers or differences in planning methodologies used by the deficit utilities.
AURORAxmp assigns market values to each resource alternative available to the
Preferred Resource Strategy (PRS), but it does not select PRS resources. Several
market price forecasts are used to determine the value and volatility of a resource portfolio. As Avista does not know what will happen in the future with any degree of certainty, it relies on risk analysis to help determine an optimal resource strategy. Risk
analysis uses several market price forecasts with different assumptions than the Base
Case or changes the underlying statistics of a study. These alternate cases are split into stochastic and deterministic studies.
A stochastic study uses Monte Carlo analysis to quantify variability in future market
prices. These analyses include 250 iterations of varying gas prices, loads, hydro,
thermal outages, wind shapes and emissions prices. Two stochastic studies were developed for this IRP, one with and one without carbon legislation. The remaining studies were deterministic scenario analyses.
Resource Selection New resource options were discussed earlier in this chapter, along with the amount of capacity necessary to meet capacity targets. New resources for the Western
Interconnect will primarily be natural gas-fired. Renewable resources added to meet
renewable portfolio standards help fill system energy needs, but fail to provide
equivalent capacity for system reliability. Figure 7.15 shows the new resources selected to meet capacity needs and RPS requirements for the Western Interconnect. The model
retires a number of coal and high heat rate natural gas plants for economic reasons.
Using the same scale, the amount of potential energy is shown in the black line with
diamonds. In 2020, 78 GW of nameplate capacity is added, but only 48 GW of energy is available from these resources. Mandates to acquire new renewable resources help reduce carbon emissions, but force utilities to invest in more infrastructure.
The Northwest is expected to need new capacity in 2015, as described earlier in this
chapter. The predominant resource selected after renewables to meet Northwest loads is combined cycle combustion turbines. 8,100 MW of CCCT are forecast to be added in
the Northwest between 2015 and 2029.
Avista Corp 2009 Electric IRP – Public Draft 7-25
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 145 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-26 Avista Corp
Chapter 7- Market Analysis
Figure 7.15: Base Case New Resource Selection
(5)
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Geothermal BiomassHydroWindSolarCoal SeqCCCTSCCTCoal- retire NG- retireOil- retire Energy (aGW)
Mid-Columbia Price Forecast
The Mid-Columbia electricity trading hub is Avista’s primary trading hub. The Western Interconnect also has trading hubs on the California/Oregon Border (COB), Four Corners, Palo Verde, SP15 (southern California), NP15 (northern California) and Mead.
The Mid-Columbia market is usually the least cost market because of low-cost hydro
generation, though other markets can be less expensive when Rocky Mountain area
gas prices are low.
Two studies were conducted for the Base Case. The first is a deterministic market view
using expected levels for key assumptions discussed in the first part of this chapter. The
second is a risk or stochastic study with 250 unique scenarios based on different underlining assumptions for gas prices, load, carbon prices, wind, hydro, forced outages and others. Each of these studies simulates the entire Western Interconnect between
2010 and 2029 for each hour. The analysis used 25 CPUs linked to a SQL server to
simulate the market, creating over 26.5 GB of data requiring 1,500 hours of computing
time.
Average prices from the stochastic study do not match deterministic or median prices.
Lognormal natural gas prices with carbon penalties affect prices in a lognormal way,
with more up-side than down-side price variability. Figure 7.16 compares stochastic market price results to the deterministic Base Case scenario. The price distributions are shown in Figure 7.17 for selected years: the horizontal axis is the percent of time,
indicating 10 percent of the iteration’s annual flat prices were above $75 per MWh in
2010 and 50 percent of the time prices were over $48 per MWh.
Avista Corp 2009 Electric IRP – Public Draft 7-26
Chapter 7- Market Analysis
Figure 7.16: Annual Flat Mid-Columbia Electric Prices
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Figure 7.17: Selected Mid-Columbia Annual Flat Price Duration Curves
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Avista Corp 2009 Electric IRP – Public Draft 7-27
Annual on- and off-peak prices are presented in Table 7.17, along with levelized costs for deterministic and stochastic analyses. The Mid-Columbia market price is expected to
average $79.56 per MWh in 2009 dollars over the next 20 years and the average
nominal price is $93.74 per MWh. Spreads between on- and off-peak prices are $14.34
per MWh in 2010 and $32.71 per MWh in 2029.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 146 of 729
2009 Electric IRPAvista Corp 7-27
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.15: Base Case New Resource Selection
(5)
10
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85
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115
130
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GeothermalBiomassHydroWindSolarCoal SeqCCCTSCCTCoal- retireNG- retireOil- retireEnergy (aGW)
Mid-Columbia Price Forecast
The Mid-Columbia electricity trading hub is Avista’s primary trading hub. The Western Interconnect also has trading hubs on the California/Oregon Border (COB), Four Corners, Palo Verde, SP15 (southern California), NP15 (northern California) and Mead.
The Mid-Columbia market is usually the least cost market because of low-cost hydro
generation, though other markets can be less expensive when Rocky Mountain area
gas prices are low.
Two studies were conducted for the Base Case. The first is a deterministic market view
using expected levels for key assumptions discussed in the first part of this chapter. The
second is a risk or stochastic study with 250 unique scenarios based on different underlining assumptions for gas prices, load, carbon prices, wind, hydro, forced outages and others. Each of these studies simulates the entire Western Interconnect between
2010 and 2029 for each hour. The analysis used 25 CPUs linked to a SQL server to
simulate the market, creating over 26.5 GB of data requiring 1,500 hours of computing
time.
Average prices from the stochastic study do not match deterministic or median prices.
Lognormal natural gas prices with carbon penalties affect prices in a lognormal way,
with more up-side than down-side price variability. Figure 7.16 compares stochastic market price results to the deterministic Base Case scenario. The price distributions are shown in Figure 7.17 for selected years: the horizontal axis is the percent of time,
indicating 10 percent of the iteration’s annual flat prices were above $75 per MWh in
2010 and 50 percent of the time prices were over $48 per MWh.
Avista Corp 2009 Electric IRP – Public Draft 7-26
Chapter 7- Market Analysis
Figure 7.16: Annual Flat Mid-Columbia Electric Prices
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Figure 7.17: Selected Mid-Columbia Annual Flat Price Duration Curves
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2010 2014
2017 2020
Avista Corp 2009 Electric IRP – Public Draft 7-27
Annual on- and off-peak prices are presented in Table 7.17, along with levelized costs for deterministic and stochastic analyses. The Mid-Columbia market price is expected to
average $79.56 per MWh in 2009 dollars over the next 20 years and the average
nominal price is $93.74 per MWh. Spreads between on- and off-peak prices are $14.34
per MWh in 2010 and $32.71 per MWh in 2029.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 147 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-28 Avista Corp
Chapter 7- Market Analysis
Table 7.17: Annual Mid-Columbia Electric Prices ($/MWh)
Deterministic Stochastic Mean
Year OnPeak OffPeak Flat OnPeak OffPeak Flat
2010 53.86 40.08 47.96 55.44 41.10 49.29
2011 54.40 40.35 48.38 56.70 42.10 50.44
2012 59.09 45.83 53.39 62.56 48.49 56.51
2013 63.62 50.37 57.95 68.92 54.34 62.68
2014 71.19 56.95 65.09 76.76 60.98 70.00
2015 80.72 65.87 74.36 86.94 70.07 79.71
2016 90.50 74.69 83.73 97.00 78.71 89.17
2017 95.46 78.86 88.32 103.78 84.00 95.27
2018 107.32 91.28 100.45 119.24 97.01 109.72
2019 112.00 95.68 105.01 126.03 102.86 116.10
2020 114.88 98.22 107.75 128.40 104.45 118.15
2021 116.16 99.70 109.11 129.17 105.09 118.86
2022 117.84 101.50 110.84 131.07 106.60 120.59
2023 123.03 106.01 115.71 138.34 112.73 127.33
2024 128.07 110.46 120.53 142.84 116.61 131.61
2025 132.85 114.43 124.97 152.13 123.83 140.01
2026 137.71 119.03 129.71 158.82 129.10 146.09
2027 143.78 124.25 135.42 161.94 131.58 148.94
2028 148.88 128.60 140.16 166.20 135.23 152.89
2029 153.78 133.09 144.92 175.56 142.85 161.55
Nominal Levelized 93.10 77.39 86.36 102.41 82.17 93.74
2009$ Levelized 79.01 65.68 73.30 86.92 69.75 79.56
Greenhouse Gas Emissions Levels Greenhouse gas levels are expected to increase over the study period where no carbon
legislation is enacted that would affect the Western Interconnect. The carbon costs
discussed earlier in this chapter provide price signals to encourage greenhouse gas emission reductions following proposed legislation at the end of 2008. The prices were based on a Wood Mackenzie study including the entire U.S. electrical system. Figure
7.18 shows emissions across the Western Interconnect. Emissions are expected to
quickly fall to 2005 levels, and then more toward 1990 levels by the end of the study.
The Wood Mackenzie study assumed carbon offsets would help meet Western Interconnect carbon reduction goals. Carbon prices would need to be significantly higher to reduce the Western Interconnect to 1990 emissions levels without the offset
assumptions. The Wood Mackenzie study found that the Eastern Interconnect will lower
emissions at twice the level as the West, but that the West would reduce it emissions by a higher percentage.
Avista Corp 2009 Electric IRP – Public Draft 7-28
Chapter 7- Market Analysis
Figure 7.18: Western States Greenhouse Gas Emissions
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GHG Emissions
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Resource Dispatch
State-level RPS and carbon legislation will change resource dispatch decisions and affect future power supply expenses. Figure 7.19 illustrates that natural gas is expected to be 27 percent of power generation in 2010, 32 percent in 2020 and 44 percent in
2029. Coal decreases from 29 percent of Western Interconnect generation in 2010 to 16
percent in 2029. Non-hydro based renewables increase from 10 percent in 2010 to 25 percent in 2029. The reduction in coal generation is offset by new renewable generation, but load growth will primarily be met by natural gas-fired resources.
Public policy changes to encourage renewable energy development and reduce
greenhouse gas emissions will change the electric marketplace. Policy changes are likely to move the electric generation fleet toward its most volatile contributor—natural gas. These policies will displace low-cost and dependable coal-fired generation with
higher cost renewables and gas-fired generation having lower capacity factors (wind)
and higher marginal costs (natural gas). Regulated utilities are expected to recover stranded coal costs, requiring society to pay for duplicative resources as renewable and natural gas resources are built to satisfy RPS and emissions performance standards.
Wholesale prices will increase with the effects of the changing resource dispatch driven
by carbon emission limitations. New environment-driven investment, combined with
higher market prices, will lead to higher retail rates absent federal action.
Avista Corp 2009 Electric IRP – Public Draft 7-29
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 148 of 729
2009 Electric IRPAvista Corp 7-29
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Table 7.17: Annual Mid-Columbia Electric Prices ($/MWh)
DeterministicStochastic Mean
YearOnPeakOffPeakFlatOnPeakOffPeakFlat
2010 53.86 40.08 47.96 55.44 41.10 49.29
2011 54.40 40.35 48.38 56.70 42.10 50.44
2012 59.09 45.83 53.39 62.56 48.49 56.51
2013 63.62 50.37 57.95 68.92 54.34 62.68
2014 71.19 56.95 65.09 76.76 60.98 70.00
2015 80.72 65.87 74.36 86.94 70.07 79.71
2016 90.50 74.69 83.73 97.00 78.71 89.17
2017 95.46 78.86 88.32 103.78 84.00 95.27
2018107.32 91.28 100.45 119.24 97.01109.72
2019112.00 95.68 105.01 126.03 102.86 116.10
2020114.88 98.22 107.75 128.40 104.45 118.15
2021116.16 99.70 109.11 129.17 105.09 118.86
2022117.84 101.50 110.84 131.07 106.60 120.59
2023123.03 106.01 115.71 138.34 112.73 127.33
2024128.07 110.46 120.53 142.84 116.61 131.61
2025132.85 114.43 124.97 152.13 123.83 140.01
2026137.71 119.03 129.71 158.82 129.10 146.09
2027143.78 124.25 135.42 161.94 131.58 148.94
2028148.88 128.60 140.16 166.20 135.23 152.89
2029153.78 133.09 144.92 175.56 142.85 161.55
Nominal Levelized 93.10 77.39 86.36 102.4182.17 93.74
2009$ Levelized 79.01 65.68 73.30 86.9269.75 79.56
Greenhouse Gas Emissions Levels Greenhouse gas levels are expected to increase over the study period where no carbon
legislation is enacted that would affect the Western Interconnect. The carbon costs
discussed earlier in this chapter provide price signals to encourage greenhouse gas emission reductions following proposed legislation at the end of 2008. The prices were based on a Wood Mackenzie study including the entire U.S. electrical system. Figure
7.18 shows emissions across the Western Interconnect. Emissions are expected to
quickly fall to 2005 levels, and then more toward 1990 levels by the end of the study.
The Wood Mackenzie study assumed carbon offsets would help meet Western Interconnect carbon reduction goals. Carbon prices would need to be significantly higher to reduce the Western Interconnect to 1990 emissions levels without the offset
assumptions. The Wood Mackenzie study found that the Eastern Interconnect will lower
emissions at twice the level as the West, but that the West would reduce it emissions by a higher percentage.
Avista Corp 2009 Electric IRP – Public Draft 7-28
Chapter 7- Market Analysis
Figure 7.18: Western States Greenhouse Gas Emissions
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Resource Dispatch
State-level RPS and carbon legislation will change resource dispatch decisions and affect future power supply expenses. Figure 7.19 illustrates that natural gas is expected to be 27 percent of power generation in 2010, 32 percent in 2020 and 44 percent in
2029. Coal decreases from 29 percent of Western Interconnect generation in 2010 to 16
percent in 2029. Non-hydro based renewables increase from 10 percent in 2010 to 25 percent in 2029. The reduction in coal generation is offset by new renewable generation, but load growth will primarily be met by natural gas-fired resources.
Public policy changes to encourage renewable energy development and reduce
greenhouse gas emissions will change the electric marketplace. Policy changes are likely to move the electric generation fleet toward its most volatile contributor—natural gas. These policies will displace low-cost and dependable coal-fired generation with
higher cost renewables and gas-fired generation having lower capacity factors (wind)
and higher marginal costs (natural gas). Regulated utilities are expected to recover stranded coal costs, requiring society to pay for duplicative resources as renewable and natural gas resources are built to satisfy RPS and emissions performance standards.
Wholesale prices will increase with the effects of the changing resource dispatch driven
by carbon emission limitations. New environment-driven investment, combined with
higher market prices, will lead to higher retail rates absent federal action.
Avista Corp 2009 Electric IRP – Public Draft 7-29
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 149 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-30 Avista Corp
Chapter 7- Market Analysis
Figure 7.19: Base Case Western Interconnect Resource Energy
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Scenario Analysis
Avista Corp 2009 Electric IRP – Public Draft 7-30
This section evaluates the market with specific changes in individual assumptions. The
unconstrained carbon emissions scenario is modeled stochastically and
deterministically. It is modeled stochastically because it is used in the PRS analysis to determine the total cost of carbon legislation. The high gas price, low gas price and solar saturation scenarios are provided to show the impact of significant market
changes on electricity and carbon prices. Market scenarios were used in prior IRPs to
stress test the PRS against different market scenarios. Since the PRS accounts for a
range of possible outcomes in its risk analysis, the market scenario analysis section has been limited in this IRP.
Chapter 7- Market Analysis
Unconstrained Carbon Emissions
The unconstrained carbon emissions scenario quantifies the projected cost of
greenhouse gas legislation. The scenario is first studied deterministically, then
stochastically, with 250 iterations of varying natural gas prices, loads, wind, forced outages and hydro conditions. The assumptions are similar to the Base Case with a few
notable exceptions. First, the natural gas price forecast is lower because of less
demand for natural gas caused by the continued use of coal-fired generation. Without
carbon legislation, gas prices are expected to be $0.80 per Dth lower, an 8.6 percent decrease. The resources selected for this scenario are shown in Figure 7.20. The primary difference between this scenario’s resource selection and the Base Case is the
reduction in new natural gas resources and an increase in new coal resources. New
coal resources totaled 11,000 MW over the 20-year study; an equivalent amount of
CCCTs were removed from the portfolio. A few additional peaking resources were developed in this scenario.
Figure 7.20: Unconstrained Carbon Emissions Resource Selection
(5)
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Mid-Columbia market prices would be lower absent carbon legislation. The deterministic analysis found prices would be $22.43 per MWh lower on a nominal levelized basis over the forecast horizon; the stochastic analysis found prices would be $25.52 per MWh
(32 percent) lower. Prices are lower without carbon penalties because fuel and dispatch
costs for natural gas-fired plants are lower. A comparison of the two forecasts is shown in Figure 7.21.
Avista Corp 2009 Electric IRP – Public Draft 7-31
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 150 of 729
2009 Electric IRPAvista Corp 7-31
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.19: Base Case Western Interconnect Resource Energy
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Scenario Analysis
Avista Corp 2009 Electric IRP – Public Draft 7-30
This section evaluates the market with specific changes in individual assumptions. The
unconstrained carbon emissions scenario is modeled stochastically and
deterministically. It is modeled stochastically because it is used in the PRS analysis to determine the total cost of carbon legislation. The high gas price, low gas price and solar saturation scenarios are provided to show the impact of significant market
changes on electricity and carbon prices. Market scenarios were used in prior IRPs to
stress test the PRS against different market scenarios. Since the PRS accounts for a
range of possible outcomes in its risk analysis, the market scenario analysis section has been limited in this IRP.
Chapter 7- Market Analysis
Unconstrained Carbon Emissions
The unconstrained carbon emissions scenario quantifies the projected cost of
greenhouse gas legislation. The scenario is first studied deterministically, then
stochastically, with 250 iterations of varying natural gas prices, loads, wind, forced outages and hydro conditions. The assumptions are similar to the Base Case with a few
notable exceptions. First, the natural gas price forecast is lower because of less
demand for natural gas caused by the continued use of coal-fired generation. Without
carbon legislation, gas prices are expected to be $0.80 per Dth lower, an 8.6 percent decrease. The resources selected for this scenario are shown in Figure 7.20. The primary difference between this scenario’s resource selection and the Base Case is the
reduction in new natural gas resources and an increase in new coal resources. New
coal resources totaled 11,000 MW over the 20-year study; an equivalent amount of
CCCTs were removed from the portfolio. A few additional peaking resources were developed in this scenario.
Figure 7.20: Unconstrained Carbon Emissions Resource Selection
(5)
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Mid-Columbia market prices would be lower absent carbon legislation. The deterministic analysis found prices would be $22.43 per MWh lower on a nominal levelized basis over the forecast horizon; the stochastic analysis found prices would be $25.52 per MWh
(32 percent) lower. Prices are lower without carbon penalties because fuel and dispatch
costs for natural gas-fired plants are lower. A comparison of the two forecasts is shown in Figure 7.21.
Avista Corp 2009 Electric IRP – Public Draft 7-31
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 151 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-32 Avista Corp
Chapter 7- Market Analysis
Figure 7.21: Mid-Columbia Prices Comparison with and without Carbon Legislation
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Base Case- DeterministicBase Case- StochasticUnconstrained Carbon Emissions- DeterministicUnconstrained Carbon Emissions- Stochastic
Avista Corp 2009 Electric IRP – Public Draft 7-32
Figure 7.22 illustrates the difference between carbon emissions with and without the
carbon adder included in the Base Case. Carbon emissions would be 11 percent higher
in 2020 and 40 percent higher in 2029 without the Base Case carbon adder. The increased emissions are caused by higher dispatch levels for coal-fired resources (Figure 7.23) relative to the Base Case. Carbon emission impacts on coal plants could
increase overall fuel costs across the Western Interconnect by 16.3 percent or $42.5
billion in present value terms (2009 dollars). Annual cost increases are shown in Figure
7.24. Carbon legislation adds $328 million in present value term (2009 dollars) over the study period for operations, but reduces capital and other non-O&M costs by $17.1
billion. In total, carbon legislation on a 20 year net present value calculation will
increase costs by $25.7 billion (10 percent).
Chapter 7- Market Analysis
Figure 7.22: Western U.S. Carbon Emissions Comparison
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Figure 7.23: Unconstrained Carbon Scenrio Resource Dispatch
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Solar Oil Gas
Gas Peakers Total Resource Output
Avista Corp 2009 Electric IRP – Public Draft 7-33
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 152 of 729
2009 Electric IRPAvista Corp 7-33
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.21: Mid-Columbia Prices Comparison with and without Carbon Legislation
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Base Case- DeterministicBase Case- StochasticUnconstrained Carbon Emissions- DeterministicUnconstrained Carbon Emissions- Stochastic
Avista Corp 2009 Electric IRP – Public Draft 7-32
Figure 7.22 illustrates the difference between carbon emissions with and without the
carbon adder included in the Base Case. Carbon emissions would be 11 percent higher
in 2020 and 40 percent higher in 2029 without the Base Case carbon adder. The increased emissions are caused by higher dispatch levels for coal-fired resources (Figure 7.23) relative to the Base Case. Carbon emission impacts on coal plants could
increase overall fuel costs across the Western Interconnect by 16.3 percent or $42.5
billion in present value terms (2009 dollars). Annual cost increases are shown in Figure
7.24. Carbon legislation adds $328 million in present value term (2009 dollars) over the study period for operations, but reduces capital and other non-O&M costs by $17.1
billion. In total, carbon legislation on a 20 year net present value calculation will
increase costs by $25.7 billion (10 percent).
Chapter 7- Market Analysis
Figure 7.22: Western U.S. Carbon Emissions Comparison
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Figure 7.23: Unconstrained Carbon Scenrio Resource Dispatch
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Gas Peakers Total Resource Output
Avista Corp 2009 Electric IRP – Public Draft 7-33
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 153 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-34 Avista Corp
Chapter 7- Market Analysis
Figure 7.24: Western Interconnect Fuel Cost Comparison
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Base Case Difference
Unconstrained Carbon
High and Low Natural Gas Prices The High and Low Natural Gas Price scenarios illustrate the range in Mid-Columbia
electricity prices for different ranges of natural gas prices. These scenarios also keep
carbon emissions at the same level as the Base Case; therefore, a carbon price can be
derived if gas prices change from the Base Case assumptions. Figure 7.25 shows natural gas prices used for these analyses at the Henry Hub. The monthly and basin differential prices remain the same as the Base Case. The objective of the Low Natural
Gas Price scenario is to maintain the real price level at the 2010 level throughout the
study and only allow nominal prices to increase with inflation. The levelized price is
$7.50 per Dth (nominal) and $6.36 per Dth (2009 dollars) in this scenario. The High Natural Gas Price scenario uses a Wood Mackenzie price forecast from the summer of
2008. Prices in this scenario did not include the current recession and subsequent
market effects as well as including lower levels of unconventional gas supplies. The
levelized price is $12.17 per Dth (nominal) and $10.33 per Dth (2009 dollars) for the High Natural Gas Price scenario.
Avista Corp 2009 Electric IRP – Public Draft 7-34
Chapter 7- Market Analysis
Figure 7.25: Henry Hub Prices for High and Low Natural Gas Price Scenarios
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Base Case
Low Gas Prices
High Gas Prices
As discussed throughout this chapter, carbon prices are dependent on natural gas prices. The objective of the High and Low Gas Price scenarios is to keep carbon
emissions at the same level as in the Base Case. To achieve these levels, the carbon
emission prices shown in Figure 7.26 were used. The nominal levelized greenhouse
gas price was $47.12 per short ton for the High Gas Price scenario. It was $24.12 for the Low Gas Price scenario compared to the Base Case of $38.61 per short ton. The
real carbon prices in 2009 dollars are $40.06 (Base Case), $20.49 (Low Gas) and
$32.83 (High Gas) per short ton respectively.
The new resources selected by AURORAxmp in the High and Low Natural Gas Price
scenarios do not differ greatly from the Base Case. This is mostly due to RPS
assumptions remaining the same between all cases and because traditional coal is not
an option for most U.S. utilities in the Western Interconnect; therefore, the model uses a mix of gas, nuclear, sequestered coal, and low capacity factor wind or solar resources. The High Gas Price scenario is displayed in Figure 7.27. The model in this case
selected more carbon sequestration than in the Base Case and added nuclear
generation to the resource mix. The model also retired three gigawatts of natural gas
and one gigawatt of coal-fired generation.
Avista Corp 2009 Electric IRP – Public Draft 7-35
New resources for the Low Gas Price scenario are shown in Figure 7.28. In the Low
Gas Price environment, the model selected only new gas-fired resources in addition to
the RPS resources. The model retired four gigawatts of older natural gas and two gigawatts of coal-fired plants.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 154 of 729
2009 Electric IRPAvista Corp 7-35
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.24: Western Interconnect Fuel Cost Comparison
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Base Case Difference
Unconstrained Carbon
High and Low Natural Gas Prices The High and Low Natural Gas Price scenarios illustrate the range in Mid-Columbia
electricity prices for different ranges of natural gas prices. These scenarios also keep
carbon emissions at the same level as the Base Case; therefore, a carbon price can be
derived if gas prices change from the Base Case assumptions. Figure 7.25 shows natural gas prices used for these analyses at the Henry Hub. The monthly and basin differential prices remain the same as the Base Case. The objective of the Low Natural
Gas Price scenario is to maintain the real price level at the 2010 level throughout the
study and only allow nominal prices to increase with inflation. The levelized price is
$7.50 per Dth (nominal) and $6.36 per Dth (2009 dollars) in this scenario. The High Natural Gas Price scenario uses a Wood Mackenzie price forecast from the summer of
2008. Prices in this scenario did not include the current recession and subsequent
market effects as well as including lower levels of unconventional gas supplies. The
levelized price is $12.17 per Dth (nominal) and $10.33 per Dth (2009 dollars) for the High Natural Gas Price scenario.
Avista Corp 2009 Electric IRP – Public Draft 7-34
Chapter 7- Market Analysis
Figure 7.25: Henry Hub Prices for High and Low Natural Gas Price Scenarios
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Base Case
Low Gas Prices
High Gas Prices
As discussed throughout this chapter, carbon prices are dependent on natural gas prices. The objective of the High and Low Gas Price scenarios is to keep carbon
emissions at the same level as in the Base Case. To achieve these levels, the carbon
emission prices shown in Figure 7.26 were used. The nominal levelized greenhouse
gas price was $47.12 per short ton for the High Gas Price scenario. It was $24.12 for the Low Gas Price scenario compared to the Base Case of $38.61 per short ton. The
real carbon prices in 2009 dollars are $40.06 (Base Case), $20.49 (Low Gas) and
$32.83 (High Gas) per short ton respectively.
The new resources selected by AURORAxmp in the High and Low Natural Gas Price
scenarios do not differ greatly from the Base Case. This is mostly due to RPS
assumptions remaining the same between all cases and because traditional coal is not
an option for most U.S. utilities in the Western Interconnect; therefore, the model uses a mix of gas, nuclear, sequestered coal, and low capacity factor wind or solar resources. The High Gas Price scenario is displayed in Figure 7.27. The model in this case
selected more carbon sequestration than in the Base Case and added nuclear
generation to the resource mix. The model also retired three gigawatts of natural gas
and one gigawatt of coal-fired generation.
Avista Corp 2009 Electric IRP – Public Draft 7-35
New resources for the Low Gas Price scenario are shown in Figure 7.28. In the Low
Gas Price environment, the model selected only new gas-fired resources in addition to
the RPS resources. The model retired four gigawatts of older natural gas and two gigawatts of coal-fired plants.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 155 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-36 Avista Corp
Chapter 7- Market Analysis
Figure 7.26: Greenhouse Gas Prices for High and Low Natural Gas Price Scenarios
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Figure 7.27: High Natural Gas Prices Scenario Resource Selection
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Geothermal BiomassHydroWindSolarCoal SeqNuclearCCCTSCCTCoal- retireNG- retire Oil- retireEnergy (aGW)
Avista Corp 2009 Electric IRP – Public Draft 7-36
Chapter 7- Market Analysis
Figure 7.28: Low Natural Gas Prices Scenario Resource Selection
(5)
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Geothermal BiomassHydroWindSolarCoal SeqNuclearCCCTSCCTCoal- retireNG- retire Oil- retireEnergy (aGW)
As expected, Mid-Columbia electricity prices are higher in the High Gas Price scenario than in the Base Case or the Low Gas Price scenarios. The nominal levelized price for
the High Gas Price scenario is $102.61 per MWh. The Low Gas Price scenario is
$67.48 per MWh, compared to $86.36 per MWh in the Base Case. Prices are $87.10,
$57.24 and $73.30 per MWh in 2009 dollars, respectively. These prices are graphically presented in Figure 7.29. Market prices follow natural gas prices because of the high
correlation between these two variables.
Avista Corp 2009 Electric IRP – Public Draft 7-37
The High Gas Price scenario lowers the contribution of natural gas in the Western Interconnect fuel mix and adds coal sequestration and nuclear projects beginning in 2020 (see Figure 7.30). The Low Gas Price scenario has a similar dispatch as the Base
Case; it includes an increase in natural gas-fired resources (see Figure 7.31). The
contribution from traditional coal-fired resources shrinks to lower carbon emissions in both scenarios.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 156 of 729
2009 Electric IRPAvista Corp 7-37
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.26: Greenhouse Gas Prices for High and Low Natural Gas Price Scenarios
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Figure 7.27: High Natural Gas Prices Scenario Resource Selection
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GeothermalBiomassHydroWindSolarCoal SeqNuclearCCCTSCCTCoal- retireNG- retireOil- retireEnergy (aGW)
Avista Corp 2009 Electric IRP – Public Draft 7-36
Chapter 7- Market Analysis
Figure 7.28: Low Natural Gas Prices Scenario Resource Selection
(5)
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Geothermal BiomassHydroWindSolarCoal SeqNuclearCCCTSCCTCoal- retireNG- retire Oil- retireEnergy (aGW)
As expected, Mid-Columbia electricity prices are higher in the High Gas Price scenario than in the Base Case or the Low Gas Price scenarios. The nominal levelized price for
the High Gas Price scenario is $102.61 per MWh. The Low Gas Price scenario is
$67.48 per MWh, compared to $86.36 per MWh in the Base Case. Prices are $87.10,
$57.24 and $73.30 per MWh in 2009 dollars, respectively. These prices are graphically presented in Figure 7.29. Market prices follow natural gas prices because of the high
correlation between these two variables.
Avista Corp 2009 Electric IRP – Public Draft 7-37
The High Gas Price scenario lowers the contribution of natural gas in the Western Interconnect fuel mix and adds coal sequestration and nuclear projects beginning in 2020 (see Figure 7.30). The Low Gas Price scenario has a similar dispatch as the Base
Case; it includes an increase in natural gas-fired resources (see Figure 7.31). The
contribution from traditional coal-fired resources shrinks to lower carbon emissions in both scenarios.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 157 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-38 Avista Corp
Chapter 7- Market Analysis
Figure 7.29: Mid-Columbia Electric Price Forecast
$0
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Low Natural Gas Prices
Figure 7.30: Resource Dispatch- High Gas Price Scenario
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av
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Hydro Nuclear Geothermal
Coal IGCC Coal IGCC Coal SeqOther Renewable Wind Solar
Oil Gas Gas PeakersTotal Resource Output
Avista Corp 2009 Electric IRP – Public Draft 7-38
Chapter 7- Market Analysis
Figure 7.31: Resource Dispatch- Low Gas Price Scenario
0%
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av
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g
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a
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a
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s
Hydro Nuclear GeothermalCoalIGCC Coal IGCC Coal SeqOther Renewable Wind SolarOilGasGas PeakersTotal Resource Output
Solar Saturation It is helpful to use the IRP process to identify and understand potential market changes,
rather than only focus on what is or is not included in the Company’s PRS. Solar has
caught the attention of many utility planners, government officials and customers
because of positive environmental characteristics, potential line loss reductions through distributed energy, free fuel and high correlations with on-peak load. Solar has many
upside potentials, but is still financially prohibitive because of its high capital costs and
limited generation. The Solar Saturation scenario was developed to understand the
market reaction to a significant decrease in the price of photovoltaic solar. Natural gas, carbon prices and load remain the same in this scenario. The only change is an 80-percent reduction in installed photovoltaic solar costs. The scenario is not used for the
PRS, but is included to identify how market prices and greenhouse gas emissions would
be impacted by a significant decrease in photovoltaic solar costs.
If photovoltaic solar became 80 percent less expensive, the amount of solar added
above and beyond the RPS levels is 75 GW, for a total of 90 GW of solar capacity by
2029 (Figure 7.32). Even with the added solar, it only contributes 23,000 aMW of
energy due to the low capacity factor. Solar is not an ideal fit to meet winter peak in northern areas (5 percent winter capacity contribution in northern states) so another technology must be used or additional solar must be added to compensate for the lower
winter capacity.
Avista Corp 2009 Electric IRP – Public Draft 7-39
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 158 of 729
2009 Electric IRPAvista Corp 7-39
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.29: Mid-Columbia Electric Price Forecast
$0
$20
$40
$60
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$120
$140
$160
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20
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9
pr
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p
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M
W
h
Base Case
High Natural Gas Prices
Low Natural Gas Prices
Figure 7.30: Resource Dispatch- High Gas Price Scenario
0%
20%
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20
1
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av
e
r
a
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e

g
i
g
a
w
a
t
t
s
HydroNuclearGeothermal
CoalIGCC CoalIGCC Coal SeqOther RenewableWindSolar
OilGasGas PeakersTotal Resource Output
Avista Corp 2009 Electric IRP – Public Draft 7-38
Chapter 7- Market Analysis
Figure 7.31: Resource Dispatch- Low Gas Price Scenario
0%
20%
40%
60%
80%
100%
20
1
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1
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120
160
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av
e
r
a
g
e

g
i
g
a
w
a
t
t
s
Hydro Nuclear GeothermalCoalIGCC Coal IGCC Coal SeqOther Renewable Wind SolarOilGasGas PeakersTotal Resource Output
Solar Saturation It is helpful to use the IRP process to identify and understand potential market changes,
rather than only focus on what is or is not included in the Company’s PRS. Solar has
caught the attention of many utility planners, government officials and customers
because of positive environmental characteristics, potential line loss reductions through distributed energy, free fuel and high correlations with on-peak load. Solar has many
upside potentials, but is still financially prohibitive because of its high capital costs and
limited generation. The Solar Saturation scenario was developed to understand the
market reaction to a significant decrease in the price of photovoltaic solar. Natural gas, carbon prices and load remain the same in this scenario. The only change is an 80-percent reduction in installed photovoltaic solar costs. The scenario is not used for the
PRS, but is included to identify how market prices and greenhouse gas emissions would
be impacted by a significant decrease in photovoltaic solar costs.
If photovoltaic solar became 80 percent less expensive, the amount of solar added
above and beyond the RPS levels is 75 GW, for a total of 90 GW of solar capacity by
2029 (Figure 7.32). Even with the added solar, it only contributes 23,000 aMW of
energy due to the low capacity factor. Solar is not an ideal fit to meet winter peak in northern areas (5 percent winter capacity contribution in northern states) so another technology must be used or additional solar must be added to compensate for the lower
winter capacity.
Avista Corp 2009 Electric IRP – Public Draft 7-39
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 159 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-40 Avista Corp
Chapter 7- Market Analysis
Figure 7.32: Solar Saturation Scenario Resource Selection
(5)
10
25
40
55
70
85
100
115
130
145
160
20
1
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9
gi
g
a
w
a
t
t
s
Geothermal BiomassHydroWindSolarCoal SeqCCCTSCCTCoal- retire NG- retireOil- retire Energy (aGW)
Adding 75 GW of solar did not have a significant impact on Mid-Columbia market prices.
There was only a reduction of $3.50 per MWh (4 percent) levelized (nominal), though second and third quarters (high solar months in the Northwest) had lower on-peak power prices than in the Base Case. Prices did not change because the marginal cost
of power was still set by gas-fired resources and because solar does not produce power
at night. More solar would need to be added and a low-cost storage technology
identified to effectively lower market prices. Greenhouse gas emissions were reduced by 10 percent from the Base Case (see Figure 7.33) in this scenario.
More solar generation reduces the Western Interconnect’s carbon footprint. Carbon
reduction is primary driven by a decrease in natural gas-fired generation. Coal energy increased by 1,000 aMW over the Base Case while natural gas-fired production fell by 18,000 aMW in this scenario (see Figure 7.34). The increase in coal generation was
from existing plants operating in off peak hours to compensate for the lack of night time
solar generation, while the reduction in natural gas-fired generation is a result of
decreased need due to the influx of solar resources to serve on-peak load. This study illustrates that market prices in the Northwest will not radically change in spite of a large amount of new solar generation being added to the system, but greenhouse gas
emissions will fall along with natural gas prices.
Avista Corp 2009 Electric IRP – Public Draft 7-40
Chapter 7- Market Analysis
Figure 7.33: Western Interconnect Carbon Emissions Comparison
150
170
190
210
230
250
270
290
310
330
350
20
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sh
o
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t
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s
Base Case
2005 Levels
1990 Levels
Solar Saturation
Figure 7.34: Resource Dispatch- Solar Saturation Scenario
Avista Corp 2009 Electric IRP – Public Draft 7-41
0%
20%
40%
60%
80%
100%
20
1
0
20
1
1
20
1
2
20
1
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1
4
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1
5
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1
6
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1
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1
8
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1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
pe
r
c
e
n
t

o
f

e
n
e
r
g
y
0
40
80
120
160
200
av
e
r
a
g
e

g
i
g
a
w
a
t
t
s
Hydro Nuclear GeothermalCoalIGCC Coal IGCC Coal Seq
Other Renewable Wind SolarOilGasGas PeakersTotal Resource Output
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 160 of 729
2009 Electric IRPAvista Corp 7-41
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Figure 7.32: Solar Saturation Scenario Resource Selection
(5)
10
25
40
55
70
85
100
115
130
145
160
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
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1
5
20
1
6
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1
7
20
1
8
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1
9
20
2
0
20
2
1
20
2
2
20
2
3
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2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
gi
g
a
w
a
t
t
s
GeothermalBiomassHydroWindSolarCoal SeqCCCTSCCTCoal- retireNG- retireOil- retireEnergy (aGW)
Adding 75 GW of solar did not have a significant impact on Mid-Columbia market prices.
There was only a reduction of $3.50 per MWh (4 percent) levelized (nominal), though second and third quarters (high solar months in the Northwest) had lower on-peak power prices than in the Base Case. Prices did not change because the marginal cost
of power was still set by gas-fired resources and because solar does not produce power
at night. More solar would need to be added and a low-cost storage technology
identified to effectively lower market prices. Greenhouse gas emissions were reduced by 10 percent from the Base Case (see Figure 7.33) in this scenario.
More solar generation reduces the Western Interconnect’s carbon footprint. Carbon
reduction is primary driven by a decrease in natural gas-fired generation. Coal energy increased by 1,000 aMW over the Base Case while natural gas-fired production fell by 18,000 aMW in this scenario (see Figure 7.34). The increase in coal generation was
from existing plants operating in off peak hours to compensate for the lack of night time
solar generation, while the reduction in natural gas-fired generation is a result of
decreased need due to the influx of solar resources to serve on-peak load. This study illustrates that market prices in the Northwest will not radically change in spite of a large amount of new solar generation being added to the system, but greenhouse gas
emissions will fall along with natural gas prices.
Avista Corp 2009 Electric IRP – Public Draft 7-40
Chapter 7- Market Analysis
Figure 7.33: Western Interconnect Carbon Emissions Comparison
150
170
190
210
230
250
270
290
310
330
350
20
1
0
20
1
1
20
1
2
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9
sh
o
r
t

t
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n
s
Base Case
2005 Levels
1990 Levels
Solar Saturation
Figure 7.34: Resource Dispatch- Solar Saturation Scenario
Avista Corp 2009 Electric IRP – Public Draft 7-41
0%
20%
40%
60%
80%
100%
20
1
0
20
1
1
20
1
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1
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Other Renewable Wind SolarOilGasGas PeakersTotal Resource Output
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 161 of 729
Chapter 7 - Market Analysis
2009 Electric IRP7-42 Avista Corp
Chapter 7- Market Analysis
Avista Corp 2009 Electric IRP – Public Draft 7-42
Market Analysis Summary
Market analysis is a key component of the IRP. The market is where the Company
balances its load and resource positions. Without a firm understanding of the
marketplace and how it is affected by public policy, it is difficult to provide a comprehensive examination of potential resource being evaluated by Avista and the utility industry. A summary of key drivers for the 2009 IRP market forecast are
presented in Table 7.18 and Table 7.19. These tables present 10- and 20-year levelized
costs in nominal and 2009 dollars. The 2007 IRP forecasts are included for comparison. Price expectations have increased since the 2007 IRP. The 10-year Malin natural gas price forecast increased 20 percent, and the Mid-Columbia electric price forecast
increased 27 percent from the 2007 IRP. Large increases are the result of carbon
mitigation costs. Without greenhouse gas legislation, Malin natural gas and Mid-
Columbia electric prices would only have increased seven percent from the previous IRP forecasts.
New legislation and regulations impacting the electric system are on the horizon. It does
not matter if the intent is to decrease greenhouse gas emissions, make generation greener, promote energy independence or affect reliability—power costs will increase because new capacity and transmission resources are needed to replace aging
resources and meet new load growth. Carbon and RPS legislation will diversify fuel
supplies, but will also increase demand for cleaner burning natural gas.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 162 of 729
2009 Electric IRPAvista Corp 7-43
Chapter 7 - Market AnalysisChapter 7- Market Analysis
Avista Corp 2009 Electric IRP – Public Draft 7-42
Market Analysis Summary
Market analysis is a key component of the IRP. The market is where the Company
balances its load and resource positions. Without a firm understanding of the
marketplace and how it is affected by public policy, it is difficult to provide a comprehensive examination of potential resource being evaluated by Avista and the utility industry. A summary of key drivers for the 2009 IRP market forecast are
presented in Table 7.18 and Table 7.19. These tables present 10- and 20-year levelized
costs in nominal and 2009 dollars. The 2007 IRP forecasts are included for comparison. Price expectations have increased since the 2007 IRP. The 10-year Malin natural gas price forecast increased 20 percent, and the Mid-Columbia electric price forecast
increased 27 percent from the 2007 IRP. Large increases are the result of carbon
mitigation costs. Without greenhouse gas legislation, Malin natural gas and Mid-
Columbia electric prices would only have increased seven percent from the previous IRP forecasts.
New legislation and regulations impacting the electric system are on the horizon. It does
not matter if the intent is to decrease greenhouse gas emissions, make generation greener, promote energy independence or affect reliability—power costs will increase because new capacity and transmission resources are needed to replace aging
resources and meet new load growth. Carbon and RPS legislation will diversify fuel
supplies, but will also increase demand for cleaner burning natural gas.
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Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 163 of 729
Chapter 8- Preferred Resource Strategy 8. Preferred Resource Strategy Introduction This chapter summarizes the 2009 Integrated Resources Plan’s (IRP) Preferred Resource Strategy (PRS), along with its potential cost and risks. It details the planning and resource decision methodologies; describes the strategy, climate change ramifications and how the PRS might evolve if base forecasts of future conditions are incorrect.The 2009 PRS is the least-cost achievable plan accounting for climate change and fuel supply and cost risks. The major change from the 2007 PRS is a greater reliance on wind to meet renewable portfolio standards (RPS), rather than a combination of wind and other renewables. More wind was selected because it is the only renewable resource available in quantities large enough to affect utility planning. It also is more actionable and controllable by the utility, allowing for less reliance on third-party developers that might or might not respond to utility request for proposal (RFP) efforts. It is likely that the 2009 PRS will change as new information becomes available on cost, resource options and legislative actions. However, the strategy contained in this chapter is based on the best
information available at this time.
Chapter Highlights
• Avista’s physical energy needs begin in 2018 and capacity needs begin in 2015.
• The first supply-side acquisition is 150 MW of wind by the end of 2012.
• Conservation additions provide 26 percent of new supplies through 2020.
• A 250 MW natural gas-fired combined cycle project is required by 2020, but could be required as soon as 2015.
• Large hydro upgrades could change the PRS if further study determines them
to be economically viable.
Supply-Side Resource Acquisition History
Avista sold its 210 MW share of the Centralia coal plant in 2001 and replaced its generation with natural gas-fired projects (see Figure 8.1). After the Centralia sale,
Avista acquired 32 MW of gas-fired peaking capacity and 287 MW of intermediate load gas-fired capacity. In addition to gas, Avista contracted for 35 MW of wind capacity from
Stateline and added 35.5 MW of new capacity through upgrades to its hydro fleet. Avista will gain control of the output for the 270 MW Lancaster Generating Facility
(Rathdrum GS) on January 1, 2010. Avista also expects to upgrade its Nine Mile Falls and Noxon Rapids hydro facilities over the next five years.
Avista Corp 2009 Electric IRP- Public Draft 8-1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 164 of 729
2009 Electric IRPAvista Corp 8-1
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
8. Preferred Resource Strategy
Introduction
This chapter summarizes the 2009
Integrated Resources Plan’s (IRP) Preferred Resource Strategy (PRS), along with its potential cost and risks. It details the
planning and resource decision
methodologies; describes the strategy,
climate change ramifications and how the PRS might evolve if base forecasts of future conditions are incorrect.
The 2009 PRS is the least-cost achievable plan accounting for climate change and fuel supply and cost risks. The major change from the 2007 PRS is a greater reliance on wind
to meet renewable portfolio standards (RPS), rather than a combination of wind and other
renewables. More wind was selected because it is the only renewable resource available
in quantities large enough to affect utility planning. It also is more actionable and controllable by the utility, allowing for less reliance on third-party developers that might or might not respond to utility request for proposal (RFP) efforts. It is likely that the 2009
PRS will change as new information becomes available on cost, resource options and
legislative actions. However, the strategy contained in this chapter is based on the best information available at this time.
Chapter Highlights
• Avista’s physical energy needs begin in 2018 and capacity needs begin in 2015.
• The first supply-side acquisition is 150 MW of wind by the end of 2012.
• Conservation additions provide 26 percent of new supplies through 2020.
• A 250 MW natural gas-fired combined cycle project is required by 2020, but could be required as soon as 2015.
• Large hydro upgrades could change the PRS if further study determines them
to be economically viable.
Supply-Side Resource Acquisition History
Avista sold its 210 MW share of the Centralia coal plant in 2001 and replaced its
generation with natural gas-fired projects (see Figure 8.1). After the Centralia sale, Avista acquired 32 MW of gas-fired peaking capacity and 287 MW of intermediate load
gas-fired capacity. In addition to gas, Avista contracted for 35 MW of wind capacity from
Stateline and added 35.5 MW of new capacity through upgrades to its hydro fleet.
Avista will gain control of the output for the 270 MW Lancaster Generating Facility (Rathdrum GS) on January 1, 2010. Avista also expects to upgrade its Nine Mile Falls and Noxon Rapids hydro facilities over the next five years.
Avista Corp 2009 Electric IRP- Public Draft 8-1
Site of the Proposed Reardan Wind Project
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 165 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-2 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.1: Resource Acquisition History
1,100
1,300
1,500
1,700
1,900
2,100
2,300
2,500
19
9
4
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9
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Resource Selection Process
Avista uses several decision support systems to develop its resource strategy. The PRS
is based on results from the PRiSM model. The model’s objective function is to meet
resource deficits while accounting for overall cost, risk and other constraints. This method replaces the traditional hand-picked portfolio comparison approach. The AURORAxmp model, discussed in the Market Analysis chapter, calculates the operating
margin (value) of Avista’s existing resource portfolio and each resource option in each
of the 250 potential future outcomes. Then the PRiSM model uses these values
combined with capital and fixed operating costs to select the best resource mix to meet capacity, energy, RPS and other requirements.
PRiSM
Avista staff developed the PRiSM model in 2002 to help select the PRS. The PRiSM model uses a linear programming routine to support complex decision making with single or multiple objectives. Linear programs provide optimal values for variables using
given system constraints.
Avista Corp 2009 Electric IRP- Public Draft 8-2
Chapter 8- Preferred Resource Strategy
Overview of the PRiSM Model
PRiSM has six basic inputs:
1. Load deficits (energy and capacity);
2. RPS standards; 3. Avista’s existing portfolio’s costs (load and resources) and operating margins
(resources);
4. Fixed operating costs, return on capital, interest and taxes for each resource
option;5. Generation levels for existing resources and new resource options; and 6. Carbon emission levels for existing resources and new resource options.
PRiSM uses these inputs to develop an optimal resource mix over time at varying levels
of cost and consummate risk level. It weights the first 10 years more heavily than the outer years to recognize the importance of near-term decisions on today’s utility
interests (i.e., customers and shareholders). A simplified view of the linear programming
objective function formula is provided below.
PRiSM Objective Function
Minimize: (X1 * NPV2010-2019) + (X2 * NPV2010-2029) + (X3 * NPV2010-2059)
Where:X1 = Weight of net costs over the first 10 years;
X2 = Weight of net costs over 20 years of the plan;
X3 = Weight of net costs over the next 50 years; and
NPV is the net present value of total cost (existing resource marginal costs, all future resource fixed and variable costs, and all future conservation costs and the net short-term market sales/purchases).
Subject to: Capacity needs;
Energy needs; Washington RPS;
Resource limitations;
Resource availability; and
Risk tolerance
The hypothetical resource set is used to develop an Efficient Frontier. The 2009 IRP
Efficient Frontier captures the optimal resource selection, given constraints at each level
of cost and risk. Figure 8.2 illustrates the Efficient Frontier. The optimal point on the
curve depends on the level of risk Avista and its customers can accept. As discussed in the 2007 IRP, utility-scale resource options are limited because of environmental
legislation. Two portfolio planning assumptions from the 2007 IRP are not continued for
this plan: RPS requirements can no longer be met entirely with utility purchases of
renewable energy certificates (RECs), and long-term fixed-price natural gas is not available to the portfolio. The loss of these options further limits resource choices compared with the 2007 IRP. Avista does not expect it will be able to acquire sufficient
RECs at a reasonable price to meet the RPS, and REC purchases expose the
Company to potential volatility that asset ownership would not. For resource planning
Avista Corp 2009 Electric IRP- Public Draft 8-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 166 of 729
2009 Electric IRPAvista Corp 8-3
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Figure 8.1: Resource Acquisition History
1,100
1,300
1,500
1,700
1,900
2,100
2,300
2,500
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
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9
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20
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Hydro UpgradesLa
n
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t
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r
1/
2

C
S
2
Resource Selection Process
Avista uses several decision support systems to develop its resource strategy. The PRS
is based on results from the PRiSM model. The model’s objective function is to meet
resource deficits while accounting for overall cost, risk and other constraints. This method replaces the traditional hand-picked portfolio comparison approach. The AURORAxmp model, discussed in the Market Analysis chapter, calculates the operating
margin (value) of Avista’s existing resource portfolio and each resource option in each
of the 250 potential future outcomes. Then the PRiSM model uses these values
combined with capital and fixed operating costs to select the best resource mix to meet capacity, energy, RPS and other requirements.
PRiSM
Avista staff developed the PRiSM model in 2002 to help select the PRS. The PRiSM model uses a linear programming routine to support complex decision making with single or multiple objectives. Linear programs provide optimal values for variables using
given system constraints.
Avista Corp 2009 Electric IRP- Public Draft 8-2
Chapter 8- Preferred Resource Strategy
Overview of the PRiSM Model
PRiSM has six basic inputs:
1. Load deficits (energy and capacity);
2. RPS standards; 3. Avista’s existing portfolio’s costs (load and resources) and operating margins
(resources);
4. Fixed operating costs, return on capital, interest and taxes for each resource
option;5. Generation levels for existing resources and new resource options; and 6. Carbon emission levels for existing resources and new resource options.
PRiSM uses these inputs to develop an optimal resource mix over time at varying levels
of cost and consummate risk level. It weights the first 10 years more heavily than the outer years to recognize the importance of near-term decisions on today’s utility
interests (i.e., customers and shareholders). A simplified view of the linear programming
objective function formula is provided below.
PRiSM Objective Function
Minimize: (X1 * NPV2010-2019) + (X2 * NPV2010-2029) + (X3 * NPV2010-2059)
Where:X1 = Weight of net costs over the first 10 years;
X2 = Weight of net costs over 20 years of the plan;
X3 = Weight of net costs over the next 50 years; and
NPV is the net present value of total cost (existing resource marginal costs, all future resource fixed and variable costs, and all future conservation costs and the net short-term market sales/purchases).
Subject to: Capacity needs;
Energy needs; Washington RPS;
Resource limitations;
Resource availability; and
Risk tolerance
The hypothetical resource set is used to develop an Efficient Frontier. The 2009 IRP
Efficient Frontier captures the optimal resource selection, given constraints at each level
of cost and risk. Figure 8.2 illustrates the Efficient Frontier. The optimal point on the
curve depends on the level of risk Avista and its customers can accept. As discussed in the 2007 IRP, utility-scale resource options are limited because of environmental
legislation. Two portfolio planning assumptions from the 2007 IRP are not continued for
this plan: RPS requirements can no longer be met entirely with utility purchases of
renewable energy certificates (RECs), and long-term fixed-price natural gas is not available to the portfolio. The loss of these options further limits resource choices compared with the 2007 IRP. Avista does not expect it will be able to acquire sufficient
RECs at a reasonable price to meet the RPS, and REC purchases expose the
Company to potential volatility that asset ownership would not. For resource planning
Avista Corp 2009 Electric IRP- Public Draft 8-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 167 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-4 Avista Corp
Chapter 8- Preferred Resource Strategy
purposes, REC purchases are an option, but not in excess of 45,000 per year. Work
since the 2007 IRP have found that long-term fixed-price natural gas contracts consume
inordinate amounts of Company capital.
Figure 8.2: Efficient Frontier Curve
cost
ri
s
k
Least Cost
Least Risk
Constraints
As discussed earlier in this chapter, constraints are necessary to solve for the optimal
resource strategy. Some constraints are physical and others are societal. The major resource constraints are: capacity and energy needs, and Washington’s RPS and emissions performance standard (SB 6001).
The PRiSM model is limited by resource type and size. It can select from combined-
and simple-cycle natural gas-fired combustion turbines, wind and small hydro upgrades. Sequestered coal plants are available beginning in 2023. A new enhancement to PRiSM for the 2009 IRP cycle ensures it selects resources in minimum block sizes
rather than mathematically optimal increments. This change better reflects how Avista
actually acquires resources. It also emulates how the Company manages lumpy resource additions and that resource positions are not perfectly balanced with load each year. PRiSM is allowed to model Avista’s portfolio to be as much as 50 MW short or 200
MW long in any given planning year.
Washington’s RPS fundamentally changed how Avista plans to meet future loads. Historically an Efficient Frontier was created with the least-cost strategy on one end and the least-risk strategy on the other. Next, management decided where they wanted to
be on the continuums, based on risk appetite. Recent least-cost strategies typically
Avista Corp 2009 Electric IRP- Public Draft 8-4
Chapter 8- Preferred Resource Strategy
consisted of gas-fired resources. Portfolios with less risk replaced some of the gas-fired
resources with wind, other renewables and coal. Past IRPs identified strategies that
included these risk-reduction resources. For illustration, these strategies are
represented on the Efficient Frontier as a red dot in Figure 8.3. Washington laws requiring the acquisition of renewable generation, or RECs, and the near-ban on new
coal-fired facilities, removes the lowest-cost portion of the efficient frontier, illustrated in
blue in Figure 8.3. The added constraints greatly reduce the Company’s ability to
reduce future costs. The 2009 IRP is therefore based on the least-cost strategy that still complies with state laws, rather than a portfolio selected on a full vetting of cost and risk.
Figure 8.3: Efficient Frontier in a Constrained Environment
cost
ri
s
k
Least Cost
Least Risk
PRS
Resource Shortages
Avista has adequate resources to meet annual physical energy and capacity needs until
2015. See Figure 8.4. The graphic accounts for energy efficiency and conservation
program impacts on the portfolio. Absent these efficiency gains, our position would be
deficit sooner. The first capacity deficit is short-lived because a 150 MW exchange contract ends in 2016. Avista plans to address the 2015-2016 capacity deficit with market purchases as 2015 approaches.
The Company’s resource portfolio has 226 MW of natural gas-fired peaking plants
available to serve winter loads. For long-term planning these resources are assumed to generate energy at their full capabilities. Operationally, the resources often will be
displaced with less expensive purchases from the wholesale marketplace. On an annual
Avista Corp 2009 Electric IRP- Public Draft 8-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 168 of 729
2009 Electric IRPAvista Corp 8-5
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
purposes, REC purchases are an option, but not in excess of 45,000 per year. Work
since the 2007 IRP have found that long-term fixed-price natural gas contracts consume
inordinate amounts of Company capital.
Figure 8.2: Efficient Frontier Curve
cost
ri
s
k
Least Cost
Least Risk
Constraints
As discussed earlier in this chapter, constraints are necessary to solve for the optimal
resource strategy. Some constraints are physical and others are societal. The major resource constraints are: capacity and energy needs, and Washington’s RPS and emissions performance standard (SB 6001).
The PRiSM model is limited by resource type and size. It can select from combined-
and simple-cycle natural gas-fired combustion turbines, wind and small hydro upgrades. Sequestered coal plants are available beginning in 2023. A new enhancement to PRiSM for the 2009 IRP cycle ensures it selects resources in minimum block sizes
rather than mathematically optimal increments. This change better reflects how Avista
actually acquires resources. It also emulates how the Company manages lumpy resource additions and that resource positions are not perfectly balanced with load each year. PRiSM is allowed to model Avista’s portfolio to be as much as 50 MW short or 200
MW long in any given planning year.
Washington’s RPS fundamentally changed how Avista plans to meet future loads. Historically an Efficient Frontier was created with the least-cost strategy on one end and the least-risk strategy on the other. Next, management decided where they wanted to
be on the continuums, based on risk appetite. Recent least-cost strategies typically
Avista Corp 2009 Electric IRP- Public Draft 8-4
Chapter 8- Preferred Resource Strategy
consisted of gas-fired resources. Portfolios with less risk replaced some of the gas-fired
resources with wind, other renewables and coal. Past IRPs identified strategies that
included these risk-reduction resources. For illustration, these strategies are
represented on the Efficient Frontier as a red dot in Figure 8.3. Washington laws requiring the acquisition of renewable generation, or RECs, and the near-ban on new
coal-fired facilities, removes the lowest-cost portion of the efficient frontier, illustrated in
blue in Figure 8.3. The added constraints greatly reduce the Company’s ability to
reduce future costs. The 2009 IRP is therefore based on the least-cost strategy that still complies with state laws, rather than a portfolio selected on a full vetting of cost and risk.
Figure 8.3: Efficient Frontier in a Constrained Environment
cost
ri
s
k
Least Cost
Least Risk
PRS
Resource Shortages
Avista has adequate resources to meet annual physical energy and capacity needs until
2015. See Figure 8.4. The graphic accounts for energy efficiency and conservation
program impacts on the portfolio. Absent these efficiency gains, our position would be
deficit sooner. The first capacity deficit is short-lived because a 150 MW exchange contract ends in 2016. Avista plans to address the 2015-2016 capacity deficit with market purchases as 2015 approaches.
The Company’s resource portfolio has 226 MW of natural gas-fired peaking plants
available to serve winter loads. For long-term planning these resources are assumed to generate energy at their full capabilities. Operationally, the resources often will be
displaced with less expensive purchases from the wholesale marketplace. On an annual
Avista Corp 2009 Electric IRP- Public Draft 8-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 169 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-6 Avista Corp
Chapter 8- Preferred Resource Strategy
average basis our loads and resources fall out of balance in 2018 for energy; the first
quarterly energy deficit is in the fourth quarter of 2014.
PRiSM selects new resources to fill capacity and energy deficits, although the model might over- or under-build for economic reasons. Because of its greater capacity need,
and the fact that wind acquisitions do not provide capacity commensurate with their
energy production, Avista will retain large energy surpluses.
Figure 8.4: Physical Resource Positions
-1000
-800
-600
-400
-200
0
200
400
20
1
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1
1
20
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4
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Winter Capacity
Summer Capacity
Annual Energy
Planning Criteria
Avista uses several risk mitigation methods to manage energy and capacity positions. For capacity, peak load is reflected at the higher of the median coldest or hottest daily temperature on record in the Spokane area. Resources are netted against peak load at
their expected capacities at the time of system peak; long-term contracts are also netted
in the calculation. A 15 percent planning margin is added to load to represent extreme
weather and resource forced outages. The NPCC suggests Northwest planning margin levels of 25 percent for winter and 17 percent for summer. Avista staff has evaluated several methods to determine whether it has adequate reserves, including a sustained
peak analysis and loss of load probability calculations. Its evaluations indicated that a
15 percent planning margin is adequate for planning purposes.
Avista uses a similar method for energy planning. Load levels use historic temperatures
and include an adjustment for extreme weather, set at a 90 percent confidence level
(single-tail). Thermal resources include forced outage rates and planning maintenance
Avista Corp 2009 Electric IRP- Public Draft 8-6
Chapter 8- Preferred Resource Strategy
downtimes. The largest adjustment is to hydro energy, where water levels are set on a
monthly basis to a level exceeded in nine out of 10 years.
Renewable Portfolio Standards (I-937)
Washington voters approved Initiative 937, the Energy Independence Act, in the November 2006 general election. The initiative requires utilities with over 25,000 customers to meet three percent of load from qualified renewables by 2012, nine
percent by 2016 and 15 percent by 2020. The initiative also requires utilities to acquire
all cost effective conservation and energy efficiency measures.
Avista projects it will meet or exceed its renewable requirements between 2012 and
2015 through hydro upgrades and a REC purchase made in 2009, as shown in green in
Figure 8.5. Avista has the ability to bank RECs acquired from the Stateline Wind
contract in 2011 for 2012, but these RECs are sold to customers as part of the Buck-a-Block program. As part of the REC analysis, Avista included a 10 percent margin so
Avista is not forced to make REC purchases in a strained market when hydroelectric
generation or load varies from its expectation and the Company would potentially be
required to pay a penalty.
The Company will need its next block of qualifying resources prior to 2016 and another
block will be required prior to 2020. Assuming Avista meets RPS requirements with
wind, as illustrated later in this section, it will require 150 MW of nameplate capacity by
2016 and a similar amount by 2020. After 2020, Avista will continue to acquire renewable resources to meet load growth as specified in I-937.
Figure 8.5: REC Requirement vs. Qualifying RECs for Washington State RPS
0
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100
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Qualifying Renewable
Renewable Requirement
Avista Corp 2009 Electric IRP- Public Draft 8-7
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 170 of 729
2009 Electric IRPAvista Corp 8-7
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
average basis our loads and resources fall out of balance in 2018 for energy; the first
quarterly energy deficit is in the fourth quarter of 2014.
PRiSM selects new resources to fill capacity and energy deficits, although the model might over- or under-build for economic reasons. Because of its greater capacity need,
and the fact that wind acquisitions do not provide capacity commensurate with their
energy production, Avista will retain large energy surpluses.
Figure 8.4: Physical Resource Positions
-1000
-800
-600
-400
-200
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Winter Capacity
Summer Capacity
Annual Energy
Planning Criteria
Avista uses several risk mitigation methods to manage energy and capacity positions. For capacity, peak load is reflected at the higher of the median coldest or hottest daily temperature on record in the Spokane area. Resources are netted against peak load at
their expected capacities at the time of system peak; long-term contracts are also netted
in the calculation. A 15 percent planning margin is added to load to represent extreme
weather and resource forced outages. The NPCC suggests Northwest planning margin levels of 25 percent for winter and 17 percent for summer. Avista staff has evaluated several methods to determine whether it has adequate reserves, including a sustained
peak analysis and loss of load probability calculations. Its evaluations indicated that a
15 percent planning margin is adequate for planning purposes.
Avista uses a similar method for energy planning. Load levels use historic temperatures
and include an adjustment for extreme weather, set at a 90 percent confidence level
(single-tail). Thermal resources include forced outage rates and planning maintenance
Avista Corp 2009 Electric IRP- Public Draft 8-6
Chapter 8- Preferred Resource Strategy
downtimes. The largest adjustment is to hydro energy, where water levels are set on a
monthly basis to a level exceeded in nine out of 10 years.
Renewable Portfolio Standards (I-937)
Washington voters approved Initiative 937, the Energy Independence Act, in the November 2006 general election. The initiative requires utilities with over 25,000 customers to meet three percent of load from qualified renewables by 2012, nine
percent by 2016 and 15 percent by 2020. The initiative also requires utilities to acquire
all cost effective conservation and energy efficiency measures.
Avista projects it will meet or exceed its renewable requirements between 2012 and
2015 through hydro upgrades and a REC purchase made in 2009, as shown in green in
Figure 8.5. Avista has the ability to bank RECs acquired from the Stateline Wind
contract in 2011 for 2012, but these RECs are sold to customers as part of the Buck-a-Block program. As part of the REC analysis, Avista included a 10 percent margin so
Avista is not forced to make REC purchases in a strained market when hydroelectric
generation or load varies from its expectation and the Company would potentially be
required to pay a penalty.
The Company will need its next block of qualifying resources prior to 2016 and another
block will be required prior to 2020. Assuming Avista meets RPS requirements with
wind, as illustrated later in this section, it will require 150 MW of nameplate capacity by
2016 and a similar amount by 2020. After 2020, Avista will continue to acquire renewable resources to meet load growth as specified in I-937.
Figure 8.5: REC Requirement vs. Qualifying RECs for Washington State RPS
0
20
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100
120
140
160
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Qualifying Renewable
Renewable Requirement
Avista Corp 2009 Electric IRP- Public Draft 8-7
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 171 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-8 Avista Corp
Chapter 8- Preferred Resource Strategy
Preferred Resource Strategy
The 2009 PRS consists of hydro upgrades, wind, conservation, distribution efficiency
programs and natural gas-combined cycle gas turbines. The first generation resource
acquisition is 150 MW of wind by the end of 2012 to take advantage of federal tax incentives. Based on expected capital cost growth rates and the likelihood of the tax credits not being extended beyond 2012, Avista will develop wind projects prior to its
2016 need.
Avista will begin rebuilding distribution feeders over the next five years. The PRS includes five MW of capacity savings and 2.7 aMW of energy savings. More discussion
on this topic is included in the distribution upgrades section of the Transmission and
Distribution chapter.
Avista has committed to upgrades at its Noxon Rapids and Nine Mile Falls projects. The
PRS identified additional cost-effective upgrade opportunities at Little Falls and Upper
Falls. These upgrades provide 5 MW of capacity and 2 aMW of energy qualifying for the
Washington RPS.
The PRiSM model selected its first large capacity addition in 2019, a 250 MW combined
cycle combustion turbine. Another 150 MW of wind capacity is also needed by the end
of 2019 for the 15 percent RPS goal, followed by a 50 MW wind resource in 2022 to
meet additional RPS obligations created by load growth. In 2024 and 2027, another 250 MW natural gas combined-cycle plant is needed to meet a capacity deficit created by
the expiration of the Lancaster tolling agreement. Table 8.1 presents PRS resources.
Table 8.1: 2009 Preferred Resource Strategy
Resource
By the End of
Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 150.0 48.0
Distribution Efficiencies 2010-2015 5.0 2.7
Little Falls Unit Upgrades 2013-2016 3.0 0.9
NW Wind 2019 150.0 50.0
CCCT 2019 250.0 225.0
Upper Falls 2020 2.0 1.0
NW Wind 2022 50.0 17.0
CCCT 2024 250.0 225.0
CCCT 2027 250.0 225.0
Conservation All Years 339.0 226.0
Total 1,449.0 1,020.6
The 2007 PRS is shown in Table 8.2 for comparison. The major difference between the 2009 and 2007 IRPs is the absence of non-wind renewables and an earlier acquisition of wind resources in the 2009 plan. The 2014 share of a CCCT plant was removed, due
Avista Corp 2009 Electric IRP- Public Draft 8-8
Chapter 8- Preferred Resource Strategy
to a lower load forecast and the decision to fill a temporary capacity shortfall with market
purchases. The 2009 plan includes 750 MW of natural gas and 350 MW of wind. The
2007 plan included 677 MW of natural gas-fired generation and 300 MW of wind.
Table 8.2: 2007 Preferred Resource Strategy
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Non-Wind Renewable 2011 20.0 18.0
Non-Wind Renewable 2012 10.0 9.0
NW Wind 2013 100.0 33.0
Non-Wind Renewable 2013 5.0 4.5
Share of CCCT 2014 75.0 67.5
NW Wind 2015 100.0 33.0
NW Wind 2016 100.0 33.0
Non-Wind Renewable 2019 10.0 9.0
Non-Wind Renewable 2020 10.0 9.0
Non-Wind Renewable 2021 5.0 4.5
Share of CCCT1 2019 297.0 267.3
Share of CCCT 2027 305.0 274.5
Conservation All Years 331.5 221.0
Total 1,368.5 983.3
Energy Efficiency and Conservation
Energy efficiency is an integral part of the PRS analytical process. Energy efficiency is
also a critical part of the Washington RPS, where utilities are required to obtain all cost effective conservation. Avista uses internal analysis to develop its avoided energy costs
and compares these figures against an acquirable supply curve of conservation. The
20-year forecast of acquired energy efficiency is shown in Figure 8.6. Avista will acquire
102 aMW of energy efficiency over the next 10 years and 226 aMW over 20 years. These acquisitions will also reduce the system peak. Efficiency gains are expected to shave 153 MW from the 2020 peak, and 339 MW from the 2029 peak.
Avista Corp 2009 Electric IRP- Public Draft 8-9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 172 of 729
2009 Electric IRPAvista Corp 8-9
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Preferred Resource Strategy
The 2009 PRS consists of hydro upgrades, wind, conservation, distribution efficiency
programs and natural gas-combined cycle gas turbines. The first generation resource
acquisition is 150 MW of wind by the end of 2012 to take advantage of federal tax incentives. Based on expected capital cost growth rates and the likelihood of the tax credits not being extended beyond 2012, Avista will develop wind projects prior to its
2016 need.
Avista will begin rebuilding distribution feeders over the next five years. The PRS includes five MW of capacity savings and 2.7 aMW of energy savings. More discussion
on this topic is included in the distribution upgrades section of the Transmission and
Distribution chapter.
Avista has committed to upgrades at its Noxon Rapids and Nine Mile Falls projects. The
PRS identified additional cost-effective upgrade opportunities at Little Falls and Upper
Falls. These upgrades provide 5 MW of capacity and 2 aMW of energy qualifying for the
Washington RPS.
The PRiSM model selected its first large capacity addition in 2019, a 250 MW combined
cycle combustion turbine. Another 150 MW of wind capacity is also needed by the end
of 2019 for the 15 percent RPS goal, followed by a 50 MW wind resource in 2022 to
meet additional RPS obligations created by load growth. In 2024 and 2027, another 250 MW natural gas combined-cycle plant is needed to meet a capacity deficit created by
the expiration of the Lancaster tolling agreement. Table 8.1 presents PRS resources.
Table 8.1: 2009 Preferred Resource Strategy
Resource
By the End of
Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012150.048.0
Distribution Efficiencies 2010-20155.02.7
Little Falls Unit Upgrades 2013-20163.00.9
NW Wind 2019150.050.0
CCCT2019250.0225.0
Upper Falls 20202.01.0
NW Wind 202250.017.0
CCCT2024250.0225.0
CCCT2027250.0225.0
ConservationAll Years339.0226.0
Total1,449.0 1,020.6
The 2007 PRS is shown in Table 8.2 for comparison. The major difference between the 2009 and 2007 IRPs is the absence of non-wind renewables and an earlier acquisition of wind resources in the 2009 plan. The 2014 share of a CCCT plant was removed, due
Avista Corp 2009 Electric IRP- Public Draft 8-8
Chapter 8- Preferred Resource Strategy
to a lower load forecast and the decision to fill a temporary capacity shortfall with market
purchases. The 2009 plan includes 750 MW of natural gas and 350 MW of wind. The
2007 plan included 677 MW of natural gas-fired generation and 300 MW of wind.
Table 8.2: 2007 Preferred Resource Strategy
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
Non-Wind Renewable 2011 20.0 18.0
Non-Wind Renewable 2012 10.0 9.0
NW Wind 2013 100.0 33.0
Non-Wind Renewable 2013 5.0 4.5
Share of CCCT 2014 75.0 67.5
NW Wind 2015 100.0 33.0
NW Wind 2016 100.0 33.0
Non-Wind Renewable 2019 10.0 9.0
Non-Wind Renewable 2020 10.0 9.0
Non-Wind Renewable 2021 5.0 4.5
Share of CCCT1 2019 297.0 267.3
Share of CCCT 2027 305.0 274.5
Conservation All Years 331.5 221.0
Total 1,368.5 983.3
Energy Efficiency and Conservation
Energy efficiency is an integral part of the PRS analytical process. Energy efficiency is
also a critical part of the Washington RPS, where utilities are required to obtain all cost effective conservation. Avista uses internal analysis to develop its avoided energy costs
and compares these figures against an acquirable supply curve of conservation. The
20-year forecast of acquired energy efficiency is shown in Figure 8.6. Avista will acquire
102 aMW of energy efficiency over the next 10 years and 226 aMW over 20 years. These acquisitions will also reduce the system peak. Efficiency gains are expected to shave 153 MW from the 2020 peak, and 339 MW from the 2029 peak.
Avista Corp 2009 Electric IRP- Public Draft 8-9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 173 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-10 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.6: Energy Efficiency Annual Expected Acquisition
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Regional (NEEA)
Local (Avista)
ReardanAvista purchased the development rights for the Reardan wind site from Energy
Northwest in 2008. The site is fully permitted for development and has several years of
meteorological data. Reardan is an attractive wind site for Avista because of its close proximately to Spokane—the site is 23 miles west of downtown Spokane. The site is expected to deliver a 28 to 32 percent capacity factor depending on the final project
configuration. This wind site is competitive to higher capacity factor sites since the
project does not require any third-party transmission and its proximity to Avista. The site has the potential to supply 50 to 100 MW of wind generation.
Additional Northwest Wind
Avista anticipates issuing an all-renewables request for proposals (RFP) in 2009. The
RFP will be for wind projects and other renewable generating facilities with expected generation up to 50 aMW. If Reardan is found to be cost-effective relative to the RFP, the total amount of generation acquired from the competitive bidding process will be
reduced.
Hydro Upgrades This IRP has analyzed the potential for upgrades on Avista’s hydro system. Small
upgrades are included in the PRS analysis, while larger projects are considered as
Avista Corp 2009 Electric IRP- Public Draft 8-10
Chapter 8- Preferred Resource Strategy
scenarios since they will require further engineering work to determine the ultimate cost
of each project. The PRS analysis found four hydro upgrades should be pursued. Little
Falls Units 1, 2 and 4 require generator rewinds and generator shaft replacements. Two
of the units will also require new runners. The upgrades will provide 1.0 MW of additional capacity and 0.32 aMW of energy for each unit. The Upper Falls upgrade will
include a generator rewind and runner replacement. The upgrade will add 2.0 MW of
capacity and 1.0 aMW of energy. These hydro upgrades add system capacity and
provide qualified renewable energy.
Loads and Resource Balances
The load forecasts shown in the following charts decrement conservation from the load
forecast by assumed conservation levels identified in the 2007 IRP to show
conservation as a resource. Peak load forecasts are reduced by 1.5 times the average
conservation acquisition level. The energy load and resource balance (L&R) forecast (Figure 8.7) reaches its first deficit in 2016 absent conservation; conservation efforts
delay the deficit two years, until 2018. The PRS additions remove all negative positions
from the L&R position. The CCCT resource included in January 2020 could be brought
online as early as 2015 without any significant impact on the PRS where loads differ from the present forecast or other factors make the resource attractive prior to that year (see the end of this chapter for detailed L&R tables).
Figure 8.7: Annual Average Load and Resource Balance
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
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1
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Existing Resources ConservationDistribution Efficiencies Hydro UpgradesCCCTWindLoad + Contingency
The first winter peak deficit without conservation occurs in 2014 and the deficit is
delayed to 2015 with conservation (see Figure 8.8). The resource portfolio shows
deficits for 2015 and 2016, but returns to a surplus position in 2017 with the expiration
of a 150 MW capacity exchange contract. Avista intends to meet this short-term deficiency with market purchases rather than acquiring a resource prior to a sustained
Avista Corp 2009 Electric IRP- Public Draft 8-11
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 174 of 729
2009 Electric IRPAvista Corp 8-11
Chapter 8 - Preferred Resoure Strategy
Chapter 8- Preferred Resource Strategy
Figure 8.6: Energy Efficiency Annual Expected Acquisition
0
5
10
15
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1
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Regional (NEEA)
Local (Avista)
ReardanAvista purchased the development rights for the Reardan wind site from Energy
Northwest in 2008. The site is fully permitted for development and has several years of
meteorological data. Reardan is an attractive wind site for Avista because of its close proximately to Spokane—the site is 23 miles west of downtown Spokane. The site is expected to deliver a 28 to 32 percent capacity factor depending on the final project
configuration. This wind site is competitive to higher capacity factor sites since the
project does not require any third-party transmission and its proximity to Avista. The site has the potential to supply 50 to 100 MW of wind generation.
Additional Northwest Wind
Avista anticipates issuing an all-renewables request for proposals (RFP) in 2009. The
RFP will be for wind projects and other renewable generating facilities with expected generation up to 50 aMW. If Reardan is found to be cost-effective relative to the RFP, the total amount of generation acquired from the competitive bidding process will be
reduced.
Hydro Upgrades This IRP has analyzed the potential for upgrades on Avista’s hydro system. Small
upgrades are included in the PRS analysis, while larger projects are considered as
Avista Corp 2009 Electric IRP- Public Draft 8-10
Chapter 8- Preferred Resource Strategy
scenarios since they will require further engineering work to determine the ultimate cost
of each project. The PRS analysis found four hydro upgrades should be pursued. Little
Falls Units 1, 2 and 4 require generator rewinds and generator shaft replacements. Two
of the units will also require new runners. The upgrades will provide 1.0 MW of additional capacity and 0.32 aMW of energy for each unit. The Upper Falls upgrade will
include a generator rewind and runner replacement. The upgrade will add 2.0 MW of
capacity and 1.0 aMW of energy. These hydro upgrades add system capacity and
provide qualified renewable energy.
Loads and Resource Balances
The load forecasts shown in the following charts decrement conservation from the load
forecast by assumed conservation levels identified in the 2007 IRP to show
conservation as a resource. Peak load forecasts are reduced by 1.5 times the average
conservation acquisition level. The energy load and resource balance (L&R) forecast (Figure 8.7) reaches its first deficit in 2016 absent conservation; conservation efforts
delay the deficit two years, until 2018. The PRS additions remove all negative positions
from the L&R position. The CCCT resource included in January 2020 could be brought
online as early as 2015 without any significant impact on the PRS where loads differ from the present forecast or other factors make the resource attractive prior to that year (see the end of this chapter for detailed L&R tables).
Figure 8.7: Annual Average Load and Resource Balance
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
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1
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Existing Resources ConservationDistribution Efficiencies Hydro UpgradesCCCTWindLoad + Contingency
The first winter peak deficit without conservation occurs in 2014 and the deficit is
delayed to 2015 with conservation (see Figure 8.8). The resource portfolio shows
deficits for 2015 and 2016, but returns to a surplus position in 2017 with the expiration
of a 150 MW capacity exchange contract. Avista intends to meet this short-term deficiency with market purchases rather than acquiring a resource prior to a sustained
Avista Corp 2009 Electric IRP- Public Draft 8-11
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 175 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-12 Avista Corp
Chapter 8- Preferred Resource Strategy
long-term need. However, if the Company determines that it cannot depend on the
market during this time period, a capacity resource could be added without a significant
impact on the long-term portfolio cost. PRiSM added the first CCCT resource in 2020,
leaving a small short position in 2019 that would be filled with market purchases.
The summer peak L&R is similar to the winter peak L&R. While peak loads are lower in
summer than winter, hydro and thermal generation capacity is also lower during the
summer. As shown in Figure 8.9, summer resource deficits occur in 2013 without conservation and in 2014 with conservation measures. The Company plans to fill the short-term deficit position between 2014 and 2016 with market purchases.
Figure 8.8: Winter Peak Load and Resource Balance
0
500
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Existing Resources ConservationDistribution Efficiencies Hydro UpgradesCCCTWindLoad + Planning Margin
Avista Corp 2009 Electric IRP- Public Draft 8-12
Chapter 8- Preferred Resource Strategy
Figure 8.9: Summer Peak Load and Resource Balance
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
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1
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Existing Resources Conservation
Distribution Efficiencies Hydro UpgradesCCCTWind
Load + Planning Margin
Greenhouse Gas Emissions
The Market Analysis chapter discusses how greenhouse gas emissions in the Western Interconnect will decrease. Avista’s greenhouse gas emissions might not fall due to the cap and trade market. The projected cap and trade market interaction will first impact
less efficient carbon emitting facilities before affecting the emissions from more efficient
facilities. This will affect existing coal resources with high fuel and incremental operation costs as they will be replaced with new or underutilized natural gas-fired resources located closer to west coast load centers. Figure 8.10 shows Avista’s expected PRS
greenhouse gas emissions. Emissions will be near 2010 levels on an annual basis, but
not lower than 2010 levels by the end of 2029. Emissions from current resource portfolio
will be reduced as Colstrip’s output decreases and natural gas facilities increase generation. The addition of new gas facilities necessary to meet growing loads will ultimately contribute to the Company’s emission totals. Emissions by 2029 would be 23
percent higher where no carbon legislation is implemented. Avista’s carbon intensity is
projected to fall from 0.32 short tons per MWh to 0.24 short tons per MWh by 2029.
Avista Corp 2009 Electric IRP- Public Draft 8-13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 176 of 729
2009 Electric IRPAvista Corp 8-13
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
long-term need. However, if the Company determines that it cannot depend on the
market during this time period, a capacity resource could be added without a significant
impact on the long-term portfolio cost. PRiSM added the first CCCT resource in 2020,
leaving a small short position in 2019 that would be filled with market purchases.
The summer peak L&R is similar to the winter peak L&R. While peak loads are lower in
summer than winter, hydro and thermal generation capacity is also lower during the
summer. As shown in Figure 8.9, summer resource deficits occur in 2013 without conservation and in 2014 with conservation measures. The Company plans to fill the short-term deficit position between 2014 and 2016 with market purchases.
Figure 8.8: Winter Peak Load and Resource Balance
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Existing ResourcesConservationDistribution EfficienciesHydro UpgradesCCCTWindLoad + Planning Margin
Avista Corp 2009 Electric IRP- Public Draft 8-12
Chapter 8- Preferred Resource Strategy
Figure 8.9: Summer Peak Load and Resource Balance
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Distribution Efficiencies Hydro UpgradesCCCTWind
Load + Planning Margin
Greenhouse Gas Emissions
The Market Analysis chapter discusses how greenhouse gas emissions in the Western Interconnect will decrease. Avista’s greenhouse gas emissions might not fall due to the cap and trade market. The projected cap and trade market interaction will first impact
less efficient carbon emitting facilities before affecting the emissions from more efficient
facilities. This will affect existing coal resources with high fuel and incremental operation costs as they will be replaced with new or underutilized natural gas-fired resources located closer to west coast load centers. Figure 8.10 shows Avista’s expected PRS
greenhouse gas emissions. Emissions will be near 2010 levels on an annual basis, but
not lower than 2010 levels by the end of 2029. Emissions from current resource portfolio
will be reduced as Colstrip’s output decreases and natural gas facilities increase generation. The addition of new gas facilities necessary to meet growing loads will ultimately contribute to the Company’s emission totals. Emissions by 2029 would be 23
percent higher where no carbon legislation is implemented. Avista’s carbon intensity is
projected to fall from 0.32 short tons per MWh to 0.24 short tons per MWh by 2029.
Avista Corp 2009 Electric IRP- Public Draft 8-13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 177 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-14 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
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Efficient Frontier Analysis The backbone of the PRS is the Efficient Frontier analysis. This analysis illustrates the relative performance of potential portfolios to each other on a cost and risk basis. The
curve created in the analysis represents the least-cost strategy at each level of risk. The
PRS analyses examined the following portfolios, as detailed here and in Figure 8.11:
ƒMarket Only: No conservation measures, deficits are met with spot market
purchases, and capacity and RPS constraints are not met with new resources.
ƒCapacity Only: No conservation measures or resources are added to meet capacity needs and RPS requirements are ignored.
ƒLeast Cost without Conservation: Least cost strategy (excluding conservation measures) meeting capacity and RPS requirements.
ƒLeast Cost: Least cost strategy that includes conservation measures meeting all capacity and RPS requirements.
ƒLeast Risk: Meets capacity and RPS requirements with the lowest risk.
ƒEfficient Frontier: A set of intermediate portfolios between the least risk and
least cost options.
The Market Only strategy is the least cost strategy from a long-term financial
perspective, but it has a high risk level. This strategy fails to meet RPS requirements
unless REC purchases are made and does not acquire capacity resources for reliability.
Avista Corp 2009 Electric IRP- Public Draft 8-14
Chapter 8- Preferred Resource Strategy
The Capacity Only strategy meets reliability needs with CT plant additions, that are
mostly displaced by wholesale market purchases. This strategy does not meet RPS
requirements or relieve volatility, except for tail risk. The Least Cost without Conservation strategy reduces risks with wind resource additions and selects CCCT
resources rather than CTs; this portfolio meets RPS and capacity requirements.
Figure 8.11: Base Case Efficient Frontier
$150
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$190
$210
$230
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$290
3,300 3,350 3,400 3,450 3,500 3,550
2010-2020 NPV of power supply costs (millions)
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Capacity Only
Least Cost w/o
ConservationLeast Cost/PRS
Least RiskEfficient Frontier
The cost differentials between each portfolio quantifies the avoided costs of the
following items:
ƒ Market costs: Market Only portfolio.
ƒ Capacity costs: difference between the Market Only and Capacity Only strategies.
ƒ RPS and risk reduction costs: difference between the Capacity Only and Least Cost without Conservation strategies.
ƒ Carbon costs: difference between market prices in the Base Case and the
Unconstrained Carbon scenario.
The levelized avoided costs for each item are shown in Table 8.3. The annual avoided conservation costs are shown in Figure 8.12. Avoided costs are determined by resource need and Mid-Columbia market prices. The first adder to Mid-Columbia prices is the
Avista Corp 2009 Electric IRP- Public Draft 8-15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 178 of 729
2009 Electric IRPAvista Corp 8-15
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Figure 8.10: Avista Owned and Controlled Resource’s Greenhouse Gas Emissions
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CO2 Reduced from Legislation
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Tons per MWh of Load
Efficient Frontier Analysis The backbone of the PRS is the Efficient Frontier analysis. This analysis illustrates the relative performance of potential portfolios to each other on a cost and risk basis. The
curve created in the analysis represents the least-cost strategy at each level of risk. The
PRS analyses examined the following portfolios, as detailed here and in Figure 8.11:
ƒMarket Only: No conservation measures, deficits are met with spot market
purchases, and capacity and RPS constraints are not met with new resources.
ƒCapacity Only: No conservation measures or resources are added to meet capacity needs and RPS requirements are ignored.
ƒLeast Cost without Conservation: Least cost strategy (excluding conservation measures) meeting capacity and RPS requirements.
ƒLeast Cost: Least cost strategy that includes conservation measures meeting all capacity and RPS requirements.
ƒLeast Risk: Meets capacity and RPS requirements with the lowest risk.
ƒEfficient Frontier: A set of intermediate portfolios between the least risk and
least cost options.
The Market Only strategy is the least cost strategy from a long-term financial
perspective, but it has a high risk level. This strategy fails to meet RPS requirements
unless REC purchases are made and does not acquire capacity resources for reliability.
Avista Corp 2009 Electric IRP- Public Draft 8-14
Chapter 8- Preferred Resource Strategy
The Capacity Only strategy meets reliability needs with CT plant additions, that are
mostly displaced by wholesale market purchases. This strategy does not meet RPS
requirements or relieve volatility, except for tail risk. The Least Cost without Conservation strategy reduces risks with wind resource additions and selects CCCT
resources rather than CTs; this portfolio meets RPS and capacity requirements.
Figure 8.11: Base Case Efficient Frontier
$150
$170
$190
$210
$230
$250
$270
$290
3,300 3,350 3,400 3,450 3,500 3,550
2010-2020 NPV of power supply costs (millions)
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Capacity Only
Least Cost w/o
ConservationLeast Cost/PRS
Least RiskEfficient Frontier
The cost differentials between each portfolio quantifies the avoided costs of the
following items:
ƒ Market costs: Market Only portfolio.
ƒ Capacity costs: difference between the Market Only and Capacity Only strategies.
ƒ RPS and risk reduction costs: difference between the Capacity Only and Least Cost without Conservation strategies.
ƒ Carbon costs: difference between market prices in the Base Case and the
Unconstrained Carbon scenario.
The levelized avoided costs for each item are shown in Table 8.3. The annual avoided conservation costs are shown in Figure 8.12. Avoided costs are determined by resource need and Mid-Columbia market prices. The first adder to Mid-Columbia prices is the
Avista Corp 2009 Electric IRP- Public Draft 8-15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 179 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-16 Avista Corp
Chapter 8- Preferred Resource Strategy
carbon adder in 2012, and then capacity and RPS adders are included. The RPS cost-
adder disappears in 2019 and 2025, as a result of the selected resources recovering
their costs from the market rather than rate payers.
Table 8.3: Levelized Avoided Costs ($/MWh)
Nominal 2009 Dollars
Mid-Columbia 68.22 54.37
Carbon 25.52 19.83
Capacity 11.66 9.29
Risk 5.76 4.68
Total 111.15 88.18
Figure 8.12: Avoided Costs for Conservation
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A $111.15 per MWh levelized avoided cost added enough conservation to lower costs by $65 million from the least-cost strategy absent this resource; risk is reduced by 14
percent. The Efficient Frontier portfolios decrease risk but increase costs. These
portfolios add wind resources beyond RPS levels and exchange CCCT plants at the end of the study for sequestered coal resources. Avista historically selected resources on the Efficient Frontier, but Washington law requires portfolios to include a certain
percentage of qualified renewables, effectively causing utilities to accept less market
risk. The least-cost portfolio, with capacity and RPS constraints, was selected over
alternative portfolios.
Avista Corp 2009 Electric IRP- Public Draft 8-16
Chapter 8- Preferred Resource Strategy
Efficient Frontier Portfolios
The Efficient Frontier analysis creates resource portfolios for given levels of risk and
cost. Avista’s management selected the least cost portfolio because of the significant
risk reductions already present with the inclusion of RPS obligations. Figure 8.13 shows a range of resource portfolios from the Efficient Frontier. Resource portfolios are similar,
but differ in the amount and timing of wind acquisitions.
Figure 8.13: Efficient Frontier Portfolios 2029 New Resources
-
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Least Cost - Mid Range + Least Risk
me
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CCCT T&D Efficiencies
Wind Hydro Upgrades
IGCC Coal IGCC Coal w/ Seq
Expected Costs
The stochastic market analysis illustrates a potential range of costs using different market outcomes. The final discussion covers the range of carbon costs that might be
added to power supply costs, given carbon legislation’s potential impact on the natural
gas market, reductions in coal-fired generation dispatch and increases in the dispatch of
natural gas-fired resources.
Capital
The PRS first requires capital in 2010 for distribution feeder upgrades, followed by
needs for wind development. The capital cash flows in Table 8.4 include AFUDC costs
and account for various tax incentives including federal investment tax credits. Costs are shown for years where capital would be placed in rate base, rather than when
capital is actually expended. The present value of the $2.2 billion required investment is
just over $1 billion. Avista may not have to supply all of the capital that has been
identified where it chooses to procure resources through power purchase agreements.
Avista Corp 2009 Electric IRP- Public Draft 8-17
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 180 of 729
2009 Electric IRPAvista Corp 8-17
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
carbon adder in 2012, and then capacity and RPS adders are included. The RPS cost-
adder disappears in 2019 and 2025, as a result of the selected resources recovering
their costs from the market rather than rate payers.
Table 8.3: Levelized Avoided Costs ($/MWh)
Nominal2009 Dollars
Mid-Columbia 68.22 54.37
Carbon25.52 19.83
Capacity11.669.29
Risk5.764.68
Total111.15 88.18
Figure 8.12: Avoided Costs for Conservation
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A $111.15 per MWh levelized avoided cost added enough conservation to lower costs by $65 million from the least-cost strategy absent this resource; risk is reduced by 14
percent. The Efficient Frontier portfolios decrease risk but increase costs. These
portfolios add wind resources beyond RPS levels and exchange CCCT plants at the end of the study for sequestered coal resources. Avista historically selected resources on the Efficient Frontier, but Washington law requires portfolios to include a certain
percentage of qualified renewables, effectively causing utilities to accept less market
risk. The least-cost portfolio, with capacity and RPS constraints, was selected over
alternative portfolios.
Avista Corp 2009 Electric IRP- Public Draft 8-16
Chapter 8- Preferred Resource Strategy
Efficient Frontier Portfolios
The Efficient Frontier analysis creates resource portfolios for given levels of risk and
cost. Avista’s management selected the least cost portfolio because of the significant
risk reductions already present with the inclusion of RPS obligations. Figure 8.13 shows a range of resource portfolios from the Efficient Frontier. Resource portfolios are similar,
but differ in the amount and timing of wind acquisitions.
Figure 8.13: Efficient Frontier Portfolios 2029 New Resources
-
200
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600
800
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1,400
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Least Cost - Mid Range + Least Risk
me
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CCCT T&D Efficiencies
Wind Hydro Upgrades
IGCC Coal IGCC Coal w/ Seq
Expected Costs
The stochastic market analysis illustrates a potential range of costs using different market outcomes. The final discussion covers the range of carbon costs that might be
added to power supply costs, given carbon legislation’s potential impact on the natural
gas market, reductions in coal-fired generation dispatch and increases in the dispatch of
natural gas-fired resources.
Capital
The PRS first requires capital in 2010 for distribution feeder upgrades, followed by
needs for wind development. The capital cash flows in Table 8.4 include AFUDC costs
and account for various tax incentives including federal investment tax credits. Costs are shown for years where capital would be placed in rate base, rather than when
capital is actually expended. The present value of the $2.2 billion required investment is
just over $1 billion. Avista may not have to supply all of the capital that has been
identified where it chooses to procure resources through power purchase agreements.
Avista Corp 2009 Electric IRP- Public Draft 8-17
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 181 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-18 Avista Corp
Chapter 8- Preferred Resource Strategy
Table 8.4: PRS Rate Base Additions for Capital Expenditures (Millions of Dollars)
Year Investment Year Investment
2010 4.9 2020 942.1
2011 5.0 2021 10.6
2012 5.1 2022 0.0
2013 278.1 2023 163.3
2014 7.7 2024 0.0
2015 2.3 2025 542.0
2016 0.0 2026 0.0
2017 1.7 2027 571.6
2018 0.0 2028 0.0
2019 0.0 2029 0.0
2010-2019 Total 304.8 2020-2029 Totals 2,229.6
Annual Power Supply Expenses and Volatility The PRS analyses track fuel, variable O&M, emissions and market transaction costs for
the existing resource portfolio. These costs are captured for each of the 250 iterations of
the Base Case risk analysis. In addition to existing portfolio costs, new resource capital,
fuel, O&M, emissions and other costs are tracked to provide a range in potential costs to serve future loads. Figure 8.14 shows expected PRS costs modeled through 2020 as the black line. Costs are expected to be $180 million in 2010. The 80 percent
confidence interval, shown in blue, ranges between $130 and $233 million. The black
diamonds represent the TailVar 90 risk level, or the top 10 percent of the worst
outcomes; this 2010 cost is $270 million, 50 percent higher than the expected value. As natural gas and greenhouse gas prices increase, power supply costs also increase.
Price uncertainty increases with time and the confidence interval band expands. The
2020 reduction in variability is created by the addition of wind and CCCT resources to
Avista’s portfolio.
Avista Corp 2009 Electric IRP- Public Draft 8-18
Chapter 8- Preferred Resource Strategy
Figure 8.14: Power Supply Expense
$-
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$800
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$1,200
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80% CL Low
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Tail Var 90
80% CL High
Natural Gas Price Risk The Market Analysis chapter showed the high and low natural gas price forecasts. The 750 MW of PRS gas-fired resources exposes Avista to natural gas price risk. This
section uses natural gas price forecast scenarios to calculate the range in expected
costs resulting from the PRS. Figure 8.15 shows the total portfolio cost range using
different natural gas points in comparison to the deterministic and stochastic Base Cases. The low gas price scenario reduces expected costs 20 percent and the high gas
price scenario increases costs 15 percent. Using stochastic model results, rather than
deterministic scenarios, illustrates risk exposure to the wholesale market. The 80
percent confidence interval in Figure 8.15 shows variability due to drivers besides natural gas. The range in costs is logarithmic, meaning there is the potential for extremely high costs but that there is not a commensurate cost reduction where gas
prices are low. For example, at the 80 percent confidence level, costs range between 30
percent lower and 40 percent higher than the mean values.
Avista Corp 2009 Electric IRP- Public Draft 8-19
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 182 of 729
2009 Electric IRPAvista Corp 8-19
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Table 8.4: PRS Rate Base Additions for Capital Expenditures (Millions of Dollars)
YearInvestmentYearInvestment
20104.9 2020942.1
20115.0 202110.6
20125.1 20220.0
2013278.1 2023163.3
20147.7 20240.0
20152.3 2025542.0
20160.0 20260.0
20171.7 2027571.6
20180.0 20280.0
20190.0 20290.0
2010-2019 Total 304.82020-2029 Totals 2,229.6
Annual Power Supply Expenses and Volatility The PRS analyses track fuel, variable O&M, emissions and market transaction costs for
the existing resource portfolio. These costs are captured for each of the 250 iterations of
the Base Case risk analysis. In addition to existing portfolio costs, new resource capital,
fuel, O&M, emissions and other costs are tracked to provide a range in potential costs to serve future loads. Figure 8.14 shows expected PRS costs modeled through 2020 as the black line. Costs are expected to be $180 million in 2010. The 80 percent
confidence interval, shown in blue, ranges between $130 and $233 million. The black
diamonds represent the TailVar 90 risk level, or the top 10 percent of the worst
outcomes; this 2010 cost is $270 million, 50 percent higher than the expected value. As natural gas and greenhouse gas prices increase, power supply costs also increase.
Price uncertainty increases with time and the confidence interval band expands. The
2020 reduction in variability is created by the addition of wind and CCCT resources to
Avista’s portfolio.
Avista Corp 2009 Electric IRP- Public Draft 8-18
Chapter 8- Preferred Resource Strategy
Figure 8.14: Power Supply Expense
$-
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$400
$600
$800
$1,000
$1,200
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80% CL Low
Expected Cost
Tail Var 90
80% CL High
Natural Gas Price Risk The Market Analysis chapter showed the high and low natural gas price forecasts. The 750 MW of PRS gas-fired resources exposes Avista to natural gas price risk. This
section uses natural gas price forecast scenarios to calculate the range in expected
costs resulting from the PRS. Figure 8.15 shows the total portfolio cost range using
different natural gas points in comparison to the deterministic and stochastic Base Cases. The low gas price scenario reduces expected costs 20 percent and the high gas
price scenario increases costs 15 percent. Using stochastic model results, rather than
deterministic scenarios, illustrates risk exposure to the wholesale market. The 80
percent confidence interval in Figure 8.15 shows variability due to drivers besides natural gas. The range in costs is logarithmic, meaning there is the potential for extremely high costs but that there is not a commensurate cost reduction where gas
prices are low. For example, at the 80 percent confidence level, costs range between 30
percent lower and 40 percent higher than the mean values.
Avista Corp 2009 Electric IRP- Public Draft 8-19
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 183 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-20 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.15: Power Supply Cost Sensitivities
0%20% 40% 60% 80% 100% 120% 140%
80% CL (Low End)
Low Gas Price Forecast
Base Case- Stochastic
Base Case- Deterministic
High Gas Price Forecast
80% CL (High End)
percent change from Base Case (2029 costs)
$0.0 $2.0 $4.0 $6.0 $8.0 $10.0
2009 dollars (billions)
Greenhouse Gas Costs
Avista anticipates federal greenhouse gas laws within the next three years; therefore
carbon cost estimates are included in the IRP Base Case. Carbon cost estimates rely on Wood Mackenzie’s forecast from the end of 2008. These prices illustrate possible
market and opportunity costs of carbon legislation, but ignore the potential for any free
carbon allocations. The PRS analysis assumes all carbon credits are auctioned, rather
than administratively allocated to utilities. This assumption does not affect the resource strategy because it analyzes the opportunity costs of trading credits for resource decision making. The ultimate number of credits granted versus auctioned to utilities is
unknown at this time, and will affect Avista’s system costs and rates. The costs shown
in Figure 8.16 illustrate the range of potential annual carbon costs associated with future
portfolio operations.
Most of the overall carbon costs are a result of decreased Colstrip generation and
increased natural gas and electricity market prices. Low cost coal-fired plants are traded
for higher-cost natural gas-fired resources. The cost of gas resources is higher than it would be absent carbon legislation because of increased demand for gas-fired resources. These additional costs represent up to 30 percent of total power supply
expenses in the Base Case. The costs were calculated by taking the difference in cost
between the Base Case against the same resource portfolio in a market without carbon legislation.
Avista Corp 2009 Electric IRP- Public Draft 8-20
Chapter 8- Preferred Resource Strategy
Figure 8.16: Carbon Related Power Supply Expense
0
50
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100% Allocation
80% Allocation
40% Allocation
0% Allocation
Carbon Legislation Impact
The PRS would not differ substantially absent carbon legislation because of
Washington’s RPS and emissions performance standards on new base load resources. Avista’s carbon emissions would be higher, as Colstrip generation would remain at
current levels, and the cost and risk to Avista’s customers would be lower. This is
illustrated by the Efficient Frontier analysis in Figure 8.17. The green curve on the upper
right of the chart is the Base Case Efficient Frontier with the red dot representing the PRS. The blue curve in the lower left corner of Figure 8.17 represents the Efficient Frontier without carbon legislation; the curve is less risky and less costly than the Base
Case. The red dot on this curve illustrates the non-carbon constrained PRS. A major
difference between the resource selections in this scenario is that the least-cost portfolio
includes gas-fired peaking plants, rather than combined cycle resources.
Avista Corp 2009 Electric IRP- Public Draft 8-21
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 184 of 729
2009 Electric IRPAvista Corp 8-21
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Figure 8.15: Power Supply Cost Sensitivities
0%20% 40% 60% 80% 100% 120% 140%
80% CL (Low End)
Low Gas Price Forecast
Base Case- Stochastic
Base Case- Deterministic
High Gas Price Forecast
80% CL (High End)
percent change from Base Case (2029 costs)
$0.0 $2.0 $4.0 $6.0 $8.0 $10.0
2009 dollars (billions)
Greenhouse Gas Costs
Avista anticipates federal greenhouse gas laws within the next three years; therefore
carbon cost estimates are included in the IRP Base Case. Carbon cost estimates rely on Wood Mackenzie’s forecast from the end of 2008. These prices illustrate possible
market and opportunity costs of carbon legislation, but ignore the potential for any free
carbon allocations. The PRS analysis assumes all carbon credits are auctioned, rather
than administratively allocated to utilities. This assumption does not affect the resource strategy because it analyzes the opportunity costs of trading credits for resource decision making. The ultimate number of credits granted versus auctioned to utilities is
unknown at this time, and will affect Avista’s system costs and rates. The costs shown
in Figure 8.16 illustrate the range of potential annual carbon costs associated with future
portfolio operations.
Most of the overall carbon costs are a result of decreased Colstrip generation and
increased natural gas and electricity market prices. Low cost coal-fired plants are traded
for higher-cost natural gas-fired resources. The cost of gas resources is higher than it would be absent carbon legislation because of increased demand for gas-fired resources. These additional costs represent up to 30 percent of total power supply
expenses in the Base Case. The costs were calculated by taking the difference in cost
between the Base Case against the same resource portfolio in a market without carbon legislation.
Avista Corp 2009 Electric IRP- Public Draft 8-20
Chapter 8- Preferred Resource Strategy
Figure 8.16: Carbon Related Power Supply Expense
0
50
100
150
200
250
300
350
400
20
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100% Allocation
80% Allocation
40% Allocation
0% Allocation
Carbon Legislation Impact
The PRS would not differ substantially absent carbon legislation because of
Washington’s RPS and emissions performance standards on new base load resources. Avista’s carbon emissions would be higher, as Colstrip generation would remain at
current levels, and the cost and risk to Avista’s customers would be lower. This is
illustrated by the Efficient Frontier analysis in Figure 8.17. The green curve on the upper
right of the chart is the Base Case Efficient Frontier with the red dot representing the PRS. The blue curve in the lower left corner of Figure 8.17 represents the Efficient Frontier without carbon legislation; the curve is less risky and less costly than the Base
Case. The red dot on this curve illustrates the non-carbon constrained PRS. A major
difference between the resource selections in this scenario is that the least-cost portfolio
includes gas-fired peaking plants, rather than combined cycle resources.
Avista Corp 2009 Electric IRP- Public Draft 8-21
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 185 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-22 Avista Corp
Chapter 8- Preferred Resource Strategy
Figure 8.17: Efficient Frontier Comparison
$100
$150
$200
$250
$300
$2,500 $2,700 $2,900 $3,100 $3,300 $3,500 $3,700
2010-2020 NPV (millions)
20
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)
The least cost portfolio in this scenario is very similar to the PRS, except 750 MW of combined cycle projects is exchanged for 800 MW of LMS100 simple-cycle generators
and one of the Little Falls hydro upgrades is dropped (see Table 8.5). The CCCT is the
least cost resource in a carbon constrained world because of its low heat rate and the
need for additional base load generation to replace coal. But without carbon constraints, the strategy relies instead on gas peaking plants that ultimately are displaced by market
purchases.
The PRS in an unconstrained carbon market would decrease expected costs 24 percent, to $807 million present value, as well as decrease annual power supply cost variation by 30 percent. Table 8.6 summarizes the cost and risk comparison among the
PRS and the least cost scenario in an Unconstrained Carbon market. The least cost
portfolio in the Unconstrained Carbon scenario decreases cost and increases risk. The
strategy has lower carbon emissions from Avista’s resources because the strategy uses peaking plants to meet capacity and buys energy from the market, meaning Avista will
not directly emit as much greenhouse gas.
Avista Corp 2009 Electric IRP- Public Draft 8-22
Chapter 8- Preferred Resource Strategy
Table 8.5: Unconstrained Carbon Scenario- Least Cost Portfolio
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 100.0 48.0
Distribution Efficiencies 2010-2015 5.0 2.7
Little Falls 4 2016 1.0 0.3
NW Wind 2019 150.0 50.0
SCCT 2019 200.0 180.0
Little Falls 2 2021 1.0 0.3
Little Falls 1 2022 1.0 0.3
NW Wind 2022 50.0 17.0
SCCT 2022 100.0 90.0
SCCT 2025 100.0 90.0
SCCT 2026 300.0 270.0
SCCT 2028 100.0 90.0
Total 1,159.0 838.6
Table 8.6: Portfolio Cost and Risk Comparison
Base Case
PRS UC PRS
UC Least Cost
Strategy
2010-2020 Cost NPV $3,430 $2,623 $2,610
2020 Expected Cost $909 $634 $609
2020 Stdev $277 $169 $179
2020 Stdev/Cost 30.5% 26.7%29.4%
2010-2020 Capital $1,247 $1,247 $1,101
2020 CO2 Emissions (000’s) 3,311 4,016 3,575
2029 CO2 Emissions (000’s) 3,286 4,041 2,928
Portfolio Scenarios
In many resource plans, a PRS is presented with a comparison to other portfolios to
illustrate cost and risk trade-offs. Avista wants to extend the portfolio analysis beyond simple portfolio comparisons for this IRP by focusing on how the portfolio would change if assumptions changed. This provides an array of strategies for fundamentally different
futures instead of a single strategy. This section identifies assumptions that could alter
the PRS, such as changes to load growth, capital costs, hydro upgrades, the
emergence of other small renewable projects and a nuclear revival.
The 2007 IRP pushed wind resources out to 2013 due to the federal production tax
credit and other renewable resource expectations. Due to the lack of sizeable non-wind
renewables and extension of federal tax credits the 2009 IRP suggests that these resources be developed sooner to take advantage of tax savings. Exact online dates will depend on results from a competitive bidding process for wind and other
renewables, expected to be released in 2009. The timing of these resources could
change depending on capital costs determined in the RFP.
Avista Corp 2009 Electric IRP- Public Draft 8-23
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 186 of 729
2009 Electric IRPAvista Corp 8-23
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Figure 8.17: Efficient Frontier Comparison
$100
$150
$200
$250
$300
$2,500 $2,700 $2,900 $3,100 $3,300 $3,500 $3,700
2010-2020 NPV (millions)
20
2
0

s
t
d
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v

(
m
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l
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i
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n
s
)
The least cost portfolio in this scenario is very similar to the PRS, except 750 MW of combined cycle projects is exchanged for 800 MW of LMS100 simple-cycle generators
and one of the Little Falls hydro upgrades is dropped (see Table 8.5). The CCCT is the
least cost resource in a carbon constrained world because of its low heat rate and the
need for additional base load generation to replace coal. But without carbon constraints, the strategy relies instead on gas peaking plants that ultimately are displaced by market
purchases.
The PRS in an unconstrained carbon market would decrease expected costs 24 percent, to $807 million present value, as well as decrease annual power supply cost variation by 30 percent. Table 8.6 summarizes the cost and risk comparison among the
PRS and the least cost scenario in an Unconstrained Carbon market. The least cost
portfolio in the Unconstrained Carbon scenario decreases cost and increases risk. The
strategy has lower carbon emissions from Avista’s resources because the strategy uses peaking plants to meet capacity and buys energy from the market, meaning Avista will
not directly emit as much greenhouse gas.
Avista Corp 2009 Electric IRP- Public Draft 8-22
Chapter 8- Preferred Resource Strategy
Table 8.5: Unconstrained Carbon Scenario- Least Cost Portfolio
Resource
By the End
of Year
Nameplate
(MW)
Energy
(aMW)
NW Wind 2012 100.0 48.0
Distribution Efficiencies 2010-2015 5.0 2.7
Little Falls 4 2016 1.0 0.3
NW Wind 2019 150.0 50.0
SCCT 2019 200.0 180.0
Little Falls 2 2021 1.0 0.3
Little Falls 1 2022 1.0 0.3
NW Wind 2022 50.0 17.0
SCCT 2022 100.0 90.0
SCCT 2025 100.0 90.0
SCCT 2026 300.0 270.0
SCCT 2028 100.0 90.0
Total 1,159.0 838.6
Table 8.6: Portfolio Cost and Risk Comparison
Base Case
PRS UC PRS
UC Least Cost
Strategy
2010-2020 Cost NPV $3,430 $2,623 $2,610
2020 Expected Cost $909 $634 $609
2020 Stdev $277 $169 $179
2020 Stdev/Cost 30.5% 26.7%29.4%
2010-2020 Capital $1,247 $1,247 $1,101
2020 CO2 Emissions (000’s) 3,311 4,016 3,575
2029 CO2 Emissions (000’s) 3,286 4,041 2,928
Portfolio Scenarios
In many resource plans, a PRS is presented with a comparison to other portfolios to
illustrate cost and risk trade-offs. Avista wants to extend the portfolio analysis beyond simple portfolio comparisons for this IRP by focusing on how the portfolio would change if assumptions changed. This provides an array of strategies for fundamentally different
futures instead of a single strategy. This section identifies assumptions that could alter
the PRS, such as changes to load growth, capital costs, hydro upgrades, the
emergence of other small renewable projects and a nuclear revival.
The 2007 IRP pushed wind resources out to 2013 due to the federal production tax
credit and other renewable resource expectations. Due to the lack of sizeable non-wind
renewables and extension of federal tax credits the 2009 IRP suggests that these resources be developed sooner to take advantage of tax savings. Exact online dates will depend on results from a competitive bidding process for wind and other
renewables, expected to be released in 2009. The timing of these resources could
change depending on capital costs determined in the RFP.
Avista Corp 2009 Electric IRP- Public Draft 8-23
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 187 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-24 Avista Corp
Chapter 8- Preferred Resource Strategy
Wind Capital Costs Sensitivity
Avista owns the rights and permits to build the Reardan wind project, but has not
secured turbines or completed engineering for the site. Most wind projects in this
position today could be completed by the end of 2010 or 2011. The PRiSM model selects this resource to be online by the end of 2012 with an estimated cost of $2,183
per kW (2009 dollars with AFUDC). There are certain tax advantages for beginning
project development in 2010, such as taking advantage of the investment tax credit.
This analysis determines the tipping point where lower capital costs would allow earlier wind development. The PRiSM model was re-run while lowering the capital cost of wind projects until the model changed resource timing. The Reardan project was selected to
be online by the end of 2010 with an all-in capital cost as high as $1,832 per kW (2009
dollars).
CCCT Capital Cost Sensitivity The Unconstrained Carbon Market future would lead Avista to consider adding simple
cycle CTs to the PRS mix to lower costs, but in the carbon constrained world, CCCT
resources have lower net costs. Since CCCT acquisition in the PRS does not occur until the end of the next decade, the cost of this resource may change and the cost relationship to a simple cycle CT might also change. This sensitivity analysis determines
the maximum CCCT cost that would allow the least cost strategy to select a SCCT over
a CCCT. The Base Case CCCT cost is $1,533 per kW (2009 dollars with AFUDC), but if
the cost were to increase five percent to $1,611 per kW (2009 dollars), the least cost strategy would change to a SCCT.
CCCT in 2015
The PRS does not meet temporary resource deficits in 2015 or 2016 and will require market purchases to maintain a 15 percent planning margin. The return of capacity from the expiration of the Portland General Exchange contract corrects this deficit. If Avista
acquired a combined cycle resource by 2015, costs to meet the earlier obligations
would increase 10-year present value costs by $102 million or 2.3 percent and reduce power supply risk between 2015 and 2019 by 5.7 percent. The decision to acquire this resource earlier will depend on the Company’s expectation that the market has the
capacity to meet regional peak load. Other scenarios that could impact this decision are
dramatic changes in the load forecast, the availability of a sufficient amount of
economically viable renewable resources with on-peak capacity contributions, or attractive pricing on a new CCCT.
Load Forecast Alternatives
Loads will probably differ from the current forecast because of the recession and the greater Spokane area could grow faster with future development activity after the economy recovers. This sensitivity analysis studies the impact to the PRS if loads grow
faster or slower than the Base Case estimate. Faster load growth will increase the need
for capital and slower load growth will slow the need for increased capital. This analysis
focuses on understanding the changes in timing of resource decisions. The Base Case forecast is for a 1.7 percent growth rate. The Low Load scenario cuts the growth rate by one percentage point to 0.7 percent and the High Growth case increases by one
Avista Corp 2009 Electric IRP- Public Draft 8-24
Chapter 8- Preferred Resource Strategy
percentage point to 2.7 percent. Table 8.7 shows the resource strategy adjusted for
lower growth rates. The lower load growth projection would not change near-term
resource acquisitions, but would eliminate the need for some wind and gas-fired
resources, as shown in the Modification to Strategy column. Table 8.8 shows the resource strategy with higher growth rates. The amount of near-term wind would
increase by 50 MW and additional peaking resources would be acquired by 2011 to
compensate for higher growth rates. In later years of the study, additional gas-fired and
wind resources would be needed to meet peak load growth and RPS requirements. This analysis indicates that lower load growth would not change near-term resource decisions.
Table 8.7: Low Load Growth Resource Strategy Changes to PRS
Resource By the End of Year Nameplate(MW)Energy (aMW)Modification to Strategy
NW Wind 2012 100.0 48.0 No Change
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
NW Wind 2019 100.0 33.0 Reduced from 150 MW
CCCT Removed 250 MW
Upper Falls 2020 2.0 1.0 Delayed to 2028
NW Wind Removed 50 MW
CCCT 2024 250.0 225.0 Delayed to 2025
CCCT Removed 250 MW
SCCT 2027 100.0 92.3 Added 100 MW
Total 560.0 402.9
Table 8.8: High Load Growth Resource Strategy Changes to PRS
Resource By the End of Year Nameplate(MW)Energy (aMW)Modification to Strategy
NW Wind 2012 200.0 64.5 Increased from 150 MW
Simple Cycle 2011 60.0 92.3 60 MW Added
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
Simple Cycle 2013 100.0 92.3 100 MW Added
Simple Cycle 2017 100.0 92.2 100 MW Added
NW Wind 2019 200.0 66.0 Increased from 150 MW
CCCT 2020 250.0 225.0 Delayed from 2019
Simple Cycle 2019 100.0 92.2 100 MW Added
Upper Falls 2020 2.0 1.0 No Change
NW Wind 2022 50.0 17.0 No Change
CCCT 2024 250.0 225.0 No Change
CCCT 2027 250.0 225.0 No Change
Total 1,570.0 1,196.1
Avista Corp 2009 Electric IRP- Public Draft 8-25
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 188 of 729
2009 Electric IRPAvista Corp 8-25
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
Wind Capital Costs Sensitivity
Avista owns the rights and permits to build the Reardan wind project, but has not
secured turbines or completed engineering for the site. Most wind projects in this
position today could be completed by the end of 2010 or 2011. The PRiSM model selects this resource to be online by the end of 2012 with an estimated cost of $2,183
per kW (2009 dollars with AFUDC). There are certain tax advantages for beginning
project development in 2010, such as taking advantage of the investment tax credit.
This analysis determines the tipping point where lower capital costs would allow earlier wind development. The PRiSM model was re-run while lowering the capital cost of wind projects until the model changed resource timing. The Reardan project was selected to
be online by the end of 2010 with an all-in capital cost as high as $1,832 per kW (2009
dollars).
CCCT Capital Cost Sensitivity The Unconstrained Carbon Market future would lead Avista to consider adding simple
cycle CTs to the PRS mix to lower costs, but in the carbon constrained world, CCCT
resources have lower net costs. Since CCCT acquisition in the PRS does not occur until the end of the next decade, the cost of this resource may change and the cost relationship to a simple cycle CT might also change. This sensitivity analysis determines
the maximum CCCT cost that would allow the least cost strategy to select a SCCT over
a CCCT. The Base Case CCCT cost is $1,533 per kW (2009 dollars with AFUDC), but if
the cost were to increase five percent to $1,611 per kW (2009 dollars), the least cost strategy would change to a SCCT.
CCCT in 2015
The PRS does not meet temporary resource deficits in 2015 or 2016 and will require market purchases to maintain a 15 percent planning margin. The return of capacity from the expiration of the Portland General Exchange contract corrects this deficit. If Avista
acquired a combined cycle resource by 2015, costs to meet the earlier obligations
would increase 10-year present value costs by $102 million or 2.3 percent and reduce power supply risk between 2015 and 2019 by 5.7 percent. The decision to acquire this resource earlier will depend on the Company’s expectation that the market has the
capacity to meet regional peak load. Other scenarios that could impact this decision are
dramatic changes in the load forecast, the availability of a sufficient amount of
economically viable renewable resources with on-peak capacity contributions, or attractive pricing on a new CCCT.
Load Forecast Alternatives
Loads will probably differ from the current forecast because of the recession and the greater Spokane area could grow faster with future development activity after the economy recovers. This sensitivity analysis studies the impact to the PRS if loads grow
faster or slower than the Base Case estimate. Faster load growth will increase the need
for capital and slower load growth will slow the need for increased capital. This analysis
focuses on understanding the changes in timing of resource decisions. The Base Case forecast is for a 1.7 percent growth rate. The Low Load scenario cuts the growth rate by one percentage point to 0.7 percent and the High Growth case increases by one
Avista Corp 2009 Electric IRP- Public Draft 8-24
Chapter 8- Preferred Resource Strategy
percentage point to 2.7 percent. Table 8.7 shows the resource strategy adjusted for
lower growth rates. The lower load growth projection would not change near-term
resource acquisitions, but would eliminate the need for some wind and gas-fired
resources, as shown in the Modification to Strategy column. Table 8.8 shows the resource strategy with higher growth rates. The amount of near-term wind would
increase by 50 MW and additional peaking resources would be acquired by 2011 to
compensate for higher growth rates. In later years of the study, additional gas-fired and
wind resources would be needed to meet peak load growth and RPS requirements. This analysis indicates that lower load growth would not change near-term resource decisions.
Table 8.7: Low Load Growth Resource Strategy Changes to PRS
Resource By the End of Year Nameplate(MW)Energy (aMW)Modification to Strategy
NW Wind 2012 100.0 48.0 No Change
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
NW Wind 2019 100.0 33.0 Reduced from 150 MW
CCCT Removed 250 MW
Upper Falls 2020 2.0 1.0 Delayed to 2028
NW Wind Removed 50 MW
CCCT 2024 250.0 225.0 Delayed to 2025
CCCT Removed 250 MW
SCCT 2027 100.0 92.3 Added 100 MW
Total 560.0 402.9
Table 8.8: High Load Growth Resource Strategy Changes to PRS
Resource By the End of Year Nameplate(MW)Energy (aMW)Modification to Strategy
NW Wind 2012 200.0 64.5 Increased from 150 MW
Simple Cycle 2011 60.0 92.3 60 MW Added
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
Simple Cycle 2013 100.0 92.3 100 MW Added
Simple Cycle 2017 100.0 92.2 100 MW Added
NW Wind 2019 200.0 66.0 Increased from 150 MW
CCCT 2020 250.0 225.0 Delayed from 2019
Simple Cycle 2019 100.0 92.2 100 MW Added
Upper Falls 2020 2.0 1.0 No Change
NW Wind 2022 50.0 17.0 No Change
CCCT 2024 250.0 225.0 No Change
CCCT 2027 250.0 225.0 No Change
Total 1,570.0 1,196.1
Avista Corp 2009 Electric IRP- Public Draft 8-25
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 189 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-26 Avista Corp
Chapter 8- Preferred Resource Strategy
The estimated cost for these portfolios is shown in Figure 8.18. The bars show the net
present value of costs between 2010 and 2020 (left axis), and the yellow line represents
the nominal capital expenditure for these resources (right axis).
Figure 8.18: High & Low Load Growth Cost Comparison
$3.0
$3.1
$3.2
$3.3
$3.4
$3.5
$3.6
Low Load Base Case High Load
ex
p
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(
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)
$0.0
$0.3
$0.6
$0.9
$1.2
$1.5
$1.8
ca
p
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a
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Expected Cost (NPV 2010-20)
Capital Expense (2010-2020)
Large Hydro Facility Scenarios
Renewable portfolio standards, capacity needs, and higher electricity market prices are
drawing attention to upgrades at Avista’s larger hydroelectric developments. Several projects were studied over 20 years ago, but they were not financially feasible at this time. Avista is reevaluating these projects to determine if there are market and
environmental benefits making them cost effective today. The large hydro upgrades
analyzed for this IRP are Cabinet Gorge Unit 5 (60 MW), Long Lake Unit 5 (24 MW) and
Long Lake second power house (60 MW). Other possible hydro upgrades include a new powerhouse at Post Falls and a second powerhouse at Monroe Street. If studies determine these resources are economically viable, then the resource strategy will
change because these resources add peak capacity as well as qualified renewable
energy. Table 8.9 illustrates potential changes to the PRS under the large hydro upgrade scenario. These upgrades cannot be completed prior to the middle of the next decade, so they will not change near-term resource acquisition plans.
Avista Corp 2009 Electric IRP- Public Draft 8-26
Chapter 8- Preferred Resource Strategy
Table 8.9: Large Hydro Upgrade Resource Strategy Modifications
Resource By the End of Year Nameplate(MW)Energy (aMW)Modification to Strategy
NW Wind 2012 100.0 48.0 No Change
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
Cabinet Gorge 5 2014 60.0 10.2 60 MW Added
Long Lake 2 Powerhouse 2019 60.0 18.0 60 MW Added
NW Wind 2019 100.0 33.0 Reduced from 150
MW
CCCT 2019 250.0 225.0 No Change
NW Wind 2022 50.0 17.0 No Change
CCCT 2026 400.0 360.0 Delayed from 2024 and upgraded from 250 MW
CCCT Removed 250 MW
Upper Falls 2029 2.0 1.0 Delayed from 2020
Totals 1,030.0 715.8
Capital cost sensitivities were performed to determine capital cost limits needed to
select large hydro upgrades for the PRS. The analysis found that although higher in cost, a second power house at Long Lake is more favorable than a new Unit 5 at the plant because of the higher capacity value of that option. Both projects could be built at
Long Lake to provide system capacity.
An initial review found that costs would need to be under $2,628 per kW, including transmission upgrades and AFUDC, for the Long Lake second powerhouse to be
selected in the least cost resource strategy. The Cabinet Gorge Unit 5 upgrade would
need to be under $1,289 per kW, including AFUDC. Avista might pursue these
upgrades at higher capital cost levels, depending on the value placed on reducing total dissolved gas and reduced market exposure.
Small Renewable Resources Scenario
The PRS in the 2005 and 2007 IRPs included small renewable resources. None were included for the 2009 IRP. Small renewable resources often have unique project characteristics that will affect project costs. This scenario illustrates changes in the PRS
if these resources were included in the Efficient Frontier analysis. As Avista solicits 150
MW of wind, it will include requests for other renewable resources in the RFP and give
resources with dependable capacity more economic benefit in subsequent bidding analysis. Figure 8.19 presents the Efficient Frontier with the addition of small renewable resources. If non-wind renewables are available to Avista at the prices shown in the
resource options chapter, these resources could modestly reduce Avista’s costs and
risks. Costs are lower because of a reduction in the quantity of resources needed because non-wind renewable resources provide capacity. For example, a 25 MW wind project is not credited with any reliable capacity in this analysis, so it must be backed up
Avista Corp 2009 Electric IRP- Public Draft 8-27
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 190 of 729
2009 Electric IRPAvista Corp 8-27
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
The estimated cost for these portfolios is shown in Figure 8.18. The bars show the net
present value of costs between 2010 and 2020 (left axis), and the yellow line represents
the nominal capital expenditure for these resources (right axis).
Figure 8.18: High & Low Load Growth Cost Comparison
$3.0
$3.1
$3.2
$3.3
$3.4
$3.5
$3.6
Low Load Base Case High Load
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Expected Cost (NPV 2010-20)
Capital Expense (2010-2020)
Large Hydro Facility Scenarios
Renewable portfolio standards, capacity needs, and higher electricity market prices are
drawing attention to upgrades at Avista’s larger hydroelectric developments. Several projects were studied over 20 years ago, but they were not financially feasible at this time. Avista is reevaluating these projects to determine if there are market and
environmental benefits making them cost effective today. The large hydro upgrades
analyzed for this IRP are Cabinet Gorge Unit 5 (60 MW), Long Lake Unit 5 (24 MW) and
Long Lake second power house (60 MW). Other possible hydro upgrades include a new powerhouse at Post Falls and a second powerhouse at Monroe Street. If studies determine these resources are economically viable, then the resource strategy will
change because these resources add peak capacity as well as qualified renewable
energy. Table 8.9 illustrates potential changes to the PRS under the large hydro upgrade scenario. These upgrades cannot be completed prior to the middle of the next decade, so they will not change near-term resource acquisition plans.
Avista Corp 2009 Electric IRP- Public Draft 8-26
Chapter 8- Preferred Resource Strategy
Table 8.9: Large Hydro Upgrade Resource Strategy Modifications
Resource By the End of Year Nameplate(MW)Energy (aMW)Modification to Strategy
NW Wind 2012 100.0 48.0 No Change
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
Cabinet Gorge 5 2014 60.0 10.2 60 MW Added
Long Lake 2 Powerhouse 2019 60.0 18.0 60 MW Added
NW Wind 2019 100.0 33.0 Reduced from 150
MW
CCCT 2019 250.0 225.0 No Change
NW Wind 2022 50.0 17.0 No Change
CCCT 2026 400.0 360.0 Delayed from 2024 and upgraded from 250 MW
CCCT Removed 250 MW
Upper Falls 2029 2.0 1.0 Delayed from 2020
Totals 1,030.0 715.8
Capital cost sensitivities were performed to determine capital cost limits needed to
select large hydro upgrades for the PRS. The analysis found that although higher in cost, a second power house at Long Lake is more favorable than a new Unit 5 at the plant because of the higher capacity value of that option. Both projects could be built at
Long Lake to provide system capacity.
An initial review found that costs would need to be under $2,628 per kW, including transmission upgrades and AFUDC, for the Long Lake second powerhouse to be
selected in the least cost resource strategy. The Cabinet Gorge Unit 5 upgrade would
need to be under $1,289 per kW, including AFUDC. Avista might pursue these
upgrades at higher capital cost levels, depending on the value placed on reducing total dissolved gas and reduced market exposure.
Small Renewable Resources Scenario
The PRS in the 2005 and 2007 IRPs included small renewable resources. None were included for the 2009 IRP. Small renewable resources often have unique project characteristics that will affect project costs. This scenario illustrates changes in the PRS
if these resources were included in the Efficient Frontier analysis. As Avista solicits 150
MW of wind, it will include requests for other renewable resources in the RFP and give
resources with dependable capacity more economic benefit in subsequent bidding analysis. Figure 8.19 presents the Efficient Frontier with the addition of small renewable resources. If non-wind renewables are available to Avista at the prices shown in the
resource options chapter, these resources could modestly reduce Avista’s costs and
risks. Costs are lower because of a reduction in the quantity of resources needed because non-wind renewable resources provide capacity. For example, a 25 MW wind project is not credited with any reliable capacity in this analysis, so it must be backed up
Avista Corp 2009 Electric IRP- Public Draft 8-27
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 191 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-28 Avista Corp
Chapter 8- Preferred Resource Strategy
with a resource that provides capacity. A 25 MW renewable resource with capacity does
not require another resource to provide back-up capacity. But these small renewable
resources are not risk free. The owner might cease production at some point in the
contract term. Biomass facilities often require an industrial waste product as fuel, so a downturn in the industry reduces fuel availability. Geothermal resources are interesting
to Avista because of the potential for low cost and stable base load power, but
availability has been questioned recently by the NPCC and only one geothermal
resource has been built in the Northwest in recent years.
Figure 8.19: Efficient Frontier Base Case vs. Other Renewables Available
$180
$200
$220
$240
$260
$280
$300
$3,300 $3,400 $3,500 $3,600 $3,700 $3,800 $3,900
2010-2020 NPV (millions)
20
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s
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(
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Where Avista is able to acquire non-wind renewables, its resource portfolio strategy will
emit fewer greenhouse gases (see Table 8.10). The PRS changes under the small renewable resource scenario are shown in Table 8.11. The strategy reduces wind capacity by 100 MW and trades 100 MW of CCCT for SCCT (the cause for increased
risk).
Avista Corp 2009 Electric IRP- Public Draft 8-28
Chapter 8- Preferred Resource Strategy
Table 8.10: Portfolio Cost and Risk Comparison
Base Case
PRS
Non-Wind Renewable
Least Cost
2010-2020 Cost NPV $3,430 $3,393
2020 Expected Cost $909 $875
2020 Standard Deviation $277 $288
2020 Standard Deviation/Cost 30.5%30.9%
2010-2020 Capital $1,247 $840
2020 CO2 Emissions (‘000s) 3,311 2,771
2029 CO2 Emissions (‘000s) 3,286 3,145
Table 8.11: Other Renewables Available- Changes to PRS
Resource By the End of Year Nameplate(MW)Energy (aMW)Modification to Strategy
Biomass/Geothermal 2011 10.0 9.1 10 MW Added
Reardan Wind 2012 50.0 15.0 No Change
NW Wind 2012 50.0 17.0 Reduced from 100 MW
Biomass/Geothermal 2012 5.0 4.5 5 MW Added
Biomass/Geothermal 2013 5.0 4.5 5 MW Added
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
Wood Biomass 2017 5.0 4.5 5 MW Added
KFCT Wood Conversion 2019 7.0 0.0 Capacity/Energy
Neutral RECs Added
NW Wind 2019 100.0 33.0 Reduced by 50 MW
Simple Cycle CT 2019 100.0 92.3 100 MW Added
CCCT 2020 250.0 225.0 Delayed from 2019
Upper Falls 2020 2.0 1.0 No Change
NW Wind 2023 50.0 17.0 Delayed from 2022
CCCT 2026 400.0 360.0 Delayed from 2024 and
changed to 400 MW
CCCT 250 MW in 2027
Removed
Total 1,042.0 786.5
NuclearNuclear resources were not included as a PRS option, but were studied as a resource scenario. This resource intrigues planners because of stable operating costs, base-load
capability, and a lack of greenhouse gas emissions. However, nuclear power has high
capital costs, and projected capital and operating costs are speculative since no U.S.
project has been completed in over 20 years. Long lead times require significant capital to be at risk during construction, forcing higher AFDUC costs. If nuclear was an option
in the PRS analysis after 2020 at $5,500 per kW (2009 dollars before AFUDC), the
project would not be selected as least cost, but would lower power supply cost variation.
At $3,800 per kW, a 250 MW nuclear project would be selected as a least cost resource
Avista Corp 2009 Electric IRP- Public Draft 8-29
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 192 of 729
2009 Electric IRPAvista Corp 8-29
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
with a resource that provides capacity. A 25 MW renewable resource with capacity does
not require another resource to provide back-up capacity. But these small renewable
resources are not risk free. The owner might cease production at some point in the
contract term. Biomass facilities often require an industrial waste product as fuel, so a downturn in the industry reduces fuel availability. Geothermal resources are interesting
to Avista because of the potential for low cost and stable base load power, but
availability has been questioned recently by the NPCC and only one geothermal
resource has been built in the Northwest in recent years.
Figure 8.19: Efficient Frontier Base Case vs. Other Renewables Available
$180
$200
$220
$240
$260
$280
$300
$3,300 $3,400 $3,500 $3,600 $3,700 $3,800 $3,900
2010-2020 NPV (millions)
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Where Avista is able to acquire non-wind renewables, its resource portfolio strategy will
emit fewer greenhouse gases (see Table 8.10). The PRS changes under the small renewable resource scenario are shown in Table 8.11. The strategy reduces wind capacity by 100 MW and trades 100 MW of CCCT for SCCT (the cause for increased
risk).
Avista Corp 2009 Electric IRP- Public Draft 8-28
Chapter 8- Preferred Resource Strategy
Table 8.10: Portfolio Cost and Risk Comparison
Base Case
PRS
Non-Wind Renewable
Least Cost
2010-2020 Cost NPV $3,430 $3,393
2020 Expected Cost $909 $875
2020 Standard Deviation $277 $288
2020 Standard Deviation/Cost 30.5%30.9%
2010-2020 Capital $1,247 $840
2020 CO2 Emissions (‘000s) 3,311 2,771
2029 CO2 Emissions (‘000s) 3,286 3,145
Table 8.11: Other Renewables Available- Changes to PRS
Resource By the End of Year Nameplate(MW)Energy (aMW)Modification to Strategy
Biomass/Geothermal 2011 10.0 9.1 10 MW Added
Reardan Wind 2012 50.0 15.0 No Change
NW Wind 2012 50.0 17.0 Reduced from 100 MW
Biomass/Geothermal 2012 5.0 4.5 5 MW Added
Biomass/Geothermal 2013 5.0 4.5 5 MW Added
Distribution Efficiencies 2010-2015 5.0 2.7 No Change
Little Falls Unit Upgrades 2013-2016 3.0 0.9 No Change
Wood Biomass 2017 5.0 4.5 5 MW Added
KFCT Wood Conversion 2019 7.0 0.0 Capacity/Energy
Neutral RECs Added
NW Wind 2019 100.0 33.0 Reduced by 50 MW
Simple Cycle CT 2019 100.0 92.3 100 MW Added
CCCT 2020 250.0 225.0 Delayed from 2019
Upper Falls 2020 2.0 1.0 No Change
NW Wind 2023 50.0 17.0 Delayed from 2022
CCCT 2026 400.0 360.0 Delayed from 2024 and
changed to 400 MW
CCCT 250 MW in 2027
Removed
Total 1,042.0 786.5
NuclearNuclear resources were not included as a PRS option, but were studied as a resource scenario. This resource intrigues planners because of stable operating costs, base-load
capability, and a lack of greenhouse gas emissions. However, nuclear power has high
capital costs, and projected capital and operating costs are speculative since no U.S.
project has been completed in over 20 years. Long lead times require significant capital to be at risk during construction, forcing higher AFDUC costs. If nuclear was an option
in the PRS analysis after 2020 at $5,500 per kW (2009 dollars before AFUDC), the
project would not be selected as least cost, but would lower power supply cost variation.
At $3,800 per kW, a 250 MW nuclear project would be selected as a least cost resource
Avista Corp 2009 Electric IRP- Public Draft 8-29
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 193 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-30 Avista Corp
Chapter 8- Preferred Resource Strategy
after 2020. Avista will continue to monitor and investigate nuclear development as
projects are announced and developed.
Summary
The IRP is a continual effort to select cost- and risk-minimizing resources that
complement existing resources and to help management and policy-makers make
informed decisions for ratepayers. The PRS includes a combination of conservation, distribution efficiency, hydro upgrades, wind and combined-cycle combustion turbines. The resource strategy identified in this report will change as new information becomes
available, but Avista focuses on near-term acquisitions where changes are less likely.
Avista will study large hydro upgrades on the Clark Fork and Spokane rivers to add system capacity and help meet renewable RPS requirements. Figure 8.20 shows power supply costs in 2019 are 38 percent higher in real terms absent carbon legislation, but
up to 95 percent higher with carbon legislation. Power supply costs grow 2.9 percent in
real terms absent carbon legislation and 4.7 percent with carbon legislation.
Figure 8.20: Real Power Supply Expected Cost Growth Index (2010 = 100)
0
50
100
150
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20
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forecasts include historical costs escalating at the average historical rate and future fuel costs for existing resources and all costs for new resources such as operations and maintenance, taxes, depreciation and return. The lines also include incremental
conservation amounts, net market purchases and sales, and carbon costs assuming
100 percent auction.
Avista Corp 2009 Electric IRP- Public Draft 8-30
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 194 of 729
2009 Electric IRPAvista Corp 8-31
Chapter 8 - Preferred Resoure StrategyChapter 8- Preferred Resource Strategy
after 2020. Avista will continue to monitor and investigate nuclear development as
projects are announced and developed.
Summary
The IRP is a continual effort to select cost- and risk-minimizing resources that
complement existing resources and to help management and policy-makers make
informed decisions for ratepayers. The PRS includes a combination of conservation, distribution efficiency, hydro upgrades, wind and combined-cycle combustion turbines. The resource strategy identified in this report will change as new information becomes
available, but Avista focuses on near-term acquisitions where changes are less likely.
Avista will study large hydro upgrades on the Clark Fork and Spokane rivers to add system capacity and help meet renewable RPS requirements. Figure 8.20 shows power supply costs in 2019 are 38 percent higher in real terms absent carbon legislation, but
up to 95 percent higher with carbon legislation. Power supply costs grow 2.9 percent in
real terms absent carbon legislation and 4.7 percent with carbon legislation.
Figure 8.20: Real Power Supply Expected Cost Growth Index (2010 = 100)
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forecasts include historical costs escalating at the average historical rate and future fuel costs for existing resources and all costs for new resources such as operations and maintenance, taxes, depreciation and return. The lines also include incremental
conservation amounts, net market purchases and sales, and carbon costs assuming
100 percent auction.
Avista Corp 2009 Electric IRP- Public Draft 8-30
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Dis
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20
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8-
3
2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 195 of 729
Chapter 8 - Preferred Resoure Strategy
2009 Electric IRP8-32 Avista Corp
Ch
a
p
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8
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Pla
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M
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To
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Th
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Pe
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22
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Ca
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M
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Ex
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30
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(
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(
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Co
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t
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3

2
5

(
2
7
)

(
6
2
)

5
1

1
0

(
5
0
)

(
1
7
4
)
(
2
1
1
) (
2
4
6
)

(
2
8
0
)
(
3
2
2
)

(
3
6
4
)

(
4
2
8
)
(
7
4
3
)

(
7
8
0
)

(
8
1
4
)

PR
S

R
e
s
o
u
r
c
e
s
Win
d
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

CC
C
T
-

-

-

-

-

-

-

-

-

-

2
6
3

2
6
3

2
6
3

2
6
3

2
6
3

5
2
5

5
2
5

7
8
8

7
8
8

7
8
8

Di
s
t
r
i
b
u
t
i
o
n

E
f
f
i
c
i
e
n
c
i
e
s

1

2

3

4

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

Hy
d
r
o

U
p
g
r
a
d
e
s
-

-

-

-

1

2

2

3

3

3

3

5

5

5

5

5

5

5

5

5

To
t
a
l

P
R
S
1

2

3

4

6

7

7

8

8

8

2
7
1

2
7
3

2
7
3

2
7
3

2
7
3

5
3
5

5
3
5

7
9
8

7
9
8

7
9
8

Ne
t

P
o
s
i
t
i
o
n

w
/

P
R
S
31
5

1
5
2

7
4

6
7

3
1

(
2
0
)

(
5
5
)

5
9

1
8

(
4
2
)

9
7

6
2

2
6

(
8
)

(
4
9
)

1
7
1

1
0
7

5
4

1
7

(
1
6
)

Pl
a
n
n
i
n
g

M
a
r
g
i
n
33
%

2
4
%

1
9
%

1
9
%

1
7
%

1
5
%

1
3
%

1
9
%

1
7
%

1
4
%

2
1
%

1
9
%

1
8
%

1
6
%

1
4
%

2
4
%

2
1
%

1
9
%

1
8
%

1
6
%
Av
i
s
t
a

C
o
r
p

20
0
9

E
l
e
c
t
r
i
c

I
R
P
-

P
u
b
l
i
c

D
r
a
f
t

8-
3
3
Ch
a
p
t
e
r

8
-

P
r
e
f
e
r
r
e
d

R
e
s
o
u
r
c
e

S
t
r
a
t
e
g
y

Ta
b
l
e

8
.
1
3
:

L
o
a
d

&

R
e
s
o
u
r
c
e
s

a
t

W
i
n
t
e
r

P
e
a
k

(
M
W
)

20
1
0

2
0
1
1

2
0
1
2

2
0
1
3

2
0
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9
Pe
a
k

D
e
m
a
n
d
1,
7
8
9 1
,
8
3
1

1
,
8
7
1

1
,
9
0
6

1
,
9
5
1

2
,
0
0
8

2
,
0
5
2

2
,
0
9
7
2
,
1
4
6 2
,
1
8
9

2
,
2
3
3

2
,
2
8
1

2
,
3
2
7
2
,
3
7
3

2
,
4
2
6
2
,
4
8
1 2
,
5
5
5 2
,
6
0
4

2
,
6
5
6

2
,
7
0
6

Pla
n
n
i
n
g

M
a
r
g
i
n
26
8

2
7
5

2
8
1

2
8
6

2
9
3

3
0
1

3
0
8

3
1
5

3
2
2

3
2
8

3
3
5

3
4
2

3
4
9

3
5
6

3
6
4

3
7
2

3
8
3

3
9
1

3
9
8

4
0
6

To
t
a
l

O
b
l
i
g
a
t
i
o
n
s
2,
0
5
7 2
,
1
0
6

2
,
1
5
2

2
,
1
9
2

2
,
2
4
4

2
,
3
0
9

2
,
3
6
0

2
,
4
1
2

2
,
4
6
8

2
,
5
1
7

2
,
5
6
8

2
,
6
2
3

2
,
6
7
6

2
,
7
2
9

2
,
7
9
0

2
,
8
5
3

2
,
9
3
8

2
,
9
9
5
3
,
0
5
4 3
,
1
1
2
Ex
i
s
t
i
n
g

R
e
s
o
u
r
c
e
s
Hy
d
r
o
1,
0
3
0 1
,
0
0
0 9
7
2

9
9
7

9
9
7

9
9
7

9
9
7

9
7
0

9
9
7

9
7
1

9
7
1

9
4
4

9
7
1

9
7
1

9
7
1

9
4
4

9
7
1

9
7
1

9
7
1

9
4
4

Ne
t

C
o
n
t
r
a
c
t
s
41
7

3
1
8

3
0
0

3
0
0

3
0
0

3
0
1

3
0
1

4
5
1

4
5
1

4
5
0

3
6
1

3
6
1

3
6
0

3
5
9

3
5
9

3
5
9

3
5
9

7
8

7
8

7
8

Th
e
r
m
a
l

R
e
s
o
u
r
c
e
s
58
0

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

5
8
4

Pe
a
k
i
n
g

R
e
s
o
u
r
c
e
s
22
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

2
2
6

Ca
p
a
c
i
t
y

o
n

M
a
i
n
t
e
n
a
n
c
e

1
0
6

1
0
5

1
0
5

1
0
0

1
0
0

1
0
0

1
0
0

1
2
7

1
0
0

1
0
0

1
0
0

1
2
7

1
0
0

1
0
0

1
0
0

1
2
7

1
0
0

1
0
0

1
0
0

1
2
7

Ex
i
s
t
i
n
g

R
e
s
o
u
r
c
e
s

2
,
3
5
9
2
,
2
3
1

2
,
1
8
7

2
,
2
0
7

2
,
2
0
7

2
,
2
0
7

2
,
2
0
8

2
,
3
5
8

2
,
3
5
8

2
,
3
3
0

2
,
2
4
1

2
,
2
4
1

2
,
2
4
1

2
,
2
4
0

2
,
2
4
0

2
,
2
4
0

2
,
2
4
0

1
,
9
5
9
1
,
9
5
9 1
,
9
5
9
Ne
t

P
o
s
i
t
i
o
n
30
2

1
2
6

3
5

1
5

(
3
6
)

(
1
0
2
)
(
1
5
2
) (
5
4
)

(
1
1
0
)
(
1
8
7
) (
3
2
7
)

(
3
8
2
)
(
4
3
5
)

(
4
8
9
)
(
5
5
0
)

(
6
1
3
)

(
6
9
8
)
(
1
,
0
3
6
)

(
1
,
0
9
5
)

(
1
,
1
5
3
)
Co
n
s
e
r
v
a
t
i
o
n
12

2
4

3
6

4
8

6
2

7
5

9
0

1
0
5

1
2
0

1
3
7

1
5
3

1
7
1

1
8
9

2
0
9

2
2
8

2
4
9

2
7
0

2
9
3

3
1
5

3
3
9

Ne
t

P
o
s
i
t
i
o
n

w
/

C
o
n
s
.

3
1
4

1
5
0

7
1

6
3

2
5

(
2
7
)

(
6
2
)

5
1

1
0

(
5
0
)

(
1
7
4
)
(
2
1
1
) (
2
4
6
)

(
2
8
0
)
(
3
2
2
)

(
3
6
4
)

(
4
2
8
)
(
7
4
3
)

(
7
8
0
)

(
8
1
4
)

PR
S

R
e
s
o
u
r
c
e
s
Win
d
-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

CC
C
T
-

-

-

-

-

-

-

-

-

-

2
6
3

2
6
3

2
6
3

2
6
3

2
6
3

5
2
5

5
2
5

7
8
8

7
8
8

7
8
8

Di
s
t
r
i
b
u
t
i
o
n

E
f
f
i
c
i
e
n
c
i
e
s

1

2

3

4

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

Hy
d
r
o

U
p
g
r
a
d
e
s
-

-

-

-

1

2

2

3

3

3

3

5

5

5

5

5

5

5

5

5

To
t
a
l

P
R
S
1

2

3

4

6

7

7

8

8

8

2
7
1

2
7
3

2
7
3

2
7
3

2
7
3

5
3
5

5
3
5

7
9
8

7
9
8

7
9
8

Ne
t

P
o
s
i
t
i
o
n

w
/

P
R
S
31
5

1
5
2

7
4

6
7

3
1

(
2
0
)

(
5
5
)

5
9

1
8

(
4
2
)

9
7

6
2

2
6

(
8
)

(
4
9
)

1
7
1

1
0
7

5
4

1
7

(
1
6
)

Pl
a
n
n
i
n
g

M
a
r
g
i
n
33
%

2
4
%

1
9
%

1
9
%

1
7
%

1
5
%

1
3
%

1
9
%

1
7
%

1
4
%

2
1
%

1
9
%

1
8
%

1
6
%

1
4
%

2
4
%

2
1
%

1
9
%

1
8
%

1
6
%
Av
i
s
t
a

C
o
r
p

20
0
9

E
l
e
c
t
r
i
c

I
R
P
-

P
u
b
l
i
c

D
r
a
f
t

8-
3
3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 196 of 729
2009 Electric IRPAvista Corp 8-33
Chapter 8 - Preferred Resoure Strategy
Ch
a
p
t
e
r

8
-

P
r
e
f
e
r
r
e
d

R
e
s
o
u
r
c
e

S
t
r
a
t
e
g
y

Ta
b
l
e

8
.
1
4
:

L
o
a
d

&

R
e
s
o
u
r
c
e
s

a
t

S
u
m
m
e
r

P
e
a
k

(
M
W
)

20
1
0

2
0
1
1

2
0
1
2

2
0
1
3

2
0
1
4

2
0
1
5

2
0
1
6

2
0
1
7

2
0
1
8

2
0
1
9

2
0
2
0

2
0
2
1

2
0
2
2

2
0
2
3

2
0
2
4

2
0
2
5

2
0
2
6

2
0
2
7

2
0
2
8

2
0
2
9
Pe
a
k

D
e
m
a
n
d
1,
6
6
9 1
,
7
1
5

1
,
7
5
1

1
,
7
8
3

1
,
8
2
3

1
,
8
7
6

1
,
9
1
5

1
,
9
5
6

2
,
0
0
0

2
,
0
4
0

2
,
0
8
0

2
,
1
2
3
2
,
1
6
5

2
,
2
0
7

2
,
2
5
5

2
,
3
0
4
2
,
3
7
2

2
,
4
1
6

2
,
4
6
3

2
,
5
0
9
Pl
a
n
n
i
n
g

M
a
r
g
i
n
25
0

2
5
7

2
6
3

2
6
7

2
7
3

2
8
1

2
8
7

2
9
3

3
0
0

3
0
6

3
1
2

3
1
8

3
2
5

3
3
1

3
3
8

3
4
6

3
5
6

3
6
2

3
6
9

3
7
6

To
t
a
l

O
b
l
i
g
a
t
i
o
n
s

1
,
9
1
9
1
,
9
7
2

2
,
0
1
4

2
,
0
5
0

2
,
0
9
6

2
,
1
5
7

2
,
2
0
2

2
,
2
4
9

2
,
30
0

2
,
3
4
6

2
,
3
9
2

2
,
4
4
1

2
,
4
9
0
2
,
5
3
8

2
,
5
9
3

2
,
6
5
0

2
,
7
2
8

2
,
7
7
8

2
,
8
3
2

2
,
8
8
5
Ex
i
s
t
i
n
g

R
e
s
o
u
r
c
e
s
Hy
d
r
o
95
3

9
3
2

1
,
0
2
0
1
,
0
2
8

1
,
0
5
1

1
,
0
2
8

1
,
0
4
9

1
,
0
2
2

1
,
0
2
2

1
,
0
2
1

1
,
0
2
3
9
9
6

9
9
6

9
9
3

1
,
0
2
8
9
9
6

9
9
6

1
,
0
0
2
1
,
0
2
3 9
9
6

Ne
t

C
o
n
t
r
a
c
t
s
30
4

2
0
4

1
8
5

1
8
5

1
8
5

1
8
5

1
8
5

3
3
5

3
3
5

3
3
3

3
3
3

3
3
3

3
3
3

3
3
2

3
3
2

3
3
2

3
3
2

6
8

6
8

6
8

Th
e
r
m
a
l

R
e
s
o
u
r
c
e
s

5
7
7

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

5
8
1

Pe
a
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Pla
n
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M
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i
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33
%

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8-
3
4
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 197 of 729
Chapter 9–Action Items 9. Action Items The Integrated Resource Plan (IRP) is an ongoing and iterative process balancing regular publication with pursuing the best long-term resource strategy. The biennial publication date provides opportunities for ongoing improvements to modeling and forecasting procedures and tools, as well as additional research into changing market variables and technologies. This section provides an overview of the progress made on the 2007 IRP Action Plan, while the 2009 Action Plan provides details about issues and improvements developed or raised during this planning cycle, but deferred for treatment in the 2011 IRP. Summary of the 2007 IRP Action Plan The 2007 IRP Action Items were separated into five categories: renewable energy, demand side management, emissions, modeling and forecasting enhancements, and transmission planning. Renewable Energy ƒ Continue studying wind potential in the Company’s service territory, possibly including the placement of anemometers at the most promising wind sites. ƒ Commission a study of Montana wind resources strategically located near existing Company transmission assets
ƒ Learn more about non-wind renewable resources to satisfy renewable portfolio
standards and decrease the Company’s carbon footprint.
Avista has actively studied wind development since the publication of the 2007 IRP. The
Company purchased the rights to develop a large wind project located at Reardan, Washington in May 2008. The site is being developed as described in the PRS chapter.
Met towers were placed at several areas in our service territory to measure wind potential. This wind development work is an ongoing project.
Preliminary work concerning a Montana wind study was done. Transmission limitations
for power coming west and the potential for such projects to not qualify toward the Washington RPS made continued work on Montana wind projects less attractive than
previously thought. Montana wind will be reevaluated as RPS laws change, and as transmission upgrades are made.
Additional studies regarding non-wind renewable energy sources continued throughout
this planning cycle. More details about non-wind renewables are included in the Generation Resource Options and Preferred Resource Strategy chapters. Avista’s
upcoming request for proposals (RFP) for wind and other renewables will provide further details for the availability and cost of non-renewable resources.
Avista Corp 2009 Electric IRP – Public Draft 9-1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 198 of 729
2009 Electric IRPAvista Corp 9-1
Chapter 9 - Action ItemsChapter 9–Action Items
9. Action Items
The Integrated Resource Plan (IRP) is an ongoing and iterative process balancing
regular publication with pursuing the best long-term resource strategy. The biennial
publication date provides opportunities for ongoing improvements to modeling and
forecasting procedures and tools, as well as additional research into changing market variables and technologies. This section provides an overview of the progress made on the 2007 IRP Action Plan, while the 2009 Action Plan provides details about issues and
improvements developed or raised during this planning cycle, but deferred for treatment
in the 2011 IRP.
Summary of the 2007 IRP Action Plan
The 2007 IRP Action Items were separated into five categories: renewable energy,
demand side management, emissions, modeling and forecasting enhancements, and
transmission planning.
Renewable Energy
ƒ Continue studying wind potential in the Company’s service territory, possibly including the placement of anemometers at the most promising wind sites.
ƒ Commission a study of Montana wind resources strategically located near existing Company transmission assets
ƒ Learn more about non-wind renewable resources to satisfy renewable portfolio
standards and decrease the Company’s carbon footprint.
Avista has actively studied wind development since the publication of the 2007 IRP. The
Company purchased the rights to develop a large wind project located at Reardan, Washington in May 2008. The site is being developed as described in the PRS chapter. Met towers were placed at several areas in our service territory to measure wind
potential. This wind development work is an ongoing project.
Preliminary work concerning a Montana wind study was done. Transmission limitations for power coming west and the potential for such projects to not qualify toward the Washington RPS made continued work on Montana wind projects less attractive than
previously thought. Montana wind will be reevaluated as RPS laws change, and as
transmission upgrades are made.
Additional studies regarding non-wind renewable energy sources continued throughout
this planning cycle. More details about non-wind renewables are included in the
Generation Resource Options and Preferred Resource Strategy chapters. Avista’s
upcoming request for proposals (RFP) for wind and other renewables will provide further details for the availability and cost of non-renewable resources.
Avista Corp 2009 Electric IRP – Public Draft 9-1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 199 of 729
Chapter 9 - Action Items
2009 Electric IRP9-2 Avista Corp
Chapter 9–Action Items
Demand Side Management
ƒ Update processes and protocols for integrating energy efficiency programs into the
IRP to improve and streamline the process.
ƒ Study and quantify transmission and distribution efficiency concepts.
ƒ Determine potential impacts and costs of load management options reviewed as part
of the Heritage Project.
ƒ Develop and quantify the long-term impacts of the newly signed contractual relationship with the Northwest Sustainable Energy for Economic Development
organization.
The integration of DSM resources into the IRP is an ongoing process. Progress made
on updating the processes and protocols for integrating energy efficiency programs into
the IRP process can be found in the Energy Efficiency chapter. Transmission and
distribution efficiency improvements have also been studied for this IRP. Details about the results of these studies can be found in the Transmission and Distribution chapter. Five megawatts of distribution feeder peak savings are included in the PRS for the 2009
IRP. Updates on the results of the Heritage Project and the Northwest Sustainable
Energy for Economic Development organization are also included in the Energy Efficiency chapter.
Emissions
ƒ Continue to evaluate the implications of new rules and regulations affecting power plant operations, most notably greenhouse gases.
ƒ Continue to evaluate the merits of various carbon quantification methods and emissions markets.
Avista’s Climate Change Committee and the Resource Planning team have been actively analyzing state and federal greenhouse gas legislation since the publication of the 2007 IRP. This work will continue until final rules are established for the Washington
legislation and federal laws are passed. Then the focus will shift towards mitigating the
cost of climate change to minimize the impact on our customers. Carbon quantification
has been done based on the World Resources Initiative - World Business Council for Sustainable Development (WRI-WBCSD) greenhouse gas (GHG) inventory protocol as part of the push to get ready for state and federal GHG reporting mandates. These
inventories have also been used for Avista’s participation in the Chicago Climate
Exchange and the Carbon Disclosure Project. Details about the work done since the 2007 IRP may be found in the Environmental Policy chapter.
Modeling and Forecasting Enhancements
ƒ Study the potential for fixing natural gas prices through financial instruments, coal
gasification, investments in gas fields or other means.
ƒ Continue studying the efficient frontier modeling approach to identify more and better uses for its information.
ƒ Further enhance and refine the PRiSM model.
Avista Corp 2009 Electric IRP – Public Draft 9-2
Chapter 9–Action Items
ƒ Continue to study the impact of climate change on the load forecast.
ƒ Monitor the following conditions relevant to the load forecast: large commercial load additions, Shoshone county mining developments and market penetration of electric cars.
As explained earlier in the IRP, more studies were done regarding several fixed natural gas opportunities including coal gasification, investment in gas fields or through financial
instruments. The common theme from all of the studies was that the capital or credit
costs would be too high for Avista to effectively participate in any projects or long-term
contracts.
There have been several improvements to the Efficient Frontier and PRiSM modeling
approaches, including solving for minimum acquirable resource sizes, and including
emissions accounting. Projected impacts from climate change and electric car market penetration have been included in the Company’s load forecast, as discussed in the Loads and Resources chapter. Details about changes to relevant load conditions are
also included in the Loads and Resources chapter.
Transmission Planning
ƒ Work to maintain/retain existing transmission rights on the Company’s transmission system, under applicable FERC policies, for transmission service to bundled retail
native load.
ƒ Continue involvement in BPA transmission practice processes and rate proceedings to minimize costs of integrating existing resources outside of the Company’s service
area.
ƒ Continue participation in regional and sub-regional efforts to establish new regional
transmission structures (ColumbiaGrid and other forums) to facilitate long-term
expansion of the regional transmission system.
ƒ Evaluate costs to integrate new resources across Avista’s service territory and from
regions outside of the Northwest.
Transmission planning Action Items are ongoing issues that will be revisited as items in
the 2009 Action Plan. Details about progress made towards the maintenance of existing
transmission rights, involvement in BPA processes, participation in regional
transmission processes, and the evaluation of integrating different resources in the IRP can be found in the Transmission and Distribution chapter.
2009 IRP Action Plan
The Company’s 2009 Preferred Resource Strategy provides direction and guidance for the type, timing and size of future resource acquisitions. The 2009 IRP Action Plan provides an overview of activities planned for inclusion in the 2011 IRP. Progress and
results for each of the Action Plan items will be monitored and reported to the Technical
Advisory Committee and in Avista’s 2011 IRP. The Action Plan was developed using
input from Commission Staff, the Company’s management team and the Technical Advisory Committee.
Avista Corp 2009 Electric IRP – Public Draft 9-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 200 of 729
2009 Electric IRPAvista Corp 9-3
Chapter 9 - Action ItemsChapter 9–Action Items
Demand Side Management
ƒ Update processes and protocols for integrating energy efficiency programs into the
IRP to improve and streamline the process.
ƒ Study and quantify transmission and distribution efficiency concepts.
ƒ Determine potential impacts and costs of load management options reviewed as part
of the Heritage Project.
ƒ Develop and quantify the long-term impacts of the newly signed contractual relationship with the Northwest Sustainable Energy for Economic Development
organization.
The integration of DSM resources into the IRP is an ongoing process. Progress made
on updating the processes and protocols for integrating energy efficiency programs into
the IRP process can be found in the Energy Efficiency chapter. Transmission and
distribution efficiency improvements have also been studied for this IRP. Details about the results of these studies can be found in the Transmission and Distribution chapter. Five megawatts of distribution feeder peak savings are included in the PRS for the 2009
IRP. Updates on the results of the Heritage Project and the Northwest Sustainable
Energy for Economic Development organization are also included in the Energy Efficiency chapter.
Emissions
ƒ Continue to evaluate the implications of new rules and regulations affecting power plant operations, most notably greenhouse gases.
ƒ Continue to evaluate the merits of various carbon quantification methods and emissions markets.
Avista’s Climate Change Committee and the Resource Planning team have been actively analyzing state and federal greenhouse gas legislation since the publication of the 2007 IRP. This work will continue until final rules are established for the Washington
legislation and federal laws are passed. Then the focus will shift towards mitigating the
cost of climate change to minimize the impact on our customers. Carbon quantification
has been done based on the World Resources Initiative - World Business Council for Sustainable Development (WRI-WBCSD) greenhouse gas (GHG) inventory protocol as part of the push to get ready for state and federal GHG reporting mandates. These
inventories have also been used for Avista’s participation in the Chicago Climate
Exchange and the Carbon Disclosure Project. Details about the work done since the 2007 IRP may be found in the Environmental Policy chapter.
Modeling and Forecasting Enhancements
ƒ Study the potential for fixing natural gas prices through financial instruments, coal
gasification, investments in gas fields or other means.
ƒ Continue studying the efficient frontier modeling approach to identify more and better uses for its information.
ƒ Further enhance and refine the PRiSM model.
Avista Corp 2009 Electric IRP – Public Draft 9-2
Chapter 9–Action Items
ƒ Continue to study the impact of climate change on the load forecast.
ƒ Monitor the following conditions relevant to the load forecast: large commercial load additions, Shoshone county mining developments and market penetration of electric cars.
As explained earlier in the IRP, more studies were done regarding several fixed natural gas opportunities including coal gasification, investment in gas fields or through financial
instruments. The common theme from all of the studies was that the capital or credit
costs would be too high for Avista to effectively participate in any projects or long-term
contracts.
There have been several improvements to the Efficient Frontier and PRiSM modeling
approaches, including solving for minimum acquirable resource sizes, and including
emissions accounting. Projected impacts from climate change and electric car market penetration have been included in the Company’s load forecast, as discussed in the Loads and Resources chapter. Details about changes to relevant load conditions are
also included in the Loads and Resources chapter.
Transmission Planning
ƒ Work to maintain/retain existing transmission rights on the Company’s transmission system, under applicable FERC policies, for transmission service to bundled retail
native load.
ƒ Continue involvement in BPA transmission practice processes and rate proceedings to minimize costs of integrating existing resources outside of the Company’s service
area.
ƒ Continue participation in regional and sub-regional efforts to establish new regional
transmission structures (ColumbiaGrid and other forums) to facilitate long-term
expansion of the regional transmission system.
ƒ Evaluate costs to integrate new resources across Avista’s service territory and from
regions outside of the Northwest.
Transmission planning Action Items are ongoing issues that will be revisited as items in
the 2009 Action Plan. Details about progress made towards the maintenance of existing
transmission rights, involvement in BPA processes, participation in regional
transmission processes, and the evaluation of integrating different resources in the IRP can be found in the Transmission and Distribution chapter.
2009 IRP Action Plan
The Company’s 2009 Preferred Resource Strategy provides direction and guidance for the type, timing and size of future resource acquisitions. The 2009 IRP Action Plan provides an overview of activities planned for inclusion in the 2011 IRP. Progress and
results for each of the Action Plan items will be monitored and reported to the Technical
Advisory Committee and in Avista’s 2011 IRP. The Action Plan was developed using
input from Commission Staff, the Company’s management team and the Technical Advisory Committee.
Avista Corp 2009 Electric IRP – Public Draft 9-3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 201 of 729
Chapter 9 - Action Items
2009 Electric IRP9-4 Avista Corp
Chapter 9–Action Items
Resource Additions and Analysis
ƒ Continue to explore the potential for wind and non-renewable resources.
ƒ Issue an RFP for the Reardan wind site, and up to 100 MW of wind or other
renewables in 2009.
ƒ Finish studies regarding costs and environmental benefits of the large hydro
upgrades at Cabinet Gorge, Long Lake, Post Falls and Monroe Street.
ƒ Study potential locations for the natural gas-fired resource identified to be online between 2015 and 2020.
ƒ Continue participation in regional IRP processes, and where agreeable find resource opportunities to meet resource requirements on a collaborative basis.
Energy Efficiency
ƒ Pursue American Reinvestment and Recovery Act of 2009 funding for income
weatherization.
ƒ Analyze and report on results of the July 2007 through December 2009 demand response pilot in Moscow and Sandpoint.
ƒ Have an external party do an updated study on technical, economic, achievable potential for energy efficiency in Avista’s service territory.
ƒ Study and quantify transmission and distribution efficiency concepts as they apply toward meeting Washington RPS goals.
ƒ Update processes and protocols for conservation measurement, evaluation and verification.
ƒ Determine potential impacts and costs of load management options.
Environmental Policy
ƒ Continue to study the potential impact of state and federal climate change
legislation.
ƒ Continue and report on the work of Avista’s Climate Change Committee.
Modeling and Forecasting Enhancements
ƒ Refine cost driver relationships in the stochastic model.
ƒ Continue to refine PRiSM by developing a resource retirement capability, adding the
ability to solve for other risk measurements and by adding more resource options.
ƒ Continue developing Loss of Load Probability and Sustained Peaking analysis for inclusion in the IRP process, and confirm appropriateness of the 15 percent capacity
planning margin assumed for this IRP.
ƒ Continue studying the impacts of climate change on the load forecast.
ƒ Stay load growth trends and their correlation to weather patterns.
Avista Corp 2009 Electric IRP – Public Draft 9-4
Chapter 9–Action Items
Transmission Planning
ƒ Work to maintain/retain existing transmission rights on the Company’s transmission
system, under applicable FERC policies, for transmission service to bundled retail native load.
ƒ Continue involvement in BPA transmission practice processes and rate proceedings to minimize costs of integrating existing resources outside of the Company’s service area.
ƒ Continue participation in regional and sub-regional efforts to establish new regional transmission structures (ColumbiaGrid and other forums) to facilitate long-term expansion of the regional transmission system.
ƒ Evaluate costs to integrate new resources across Avista’s service territory and from regions outside of the Northwest.
ƒ Study and implement distribution feeder rebuild projects to reduce system losses.
ƒ Study transmission reconfigurations to economically reduce system losses.
Avista Corp 2009 Electric IRP – Public Draft 9-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 202 of 729
2009 Electric IRPAvista Corp 9-5
Chapter 9 - Action ItemsChapter 9–Action Items
Resource Additions and Analysis
ƒ Continue to explore the potential for wind and non-renewable resources.
ƒ Issue an RFP for the Reardan wind site, and up to 100 MW of wind or other
renewables in 2009.
ƒ Finish studies regarding costs and environmental benefits of the large hydro
upgrades at Cabinet Gorge, Long Lake, Post Falls and Monroe Street.
ƒ Study potential locations for the natural gas-fired resource identified to be online between 2015 and 2020.
ƒ Continue participation in regional IRP processes, and where agreeable find resource opportunities to meet resource requirements on a collaborative basis.
Energy Efficiency
ƒ Pursue American Reinvestment and Recovery Act of 2009 funding for income
weatherization.
ƒ Analyze and report on results of the July 2007 through December 2009 demand response pilot in Moscow and Sandpoint.
ƒ Have an external party do an updated study on technical, economic, achievable potential for energy efficiency in Avista’s service territory.
ƒ Study and quantify transmission and distribution efficiency concepts as they apply toward meeting Washington RPS goals.
ƒ Update processes and protocols for conservation measurement, evaluation and verification.
ƒ Determine potential impacts and costs of load management options.
Environmental Policy
ƒ Continue to study the potential impact of state and federal climate change
legislation.
ƒ Continue and report on the work of Avista’s Climate Change Committee.
Modeling and Forecasting Enhancements
ƒ Refine cost driver relationships in the stochastic model.
ƒ Continue to refine PRiSM by developing a resource retirement capability, adding the
ability to solve for other risk measurements and by adding more resource options.
ƒ Continue developing Loss of Load Probability and Sustained Peaking analysis for inclusion in the IRP process, and confirm appropriateness of the 15 percent capacity
planning margin assumed for this IRP.
ƒ Continue studying the impacts of climate change on the load forecast.
ƒ Stay load growth trends and their correlation to weather patterns.
Avista Corp 2009 Electric IRP – Public Draft 9-4
Chapter 9–Action Items
Transmission Planning
ƒ Work to maintain/retain existing transmission rights on the Company’s transmission
system, under applicable FERC policies, for transmission service to bundled retail native load.
ƒ Continue involvement in BPA transmission practice processes and rate proceedings to minimize costs of integrating existing resources outside of the Company’s service area.
ƒ Continue participation in regional and sub-regional efforts to establish new regional transmission structures (ColumbiaGrid and other forums) to facilitate long-term expansion of the regional transmission system.
ƒ Evaluate costs to integrate new resources across Avista’s service territory and from regions outside of the Northwest.
ƒ Study and implement distribution feeder rebuild projects to reduce system losses.
ƒ Study transmission reconfigurations to economically reduce system losses.
Avista Corp 2009 Electric IRP – Public Draft 9-5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 203 of 729
Chapter 9 - Action Items
2009 Electric IRP9-6 Avista Corp
Chapter 9–Action Items
Production Credits
Primary 2009 IRP Team
Individual Contribution Contact
Clint Kalich, Manager of Resource Planning & Analysis Project Manager [e-mail]
James Gall, Senior Power
Supply Analyst
Modeling and Analysis
/Author
[e-mail]
John Lyons, Power Supply Analyst Research/Author/Editor [e-mail]
Randy Barcus, Chief Corporate Economist Load Forecast [e-mail]
Lori Hermanson, Partnership
Solutions Manager
Conservation [e-mail]
John Gibson, Senior Efficiencies Engineer Transmission & Distribution [e-mail]
Other Contributors
Jon Powell, Partnership Solutions Manager Bob Lafferty, Director of Power Supply
Greg Rahn, Manager of Natural Gas Planning Scott Waples, Chief System Planner
Kelly Irvine, Natural Gas Analyst Tracy Rolstad, Senior Planning Engineer II
Thomas Dempsey, Manager of Generation
Joint Projects
Steve Silkworth, Manager of Wholesale
Marketing and Contracts
Avista Corp 2009 Electric IRP – Public Draft 9-6
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 204 of 729
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 205 of 729
1411 East Mission Avenue
Spokane, Washington 99202
509.489.0500
www.avistautilities.com
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 206 of 729
Appendix
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 207 of 729
2009

Electric
Integrated Resource Plan

Appendix A – Technical Advisory Committee
Meeting Presentations

August 31, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 208 of 729

2009 Integrated Resource Plan

Technical Advisory Committee Meeting No. 1 Agenda
May 14, 2008

Topic Time Staff

1. Introduction 10:30 Vermillion

2. Load & Resource Balance Update 10:35 Gall

3. Climate Change Update 11:15 Lyons

4. Lunch 12:15

Special Guest - Steve Silkworth- update on renewable acquisitions

5. Loss of Load Probability Analysis 1:15 Gall

6. 2009 IRP Topic Discussions 2:00 Kalich
• Work Plan
• Analytical Process Changes
• Other

7. Adjourn 3:30

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 209 of 729
Load and Resource Balance Forecast
James Gall
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 210 of 729
2007 IRP L&R Review
ƒCapacity & Energy short beginning 2011
ƒLoad is expected to grow at 2.3% over the next 10 years, and
2.0% over the next twenty years
ƒLancaster will be added to the utility’s portfolio beginning in 2010,
pushing our deficit out to 2015 for capacity and 2017 for energy
Lancaster
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 211 of 729
Current L&R
What’s Changed:
ƒLancaster- 270 MW CCCT in Rathdrum, ID will be available Jan
1, 2010
ƒLoad- 10 year growth rate 1.9%, 20 year growth rate 1.8% for
Peak and Energy. The 2010 forecast is 52 aMW lower than
previous forecast or 4.4% lower, due to slow down in growth and
implementation of conservation programs.
ƒHydro- Uses 2006/07 Northwest Power Pool Headwater benefits
study, mean energy is used versus median energy [-8 aMW]
ƒMisc- Updates to contracts, most from WNP-3 expected
availability [+22 aMW]
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 212 of 729
Annual Average Energy Position
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
aM
W
Hydro Base Thermal Contracts Peakers Load Load w/ Cont.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 213 of 729
Annual Average Energy Position (exclude Q2)
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
aM
W
Hydro Base Thermal Contracts Peakers Load Load w/ Cont.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 214 of 729
Annual Position at System Peak
0
500
1,000
1,500
2,000
2,500
3,000
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
MW
Hydro Base Thermal Contracts
Peakers Load Load w/PM, w/o Maint
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 215 of 729
Washington State RPS (aMW)
On-line Year 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020
Native Load (Excludes Potlatch) 1,012 1,034 1,053 1,074 1,094 1,121 1,153 1,177 1,194 1,211 1,233 1,253
WA State Load 659 674 686 700 713 730 751 767 778 789 803 816
Load 10% Change of Exceedance 28 29 29 30 30 31 32 33 33 34 34 35
Planning RPS Load 687 702 715 729 743 761 783 799 811 822 837 851
RPS %0% 0% 0% 3% 3% 3% 3% 9% 9% 9% 9% 15%
Required Renewable Energy 0.0 0.0 0.0 21.3 21.7 22.1 22.6 69.5 71.2 72.5 73.5 124.5
Current Qualifying Resources
Stateline 1999 7.6 7.6 7.6 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0
Long Lake 3 1999 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2 2.2
Little Falls 4 2001 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6
Cabinet 2 2004 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9 2.9
Cabinet 3 2001 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5 4.5
Cabinet 4 2007 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0
Apprentice Credits 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4 0.4
Hydro 10% Chance of Exceedance (4.1)(4.1)(4.1)(4.1)(4.1)(4.1)(4.1)(4.1)(4.1)(4.1)(4.1)(4.1)
Total Qualifying Resources 16.1 16.1 16.1 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5 8.5
Net Requirement Need (Completed) 0.0 0.0 0.0 12.8 13.2 13.6 14.1 61.0 62.7 64.0 65.0 116.0
Budgeted Hydro Upgrades
Noxon 1 2009 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3 2.3
Noxon 2 2010 0.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0 1.0
Noxon 3 2011 0.0 0.0 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3 1.3
Noxon 4 2012 0.0 0.0 0.0 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2 1.2
Little Falls 1 2015 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.6 0.6 0.6 0.6 0.6
Little Falls 2 2016 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.6 0.6 0.6 0.6 0.6
Apprentice Credits 0.5 0.7 0.9 1.2 1.2 1.2 1.3 1.4 1.4 1.4 1.4 1.4
Hydro 10% Chance of Exceedance (1.0)(1.4)(1.9)(2.4)(2.4)(2.4)(2.6)(2.8)(2.8)(2.8)(2.8)(2.8)
Total Budgeted Hydro Upgrades 1.8 2.6 3.6 4.5 4.5 4.5 5.1 5.6 5.6 5.6 5.6 5.6
Net Requirement Need (Budgeted) 0.0 0.0 0.0 8.2 8.6 9.1 9.0 55.3 57.1 58.3 59.4 110.4
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 216 of 729
Climate Change Update
John Lyons, Ph.D.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 217 of 729
2
Climate Change Update
¾Federal GHG legislation – Overview of Lieberman-Warner Bill
¾EPA Analysis of Lieberman-Warner
¾EIA Analysis of Lieberman-Warner
¾Washington Greenhouse Gas Legislation
¾Regional Greenhouse Gas Initiative
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 218 of 729
3
Lieberman-Warner Climate Security Act of 2007
¾Covers emissions of 10,000 mtco2 or greater
¾GHG Emissions Reduction Goals:
2012 – 2005 levels (5,775 mmtco2)
2020 – 15% below 2005 levels (4,924 mmtco2)
2030 – 35% below 2005 levels (3,860 mmtco2)
2040 – 50% below 2005 levels (2,796 mmtco2)
2050 – 70% below 2005 levels (1,732 mmtco2)
2007 total U.S. GHG emissions were about 6,000 mmtco2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 219 of 729
4
Lieberman-Warner Climate Security Act of 2007
¾73.5% of allowances distributed for free in 2012 to 14 different
groups, free allocations decrease over time
¾Allows unlimited banking and trading of allowance
¾Borrowing is from EPA is allowed with interest for up to 15% of
obligations
¾30% of reductions can be offsets (15% domestic and 15%
international)
¾Establishes a Carbon Market Efficiency Board to monitor and
intervene in the carbon market
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 220 of 729
5
EPA Analysis of Lieberman-Warner
¾Reference Case
¾S. 2191 Scenario
¾S. 2191 Scenario with Low International Actions
¾S. 2191 Scenario Allowing Unlimited Offsets
¾S. 2191 Scenario with No Offsets
¾S. 2191 Constrained Nuclear and Biomass
¾S. 2191 Constrained Nuclear, Biomass, and CCS
¾S. 2191 Constrained Nuclear, Biomass, and CCS + Beyond
Kyoto + Natural Gas Cartel
¾Alternative Reference Scenario
¾S. 2191 Alternative Reference Scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 221 of 729
6
U.S. Carbon Footprint Projections 2015 – 2030
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 222 of 729
7
Federal Spending of Auctioned Credits
ADAGE IGEM
Category 2015 2030 2015 2030
Administration of S. 2191 (assumed to be 1% of auction revenues)1.6 2.3 2.2 3.2
Zero or Low‐Carbon Energy Technologies Deployment 7.8 23.7 10.9 32.7
Advanced Coal and Sequestration Technologies Program 6.1 18.5 8.5 25.6
Fuel from Cellulosic Biomass Program 1.5 4.4 2.0 6.1
Advanced Technology Vehicles Manufacturing Program 2.9 8.9 4.1 12.3
Sustainable Energy Program 6.1 18.5 8.5 25.6
Energy Consumers 8.5 25.6 11.7 35.4
Climate Change Worker Training Program 2.4 7.1 3.3 9.8
Adaptation for Natural Resources in the U.S. and Territories 8.5 25.6 11.7 35.4
International Climate Change Adaptation and National Security Program 2.4 7.1 3.3 9.8
Emergency Firefighting Program 1.2 1.2 1.2 1.2
Energy Independence Acceleration Fund 0.9 2.8 1.3 3.9
Total 49.9 145.7 68.7 201.0
ADAGE (Applied Dynamic Analysis of the Global Economy ‐ Ross 2007)
IGEM (Intertemporal General Equilibrium Model ‐ Jorgenson 2007)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 223 of 729
8
Value of Auctioned & Allocated Allowances
ADAGE IGEM
Category 2015 2030 2015 2030
Subtitile A ‐ Auctions (pre‐spent by Feds)47.0 147.0 64.0 201.0
Subtitle B ‐ Early Action 3.0 0.0 4.0 0.0
Subtitle C ‐ States 18.0 26.0 24.0 35.0
Subtitle D ‐ Electricity Consumers 14.0 21.0 20.0 29.0
Subtitle E ‐ Natural Gas Consumers 3.0 5.0 4.0 6.0
Subtitle F ‐ Bonus Allowances for CCS 6.0 9.0 9.0 13.0
Subtitle G ‐ Domestic Ag/Forestry 8.0 12.0 11.0 16.0
Subtitle H ‐ International Forest Protection 4.0 6.0 5.0 8.0
Subtitle I ‐ Transition Assistance 54.0 6.0 74.0 9.0
Subtitle J ‐ Landfill / Coal Mine CH4 Allowance Set ‐ Asides 2.0 2.0 2.0 3.0
Total 159.0 234.0 217.0 320.0
  net of customer "refunds"142.0 208.0 193.0 285.0
  customer refund %11% 11% 11% 11%
ADAGE (Applied Dynamic Analysis of the Global Economy ‐ Ross 2007)
IGEM (Intertemporal General Equilibrium Model ‐ Jorgenson 2007)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 224 of 729
9
EPA Analysis of U.S. Carbon Emission Cost
($/Metric Ton)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 225 of 729
10
EPA Analysis Total U.S. Carbon Emission Cost
($billions)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 226 of 729
11
EIA Analysis of Lieberman-Warner
¾Analysis included 7 cases
¾Reference Case
¾S. 2191 Core
¾No International Offsets Case
¾S. 2191 High Cost (CCS, Nuclear and biomass costs 50% higher
than in the base case)
¾S. 2191 Limited Alternatives
¾S. 2191 Limited Alternatives / No International Offsets
¾S. 1766 Update (Low Carbon Economy Act of 2007)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 227 of 729
12
EIA Analysis Results
¾As expected, impacts directly related to the availability and cost of
low-carbon technologies such as CCS and nuclear, as well as the
availability of international offsets
¾Results are also dependent upon the assessment of the current
high commodity prices being permanent or temporary
¾Most reductions before 2030 are electricity-related
¾GDP reductions in the S. 2191 cases
¾2020: 0.3% to 0.9%
¾2030: 0.3% to 0.8%
¾Higher manufacturing impacts
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 228 of 729
13
EIA Analysis Results
¾Significant increases in new capacity because of early retirement
of coal plants through 2030
¾There are limited opportunities in the electric power industry after
2030 because the most GHG-intensive plants will have been retired,
but population growth will require new generation
¾Delivered coal prices increase 405% to 804% in 2030 (2006$)
¾Natural gas prices increase 34% to 107% in 2030 (2006$)
¾Retail gasoline prices increase $0.41 to $1.01 in 2030
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 229 of 729
14
Washington State GHG legislation
Washington state has three different laws that directly impact GHG
emissions and electric resource planning:
¾Washington Energy Independence Act (I-937): 15% of new
generation must be renewable by 2020
¾SB 6001: Limits new base load generation to 1,100 pounds of
CO2 per MWh
¾HB 2815: Sets GHG reductions goals for the state as part of
the Western Climate Initiative
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 230 of 729
15
Washington HB 2815
Goals are set to meet Washington’s share of the Western Climate
Initiative
¾2020 – Below 1990 levels
¾2035 – 25% below 1990 levels
¾2050 – 50% below 1990 levels
¾May 2008: Guidelines are expected to be released by Department
of Ecology
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 231 of 729
16
Avista Generation Carbon Footprint
(WRI-WBCSD Protocols, Selected Years 1990-2006)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 232 of 729
17
Avista/WI Generation Carbon Footprint
(millions of tons)
-
1.0
2.0
3.0
4.0
5.0
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
Avista CO2 Footprint
Western Interconnect CO2
Footprint (factor 100)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 233 of 729
18
Regional Greenhouse Gas Initiative (RGGI)
¾Begins January 1, 2009
¾Memorandum of understanding signed in 2005 and includes 10
northeastern states
¾Caps CO2 emissions from all power plants greater than 25 MW
¾Emissions capped at 121 million short tons per year from 2009
through 2014
¾2015 – 2019 emissions cap reduced by 10%
¾25% of allowances must be strategic or customer oriented in
nature
¾Some offsets allowed – amount tied to allowance price
¾Quarterly auctions beginning in September 2008 with most states
having 100% auctions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 234 of 729
Loss of Load Probability
James Gall
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 235 of 729
What is Loss of Load Probability?
A measure of the probability that a system demand will exceed
capacity during a given period; often expressed as the estimated
number of days over a long period, frequently 10 years or the life of
the system.
-U.S. Department of Energy
Our study is measured as # of draws where there was a loss of
load, for example 1 in 20 draws, is 5%.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 236 of 729
LOLP Model Overview
What is it?
ƒEstimates the probability that not all of load will be served in a
given simulation
ƒUses available capacity for a given week in January and August
ƒSimulates major random events, such as wind, hydro, load, and
forced outages
ƒUsed to validate planning margin in IRP forecast period
What it is not?
ƒEnergy dispatch model
ƒFinancial costs are not considered
ƒNo estimates for localized transmission/distribution outages
ƒDoes not take into account natural disaster/terrorism related
outages
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 237 of 729
How It Works
Runs for 168 continuous hours (7 days) in January & August
1)Load is estimated (-)
2)Available capacity from thermal resources (+)
3)Run of river hydro (+)
4)Wind shape calculated (+)
5)Contracts are netted (+/-)
6)Available storage hydro is shaped to high load hours (+) [LP]
7)Market energy purchased up to an assumed limit (+) [LP]
8)Federal hydro release from upstream storage (+) [LP]
9)If load is not served in one or more hours, loss of load occurs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 238 of 729
Load
ƒUses actual 2007 hourly load shapes for January and August
ƒEach day an amount of energy is drawn,
ƒCorrelated to previous day to simulate cold and hot snaps,
ƒBased on historic weekly energy shape, and
ƒNormal distributions are assumed
1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
0 12 24 36 48 60 72 84 96 108 120 132 144 156
Hour
MW
Draw
Expected Case
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 239 of 729
Hydro
ƒAvailable energy is a random draw from 70 year historical record
from the Northwest Power Pool
ƒRun-of-River projects use this energy shaped to historical flow
ƒStorage projects use a Linear Program (LP) to move hydro
energy to more valuable hours subject to storage constraints and
minimum and maximum capacity.
ƒPlants can spill energy, and draft reservoirs to minimum level
ƒScenarios can be studied with/without federal hydro release from
upstream storage to prevent load loss
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 240 of 729
Wind
ƒHourly shape based on expected mean energy and frequency
distribution for on/off peak hours by month
ƒHour to hour correlation
ƒFuture enhancement will have projects correlated
January: On-Peak
0%
25%
50%
75%
100%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Probability
Ca
p
a
c
i
t
y

F
a
c
t
o
r
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 241 of 729
Forced Outages
ƒFor each plant:
ƒForced Outage Rate (FOR)
ƒMean Time To Repair (MTTR)
ƒRamp Rate
ƒFor each hour a unit has a probability of an outage, calculated
as:
Outage Probability = FOR x 8760 / MTTR / 52
e.g. 0.10 x 8760 / 24 / 52 = 70% chance of outage in the week or 0.42% in a given hour
ƒIf an outage is drawn, another probability is calculated if the unit
is to return to service, calculated as:
Return to Service if: Rnd# > 1 / MTTR, than “on”, otherwise “off”
ƒIf a unit has a ramp rate, such as 10 hours, the units available
generation will increase linearly over 10 hours until it reaches
maximum capability
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 242 of 729
2009 Results- Base Case
1,4921,656Average Peak Load
00Federal Hydro
300300Available Market (MW)
1,0811,319Average Load
2,0052,023Peak Load
55.6%47.6%Market Reliance
3.8%2.1%Loss of Load
AugustJanuary
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 243 of 729
How Many Iterations Do You Need?
0.0%
1.0%
2.0%
3.0%
4.0%
5.0%
6.0%
7.0%
8.0%
1
50
1
10
0
1
15
0
1
20
0
1
25
0
1
30
0
1
35
0
1
40
0
1
45
0
1
50
0
1
55
0
1
60
0
1
65
0
1
January
August
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 244 of 729
2009 Results- Scenario 1, Less Market Opportunity
200 MW (on-peak), 300 MW (off-peak)
1,4941,656Average Peak Load
00Federal Hydro
200200Available Market (MW)
1,0811,319Average Load
1,8412,053Peak Load
56.1%47.3%Market Reliance
12.1%7.4%Loss of Load
AugustJanuary
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 245 of 729
2009 Results- Scenario 2, Increase Market Opportunity
400 MW of Market
1,4941,656Average Peak Load
00Federal Hydro
400400Available Market (MW)
1,0811,319Average Load
1,7622,026Peak Load
56.1%47.3%Market Reliance
0.9%0.4%Loss of Load
AugustJanuary
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 246 of 729
2020 Results- Scenario 3, Potential Future
1,8492,048Average Peak Load
00Federal Hydro
300300Available Market (MW)
1,3381,631Average Load
2,2792,494Peak Load
19.6%41.7%Market Reliance
0.8%3.3%Loss of Load
AugustJanuary
Adds: Lancaster (270 MW), Reardan (50 MW), CCCT (200 MW), Wind (200 MW)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 247 of 729
2020 Results- Scenario 4, All Wind Future
1,8482,048Average Peak Load
00Federal Hydro
300300Available Market (MW)
1,1381,629Average Load
2,1982,515Peak Load
51.8%73.5%Market Reliance
3.2%9.8%Loss of Load
AugustJanuary
Adds: Lancaster (270 MW), Reardan (50 MW), CCCT (0 MW), Wind (400 MW)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 248 of 729
2020 Results- Scenario 5, Flat Wind Future
1,8512,047Average Peak Load
00Federal Hydro
300300Available Market (MW)
1,3391,630Average Load
2,2382,662Peak Load
39.0%65.7%Market Reliance
1.8%6.0%Loss of Load
AugustJanuary
Adds: Lancaster (270 MW), Reardan (50 MW), CCCT (0 MW), Wind (400 MW)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 249 of 729
2009 Results- Scenario 6, 5% LOLP Case
1,4931,657Average Peak Load
00Federal Hydro
270235Available Market (MW)
1,0801,319Average Load
1,7801,992Peak Load
54.8%47.5%Market Reliance
5.1%4.9%Loss of Load
AugustJanuary
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 250 of 729
What it takes to stay at 5% LOLP for 2009 if remove
100MW of market availability
ƒRemove 100MW of Market: 15.1%/15.9%
ƒAdd 100MW of CCCT: 5.0%/5.4%
ƒAdd 300MW of Wind: 7.9%/11.1%
ƒAdd 600MW of Wind: 6.0%/8.3%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 251 of 729
2009 Results- Scenario 7, Federal Hydro 16 hrs
1,4931,657Average Peak Load
16 hrs16 hrsFederal Hydro
300300Available Market (MW)
1,0801,320Average Load
1,7852,025Peak Load
55.8%47.6%Market Reliance
0.0%0.1%Loss of Load
AugustJanuary
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 252 of 729
2009 IRP Topic Discussions
Clint Kalich
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 253 of 729
Work Plan – Proposed TAC Meeting Schedule
May 14, 2008 –Kickoff Meeting
August 2008 –TBD
October 2008 –TBD
January 2009 –Review of final modeling and assumptions
March 2009 –Review of scenarios and futures, resource, and
transmission costs
April 2009 –Review of final PRS
June 2009 –Review of report
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 254 of 729
Work Plan – Flow Diagram
Resource Option Analysis
Mark to market all generation and
conservation opportunities
Levelized Cost Calculation
Conservation
Costs
AURORAXMP
Base Case
Expected Fuel
Prices, Load,
Transmission,
Resources
Develop Capacity
Expansion for
Western
Interconnect
Generate electric
price forecast
Intrinsic resource
market valuation
Preferred Resource Strategy
Given constraints arrives at a least-cost solution defined
in terms of present value of expected power supply
expenses and risk, and generates an efficient frontier
analysis.
Model selects resources and conservation measures to
meet capacity and energy deficits, greenhouse gas
limits, and renewable & conservation portfolio standards
Risk is defined as the variation in power supply
expenses derived from stochastic studies
Market Futures
Stochastic
Load, fuel price, hydro,
wind generation,
emissions, thermal forced
outages.
Market Scenario
Deterministic
Implicit market scenarios
Separate capacity
expansion for each
scenario
PRiSM 2.1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 255 of 729
Work Plan – Timeline on IRP Development
Preferred Resource Strategy
Identify Regional resource options for electric market price forecast 8/15/2008
Identify Avista’s resource options 8/31/2008
Develop PRiSM 2.1 model & implement 9/15/2008
Update AURORAxmp database for electric market price forecast 9/30/2008
Select natural gas price forecast 10/10/2008
Finalize deterministic Base Case 10/17/2008
Create datasets/statistics variables for risk studies 10/31/2008
Base case risk study complete 11/30/2008
Develop Efficient Frontier & PRS 1/30/2009
Simulation of risk studies “futures” complete 1/30/2009
Simulate market scenarios in AURORAxmp 2/27/2009
Evaluate resource strategies against market futures & scenarios 3/20/2009
Present to TAC preliminary study and PRS 3/31/2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 256 of 729
Work Plan – Timeline on IRP Development
Writing Tasks
File 2009 Integrated Resource Planning Work Plan 8/30/2008
Prepare Report and Appendix Outline 9/15/2008
Prepare text drafts 4/15/2009
Prepare charts and tables 4/15/2009
Internal draft released 5/1/2009
External draft released 6/15/2009
Final editing and printing 8/1/2009
Report distribution 8/30/2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 257 of 729
Analytical Process Changes
DSM Fully Integrated Into PRiSM
ƒValuation, risk, selection
PRiSM Improvements
ƒ“Lumpiness” added
ƒPortfolio carbon limits
ƒAdditional resource options
ƒPlant retirement
ƒNew efficient frontier method (balancing risk and cost)
ƒEnd effects more accurately modeled
ƒAdded AFUDC
ƒMarket and green tag purchases risk
Resource dispatch & valuation
ƒEvaluating options to AURORA (e.g., LP Model)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 258 of 729
Planning Futures/Scenarios
ƒMore carbon looks
ƒSolar cost collapse
ƒSustained high gas prices
ƒLots of nuclear (government support/promotion)
ƒ25% RPS nationwide
ƒBack to the Future
ƒDetermine cost of renewable energy & carbon legislation
ƒOther Ideas from TAC??
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 259 of 729

2009 Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
August 27, 2008

Topic Time Staff

1. Introduction 10:30 Vermillion

2. Risk Assumptions/PRiSM 10:35 Gall

3. Resource Assumptions 11:30 Lyons

4. Lunch 12:15

5. Scenarios and Futures 1:15 Lyons

6. Demand Side Management 2:00 Powell

7. Adjourn 3:30

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 260 of 729
Stochastic Analysis & Resource Portfolio
Selection Modeling
James Gall
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 261 of 729
2
Presentation Overview
Risk
ƒDiscuss methods and risk assumptions, expected (mean) values
will be discussed at later TAC meetings
ƒVariable correlations are difficult to quantify, recommendations
are placeholders until better information is available or the TAC
agrees the assumption is acceptable for modeling purposes
ƒRisk analysis is modeled in AURORA- impacts electric markets
prices and the cost of new resource options
ƒFeedback and suggestions are needed
PRiSM
ƒOverview of the model and enhancements
ƒFeedback and suggestions are welcome
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 262 of 729
Stochastic Analysis Methods & Assumptions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 263 of 729
4
Long-Term Correlation Matrix
Lancaster
1.00-0.25-0.25Load Growth
1.000.50Hog Fuel Prices
1.00-0.25-0.25-0.25New Coal Prices
1.001.000.75SO2Prices
1.000.75NOXPrices
1.000.50CO2Prices
1.00Gas Prices
Load
Growth
Hog
Fuel
Prices
New
Coal
Prices
SO2
Prices
NOX
Prices
CO2
Prices
Gas
Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 264 of 729
5
Carbon Dioxide Credit Prices (CO2, GHG)
ƒSimilar method to 2007 IRP
ƒFor each iteration, a potential carbon cost scenario is selected,
based on a weighting of 10 EPA studies.
ƒAfter the scenario is selected, the cost is treated as an expected
value and a lognormal distribution is applied to each year.
ƒFurther, natural gas and other market price drivers are correlated
to the CO2 prices
ƒThe intent of this method is model the unknown nature of climate
change legislation, it potential for year-to-year price volatility, and
its affect on other major market price drivers.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 265 of 729
6
Carbon Dioxide Credit Prices (nominal)
81.31 59.91 42.76 33.09 23.46 --Expected Value100%
47.69 28.66 20.63 17.37 10.20 --EPA S. 1766 ADAGE15%
109.34 85.97 61.89 46.75 35.00 --EPA S. 2191 Alt. Ref. IGEM5%
75.27 54.30 38.51 30.14 21.00 --EPA S. 2191 Alt. Ref. ADAGE35%
159.63 132.73 94.90 72.29 57.20 --EPA S. 2191 ADAGE Scenario 72%
119.07 95.02 67.39 51.85 39.70 --EPA S. 2191 ADAGE Scenario 63%
221.27 190.04 134.79 100.39 80.80 --EPA S. 2191 IGEM with No Offsets2%
47.69 28.66 20.63 16.09 8.70 --EPA S. 2191 IGEM Unlimited Offsets10%
88.25 66.36 48.14 36.53 26.20 --EPA S. 2191 ADAGE - Low Intl Action15%
122.3298.04 70.15 53.13 40.50 --EPA S. 2191 IGEM3%
94.74 72.40 50.89 39.08 28.60 --EPA S. 2191 ADAGE10%
2029202520202016201220112010Nominal $/ Short Ton%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 266 of 729
7
Carbon Dioxide Credit Prices (Cont.)
ƒRandomly draws price strips for each AURORA iteration
ƒEach year has lognormal distribution (draw is the mean), market
become less volatile over time as market matures
ƒ2012-2014 prices use 50% sigma
ƒ2015-2016 prices use 25% sigma
ƒ2017-2029 prices use 10% sigma
2012 Price Distribution
0%
2%
4%
6%
8%
10%
12%
14%
16%
$0 $10 $20 $30 $40 $50 $60 $70 $80 $90 $100 $110 $120
$/ ShortTon
Pr
o
b
a
b
i
l
i
t
y
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 267 of 729
8
CO2 Price Trends (10 Simulations)
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$
p
e
r

s
h
o
r
t

t
o
n
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 268 of 729
9
Natural Gas Prices
ƒLognormal distribution
ƒCorrelated to CO2 credit prices (50% as placeholder),
–Wood Mackenzie will help identify this assumption by studies that
model gas prices by changes in gas demand from CO2 legislation
ƒAssumes 35% sigma before CO2 volatility is applied, than ~58-
70%
ƒMonthly prices may be correlated to load in the winter
ƒNo direct annual serial correlation
ƒLoad growth is negatively correlated at 25%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 269 of 729
10
y = 0.1461x + 4.2886
R2 = 0.3481
$-
$5
$10
$15
$20
$25
$30
$35
$- $20 $40 $60 $80 $100 $120 $140 $160
CO2 Prices ($/Short Ton)
Na
t
u
r
a
l

G
a
s

P
r
i
c
e
s

(
H
H

$
/
D
t
h
)
Modeled Natural Gas & CO2 Price Relationship
Year 2015, Correlation 59%, 500 draws
Expected Gas Price
Ex
p
e
c
t
e
d

C
O
2
Pr
i
c
e
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 270 of 729
11
Load Growth
ƒNormal distribution
ƒStandard deviation is equal to expected value, represents
potential volatility due economic activity (perhaps too
volatile)
ƒEnergy load growth negatively correlated to gas (-25%),
CO2 (-25%),
ƒPeak load variance modeled as weather variance
ƒWestern Interconnect regional correlation between zones,
similar to the 2007 IRP
ƒPotential correlation between natural gas prices in winter
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 271 of 729
12
2010 Distribution Example
0
20
40
60
80
100
-9.0% -6.0% -3.0% 0.0% 3.0% 6.0% 9.0% 12.0%
Load Change
Fr
e
q
u
e
n
c
y
0%
20%
40%
60%
80%
100%
Cu
m
u
l
a
t
i
v
e
Frequency
Cumulative %
Avista Load Growth Example
Avista Historic Load Growth
-6%
-4%
-2%
0%
2%
4%
6%
8%
19
9
0
19
9
1
19
9
2
19
9
3
19
9
4
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
Ye
a
r

o
v
e
r

Y
e
a
r

L
o
a
d

C
h
a
n
g
e
Avg Growth: 1.7%
Stand Dev: 3%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 272 of 729
13
Load Growth Example (Forecast- 5 draws)
-6%
-4%
-2%
0%
2%
4%
6%
8%
19
9
0
19
9
2
19
9
4
19
9
6
19
9
8
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
Ye
a
r

o
v
e
r

Y
e
a
r

L
o
a
d

C
h
a
n
g
e
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 273 of 729
14
Hog Fuel (Wood Waste) Prices
ƒNormal distribution
ƒStandard deviation: 10% of expected value
ƒPositively correlated CO2 (50%) prices,
–A higher CO2 price could add demand to Wood Prices to offset
CO2
ƒPotential correlation to load growth, but more likely correlated to
on economic growth, while loads tend to have additional drivers
ƒWhat about correlating to natural gas prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 274 of 729
15
$-
$5
$10
$15
$20
$25
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
Ga
s

(
$
/
d
t
h
)
,

W
o
o
d

(
$
/
T
o
n
)
Sumas Gas Price
KF Wood
Kettle Falls Prices Compared to Sumas Gas Prices
92% Correlation
A multiple regression including inflation & natural gas prices were tested to see if inflation was
actually the cause for the correlation.
The results indicated that Sumas gas prices was not a significant predictor of wood prices.
Therefore natural gas will not be correlated to wood prices for this IRP.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 275 of 729
16
Mine Mouth Coal Price
ƒNormal distribution
ƒStandard deviation: 10% of expected value
ƒNegatively correlated to CO2 (-25%), and other emissions (-25%)
–As policy changes decreasing domestic coal demand, prices could
potentially lower as coal mines remain open for international
demand
ƒBasis for short and long-haul coal prices for new coal options-
this should not affect market prices to any extent
ƒNo change to existing coal prices for existing plants
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 276 of 729
17
NOX and SO2 Credit Prices
ƒLognormal distribution
ƒStandard Deviation: 10% of expected values
ƒExpected values will be based on July 2008 Wood-Mackenzie
study
ƒPositively correlated to CO2 prices (75%)
–Stricter CO2 policy will likely lead to stricter air emissions policy
and additional gas fired generation- requiring the needs for credits
ƒNegatively correlated to new coal prices (-25%)
ƒNo mercury prices will be modeled in this IRP, rather controls will
be assumed to be installed on required plants.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 277 of 729
18
Hydro
ƒEach year of each iteration will randomly draw of historical 70
year history (1929-1998)
ƒNo historical evidence of normality
Mid Columbia Hydro Project Capacity Factor Distribution
0
1
2
3
4
5
6
7
33
%
35
%
37
%
39
%
41
%
43
%
45
%
47
%
49
%
51
%
53
%
55
%
57
%
59
%
Capacity Factor
Fr
e
q
u
e
n
c
y
0%
20%
40%
60%
80%
100%
120%
Frequency
Cumulative %
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 278 of 729
19
Wind
ƒGeneric wind for existing projects will use fixed shape with
distribution of energy- this is only used for market analysis.
ƒFor potential Avista wind resources, each hour will be randomly
drawn based on its probability of occurrence in a given month
and time of day with correlation to previous hour.
ƒStatistics are available for potential projects on the Columbia
River, Reardan, and Montana.
ƒSimilar method was used in the 2007 IRP.
ƒPotential correlation to winter hydro conditions and will be
evaluated
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 279 of 729
20
Forced Outages
ƒUse AURORA logic for random forced outages
ƒOnly Coal, Nuclear, and CCCT plants will be modeled with F/O
logic
ƒMean Repair Times:
–Nuclear: 84 hours
–Coal: 72 hours
–CCCT: 24 hours
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 280 of 729
PRiSM
Preferred Resource Strategy Model
Overview & Enhancements
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 281 of 729
22
What is PRiSM?
ƒPreferred Resource Strategy Model
–Selects resource & conservation opportunities on an optimal cost
and risk basis using a linear program (What’s Best!)
–What’s Best is a linear programming tool added to MS Excel
ƒObjective function is to either select resource strategies to meet
our energy/capacity/market/RPS/CO2 requirements on a least
cost or least risk basis
ƒCost is measured by the present value of incremental fuel &
O&M expenses and new capital investment
ƒRisk is measured by the variation in fuel & variable O&M
expenses in years 2019 & 2029 (possible PV of 20 years)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 282 of 729
23
Efficient Frontier- Introduction
Ri
s
k
Expected Return
Stocks
Bonds
T-Bills
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 283 of 729
24
Efficient Frontier- Introduction
Present Value of Cost
Ma
r
k
e
t

R
i
s
k
Nuclear
CCCT
Market/SCCT
Wind
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 284 of 729
25
New Enhancements
ƒConservation measures are selected in model rather than an
input (only measures that are between $xx/MWh & $xxx/MWh)
ƒResources are now added in increments rather than any amount
ƒUse more precise method to estimate frontier curve
ƒMeets both summer & winter capacity requirements
ƒAbility to retire resources
ƒAbility to account for greenhouse gas caps
ƒMore accurate ability to take into account post IRP time period
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 285 of 729
2009 IRP Resource Assumptions
John Lyons
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 286 of 729
2
Supply Side Resource Data Sources
ƒResource lists developed internally
–Trade journals
–Press releases
–Engineering studies and models (ThermoFlow)
–Announcements from state commissions
–International projects
–Proposals from developers
ƒPower Council
ƒConsulting firms/reports: Wood Mackenzie, Goldman Sachs,
Black & Veatch
ƒState and federal resource studies
ƒThese data sources are used to develop generic resource types
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 287 of 729
3
Resource Differences from 2007 IRP
ƒFewer types of coal resources are included – only ultra critical
and IGCC plants are being modeled
ƒAlberta oil sands are not included as a resource option
ƒSolar and hydro are being included as resource options for the
preferred resource strategy
ƒAdding more specifics for the Other Renewable Resources
category – geothermal, biomass, and solar resources are being
modeled separately
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 288 of 729
4
Non-Renewable Supply Side Resources
ƒNatural Gas Combined Cycle (CCCT)
–2 x 1 and 1 x 1 with duct burner water cooled (1x1 for PRS)
–2 x 1 and 1 x 1 with duct burner air cooled
–600 MW with sequestration
ƒNatural Gas-Fired Simple Cycle – Aero, Frame, and Hybrid
ƒSmall co-generation (< 5 MW)
ƒPipeline co-generation
ƒCoal – ultra critical, IGCC, and IGCC with sequestration
ƒNuclear
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 289 of 729
5
2008 Combined Cycle Total Installed Cost Estimate
2,000 Feet Elevation
$400
$800
$1,200
$1,600
$2,000
$2,400
$2,800
$3,200
0 25 50 75
10
0
12
5
15
0
17
5
20
0
22
5
25
0
27
5
30
0
32
5
35
0
37
5
40
0
Elevation & Loss Adjusted Capacity (MW)
In
s
t
a
l
l
e
d

C
o
s
t
s

(
$
/
k
W
)
Total Plant Installed Cost
CC $/kW Installed Curve Fit
7FA
7FB
501F
501G
Siemans SGT
6600G
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 290 of 729
6
2008 Simple Cycle Total Installed Cost Estimate
2,000 Feet Elevation
$0
$400
$800
$1,200
$1,600
$2,000
0 25 50 75
10
0
12
5
15
0
17
5
20
0
22
5
25
0
27
5
Elevation and Loss Adjusted Capacity (MW)
GT

E
q
u
i
p
m
e
n
t

O
n
l
y

a
n
d

I
n
s
t
a
l
l
e
d

Co
s
t
s

(
$
/
k
W
)
Gas Turbine Equipment Only Cost
Total GT $/kW Installed Cost
LMS100 Gas Turbine Only Cost
Total LMS 100 Installed Cost
LMS 100
LM6000
P&W Swift Pac 50
7EA 7FA 7FB
Siemans
SGT6-
5000F
501 G
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 291 of 729
7
Renewable Supply Side Resources
ƒGeothermal
ƒWind – 100 MW, < 5 MW, and offshore
ƒCCCT Wood Boiler
ƒWood Gasification Conversion
ƒOpen Loop Biomass – landfill gas, wood, waste, etc.
ƒClosed Loop Biomass
ƒSolar Photovoltaic
ƒSolar Thermal
ƒRoof Top Solar
ƒTidal Power
ƒHydrokinetics
ƒRun of River Hydro
ƒPumped Storage
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 292 of 729
8
Avista Resource Upgrades
ƒLittle Falls Unit #1 – 4 Upgrades
ƒPost Falls Unit #6 Upgrade
ƒUpper Falls Upgrade
ƒLong Lake new unit and new powerhouse
ƒCabinet Gorge #5
ƒScheduled upgrades and acquisitions are included in the L&R
–Noxon Rapids Units #1 – 4 scheduled for 2009 – 2012
–Lancaster Generation Facility – 2010
–Reardan – preliminarily scheduled for 2011
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 293 of 729
Avista 2009 IRP Resource Assumptions
Draft as of 8/27/082009 Dollars
Resource (not locational specific)First Year Available Availability (MW)
Capital Cost- Exclude
AFUDC (2009$/kW)
Transmission
Interconnect ($/kW)Construction (Yrs)Fixed O&M ($/kW/Yr)
Net HHV Heat
Rate(s) (Btu/kWh)
Variable
Costs ($/MWh)
Gas
Transport ($/Dth/Mn)Fuel Charge (%)
Winter
Capacity Credit (%)
Summer
Capacity Credit (%)Availability (%)Forced Outage (%)
Annual Avg
Maintenance (days)Min Dispatch (%)Start up Cost ($/MW/Start)Start up Fuel (Dth/MW/Start)Ramp Rate (%/hr)CO2 (lbs/mmbtu)SO2 (lbs/mmbtu NOX (lbs/mmbtu)Federal Incentives Sources/NotesCCCT (2x1) w/ duct burner (wet)2011 N/A 3 6,750/ 8,500 3.29 0.27 1.0 105 95 90.1 5 18 55 35 6.6 20 117 0.0006 0.02 No
CCCT (2x1) w/ duct
burner (dry)2011 N/A 3 6,900/
8,700 3.29 0.27 1.0 105 95 90.1 5 18 55 35 6.6 20 117 0.0006 0.02 No
CCCT (1x1) w/ duct
burner (wet)2011 N/A 900 3 11.0 6,750/
8,500 3.29 0.27 1.0 105 95 90.1 5 18 55 35 6.6 20 117 0.0006 0.02 No O&M: '08 CS2 Budget (LTSA/Major Maint is in VOM calculation), emissions based on CS2, Eng. Est.
CCCT (1x1) w/ duct burner (dry)2011 N/A 928 3 11.0 6,900/ 8,700 3.29 0.27 1.0 105 95 90.1 5 18 55 35 6.6 20 117 0.0006 0.02 No Capital Cost Est from Thermoflex and HR based on
CCCT (600MW, w/ Seq) 2025 N/A 0.27 1.0 105 95 90.1 5 18 11.7 0 0 No
Small Co-Gen (<5MW) 2011 15 2,000 1.5 5.0 5,700 5.00 0.27 1.0 105 95 92.3 5 10 n/a n/a n/a n/a 117 0.0006 0.02 No
Pipeline Co-Gen 2010 n/a n/a n/a n/a n/a n/a n/a n/a n/a No
Frame SCCT 2010 N/A 480 1.5 10,200 5.00 0 3.4 105 95 92.3 5 10 15 3.7 100 117 0.0006 0.02 No Thermoflex, NPCC
Hybrid SCCT (LMS 100) 2010 N/A 900 1.5 8,400 5.00 0 3.4 105 95 92.3 5 10 100 117 0.0006 0.02 No Thermoflex, NPCC
Wind (100MW)2010 500 2,400 2 50.0 n/a 3.00 n/a n/a TBD TBD 28-33 n/a n/a n/a n/a n/a n/a n/a n/a n/a FULL PTC- 10 Yrs (end 2011)
Recent press, O&M from Uwe’s latest O & M
Presentation
Wind (<5MW)2010 10 3,000 2 n/a 3.00 n/a n/a TBD TBD 20.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a FULL PTC- 10 Yrs
(end 2011)
Wind (Offshore)2018 100 5,000 95.0 n/a n/a n/a TBD TBD 45.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a FULL PTC- 10 Yrs (end 2011)
PSE Assumption from Wind Developer
Coal (Ultra Critical) 2019 N/A 3,000 8 38.0 8,825 1.30 n/a n/a 100 100 89.2 7 14 50 n/a n/a 8 205 0.12 0.07 No Black & Veatch (O&M), VOM Goldman Sachs, maint based on Colstrip
Coal (IGCC)2022 N/A 3,600 8 41.0 8,130 4.00 n/a n/a 105 95 89.2 7 14 75 n/a n/a 4 205 0.03 0.15 No Black & Veatch (O&M), VOM Goldman Sachs, assumes
extra gasifier
Coal (IGCC w/ Seq) 2025 N/A 5,040 8 50.0 9,595 4.40 n/a n/a 100 100 88.3 7 17 75 n/a n/a 4 20.5 0.003 0.015 No Escalated rates from IGCC based on NPCC for O&M, capital 40% higher than IGCC
Geothermal 2012 4,250 3 75.0 5.00 n/a n/a 110 90 93.4 5 6 n/a n/a n/a n/a 10 n/a n/a FULL PTC- 5 Yrs (End 2011)
Capital Costs per Avg of Kitz & Public Renewable Partners, O&M per GS Study
CCCT Wood Boiler 2012 20 2,500 3 121.0 10,500 6.00 n/a n/a 100 100 90.1 5 18 0 n/a n/a n/a 202 0.025 0.17 HALF PTC- 5 Yrs (End 2011)
Emissions data per Kettle Falls & TD analysis
Wood Gasification Conv.
for CCCT DB 25 n/a n/a 100.0 n/a n/a n/a 202 HALF PTC- 5 Yrs (End 2011)
Wood Gasification
Conversion (KFCT)7 n/a n/a 100.0 n/a n/a n/a 202 HALF PTC- 5 Yrs
(End 2011)
Biomass Open Loop
(landfill,wood,waste,etc)2011 5,000 2 n/a n/a 100 100 92.3 5 10 n/a n/a n/a n/a n/a n/a n/a HALF PTC- 5 Yrs (End 2011)
Black & Veatch (Capital)
Biomass Closed Loop 2017 2 n/a n/a 100 100 92.3 5 10 n/a n/a n/a n/a n/a n/a n/a FULL PTC- 10 Yrs (end 2011)
Solar Photovoltaic 2010 50 7,500 1 32.0 n/a 0.00 n/a n/a 100 20.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a 30% ITC (End 2011)Black & Veatch (Capital), O&M per Goldman Sachs
Study
Solar Thermal 2010 50 4,200 3 65.0 n/a 0.00 n/a n/a 100 30.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a 30% ITC (End 2011)Black & Veatch (Capital) O&M per Goldman Sachs Study
Roof Top Solar 2010 50 8,000 0.5 30.0 n/a 0.00 n/a n/a 100 15.5 n/a n/a n/a n/a n/a n/a n/a n/a n/a 30% ITC (End 2011)Kyocera Website, O&M per Goldman Sachs Study
Nuclear 2022 500 5,500 10 97.0 10,400 0.55 n/a n/a 100 100 87.1 8 18 n/a n/a n/a n/a n/a FULL PTC- 10 Yrs (end 2011)
Reports/Huron Consulting (Capex), Black & Veatch (O&M)
Tidal Power 2018 2 10,000 1.5 1000.0 n/a 0.00 n/a n/a 0 0 30.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a FULL PTC- 10 Yrs (end 2011)
Tidal Power Conference and CC fabricated based on
range from conference
Little Falls 1 Upgrade 2014 1.0 2,600 2 0.0 n/a 0.00 n/a n/a 100 100 61.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs
(end 2011)
Avista Engineering Preliminary Estimate
Little Falls 2 Upgrade 2015 1.0 1,800 2 0.0 n/a 0.00 n/a n/a 100 100 61.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs (end 2011)
Avista Engineering Preliminary Estimate
Little Falls 3 Upgrade 2016 1.0 3,200 2 0.0 n/a 0.00 n/a n/a 100 100 61.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs (end 2011)
Avista Engineering Preliminary Estimate
Little Falls 4 Upgrade 2017 1.0 1,300 2 0.0 n/a 0.00 n/a n/a 100 100 61.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs (end 2011)
Avista Engineering Preliminary Estimate
Post Falls 6 Upgrade 2018 0.2 5,000 2 0.0 n/a 0.00 n/a n/a 100 100 50.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs
(end 2011)
Avista Engineering Preliminary Estimate
Upper Falls Upgrade 2019 2.0 3,500 3 0.0 n/a 0.00 n/a n/a 100 100 90.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs (end 2011)
Avista Engineering Preliminary Estimate
Long Lake 5 Addition 2020 24.0 2,167 5 1.0 n/a 0.00 n/a n/a 100 100 30.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs (end 2011)
Avista Engineering Preliminary Estimate
Long Lake 2nd
Powerhouse 2020 60.0 2,000 6 2.0 n/a 0.00 n/a n/a 100 100 2.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs (end 2011)
Avista Engineering Preliminary Estimate
Cabinet Gorge Unit 5 2016 60.0 1,417 5 2.0 n/a 0.00 n/a n/a 100 100 12.5 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs
(end 2011)
Avista Engineering Preliminary Estimate
Pumped Storage 2020 25 5,000 8 5.0 n/a Off-Peak
Market n/a n/a 100 100 50.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a No Avista Engineering Preliminary Estimate
Hydrokinetics 2014 5 4,000 3 3.0 n/a 0.00 n/a n/a 75.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs (end 2011)
Avista Engineering Preliminary Estimate
Run of River Hydro 2020 N/A 4,500 5 2.0 n/a 0.00 n/a n/a 100 100 30.0 n/a n/a n/a n/a n/a n/a n/a n/a n/a HALF PTC- 10 Yrs (end 2011)
Avista Engineering Preliminary Estimate
DRAFT
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 294 of 729
Scenarios and Futures
John Lyons
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 295 of 729
2
Uses of Scenarios and Futures
Provide details about impacts and size of impacts of different assumptions
ƒAvista’s current load and resource portfolio
ƒPreferred Resource Strategy
ƒWholesale electric market
ƒDifferent resource options
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 296 of 729
3
Market Scenarios
ƒStarts with the Base Case assuming expected conditions
ƒHydro
ƒLoad
ƒGas prices
ƒWind
ƒEmissions prices
ƒForced outages
ƒScenarios study the effects of fundamental changes to a driving
force in the forecast
ƒScenarios have quicker solution times and provide more
understandable results due to the limited change in variables
ƒUsed to test portfolio sensitivities
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 297 of 729
4
Market Futures
ƒA future is a stochastic or random study using Monte Carlo style
analysis for risk quantification
ƒMultiple iterations provide a shape and boundaries to potential
costs
ƒAvista’s modeling process looks 21 years into the future with
several hundred draws of hydro, load, wind, fuel prices,
emissions costs, and thermal forced outage values
ƒFutures can quantitatively assess market risk
ƒUse a large amount of computational power for each future
ƒResults are sometimes difficult to understand because of the
sheer number of variables
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 298 of 729
5
2009 IRP Market Futures
ƒBase Case:uses expected hydro, wind, load, fuel costs, and
emissions costs
ƒUnconstrained Carbon:quantifies CO2 emissions costs
ƒHigh CO2 Costs: higher expected value of CO2 emissions costs
ƒVolatile Fuel: increase natural gas price volatility
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 299 of 729
6
2009 IRP Market Scenarios
ƒHigh and Low Gas Prices: 50% higher and 50% lower prices
ƒCO2 and Natural Gas:different levels of linkage between CO2
and natural gas prices
ƒHigh and Low Load Growth
ƒElectric Car:high penetration of electric cars
ƒConstant Gas Growth: No downward trend in near term gas
prices
ƒUnconstrained Carbon Costs: zero carbon costs
ƒHigh Carbon Costs: significantly higher than the Base Case
ƒNuclear:significant new nuclear in the Western Interconnect
ƒBuck-a-Watt Solar:drastic decrease in photovoltaic solar costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 300 of 729
7
2009 IRP Portfolio Options
ƒEfficient frontier
ƒNo Resource Additions –market reliance
ƒAll CT –with and without green tags
ƒAll CCCT –with and without green tags
ƒFixed Gas –with and without
ƒAll Renewables
ƒWind and CT
ƒNuclear –available in 2020
ƒCoal –available in 2018
ƒ2007 IRP
ƒOthers?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 301 of 729
8
New Scenario Approach
ƒPrevious slides show Avista’s past approach to scenarios and futures
ƒThis approach is difficult to use to adjust our resource strategy
ƒMoving towards a smaller number of scenarios, where each scenario
represents a fundamentally different future with its own assumptions
ƒScenario matrix with the economy and environmental concerns
1. Base Case –center of the matrix
2. Quadrant 1 –Economic Boom and Weak Environmental
3. Quadrant 2 –Economic Boom and Strong Environmental
4. Quadrant 3 –Economic Bust and Weak Environmental
5. Quadrant 4 –Economic Bust and Strong Environmental
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 302 of 729
9
Scenario Matrix – Environmental Regulation and Economics
Weak
Environmental Strong
Environmental
Economic Boom
Economic Bust
Quadrant 1
Quadrant 4
Quadrant 2
Quadrant 3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 303 of 729
10
Potential Scenario Drivers
ƒEconomic –inflation, load, commodities, and market developments
ƒEnvironmental –carbon costs, RPS, and competition for
renewables
ƒPolitical –structure of carbon market
ƒSocial –views of environmental issues and response of customers
to rate pressure
ƒTechnological –help or hindrance, new technologies, and electric
cars
ƒOrganizational –business as usual, new ways of doing things
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 304 of 729
Demand-Side Management
in the 2009 Electric IRP
Jon Powell
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 305 of 729
1
DSM / IRP Objectives
Opportunity to perform a comprehensive overview of
electric resource opportunities and strategy on a
level playing field
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 306 of 729
2
DSM Challenges in the IRP
ƒIRP results must be actionable to be meaningful
ƒThe IRP must provide the basis for continual evaluation of DSM
opportunities between IRP cycles
ƒ“Normal” technical challenges of assessing DSM resources
within the IRP
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 307 of 729
3
How Avista Addresses Challenges
ƒThe biennial high-level IRP process is augmented with an annual
detailed DSM business plan
ƒOur tariffs are reasonably flexible in the short-term; even more
flexible in the long-term
ƒThe IRP avoided cost stream forms the basis for intra-IRP DSM
resource analysis and cost-effectiveness
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 308 of 729
4
Annual DSM Business Plan
ƒEstablishes a corporate budget
ƒAllows for the detailed review of DSM opportunities
ƒConsiders the packaging of measures
ƒEstablishes a high-level program plan for promising measures:
–Infrastructure requirements (labor and non-labor)
–Outreach requirements (brochures, paid and free media, etc)
–Establishes critical trade allies relationships (including potential
regional cooperative efforts)
ƒProgram trigger points are established
ƒPlan for the M&E necessary for program management and external
reporting
ƒCalculate prospective cost-effectiveness (program and portfolio)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 309 of 729
5
DSM Tariffs and Operations
ƒTariffs can, and have, changed to meet resource acquisition needs
ƒDSM operations governed by Schedule 90 and funded by Schedule 91
ƒTariffs allow for the inclusion of any measure into the DSM portfolio
ƒFour basic portfolio’s within Avista’s DSM operations
1. Non-Residential – mix of “site-specific” and prescriptive programs
2. Residential – exclusively prescriptive programs
3. Residential Limited Income – any measure cooperating with CAP agencies
4. Regional – NEEA’s market transformation portfolio
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 310 of 729
6
Avista's Incentive Tiers
0
5
10
15
20
25
0 20 40 60 80 100 120 140 160 180 200
Months Simple Payback
ce
n
t
s
/
1
s
t

y
r

k
W
h
Lighting Non-Lighting
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 311 of 729
7
Electric Avoided Costs
ƒPrice is an efficient means of signaling resource scarcity
ƒAvoided cost composed of:
–Commodity avoided cost ($/kWh)
–Distribution losses ($/kWh)
–Carbon cost ($/kWh)
–Value of risk reduction ($/kWh)
–Generation capacity ($/kW)
–T&D capacity ($/kW)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 312 of 729
Demand-Side Management
in the 2009 Electric IRP
Lori Hermanson
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 313 of 729
1
Integration of DSM into the 2009 IRP
Interactive process that meets regulatory requirements and
produces results for the business planning process.
ƒIdentify commercially available non-residential technologies
and applications
–“Acceptance” or “rejection” within the IRP will not remove
any technology or application from potentially being
included in our non-residential portfolio
–Almost 2,500 measures being evaluated for the 2009 IRP
ƒRe-evaluate existing residential measures and evaluate the
inclusion of additional measures
–May change the menu of qualifying residential measures.
–Nearly 800 measures being evaluated for 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 314 of 729
2
Integration of DSM into the 2009 IRP
ƒInclusion of Limited Income and Non-Residential Site Specific
programs are done by modifying the historical baseline
–Not necessarily limited to modifying baseline for price
elasticity and load growth
ƒImprovements in estimating Site Specific programs
–Identified the largest portion of Site Specific programs and
are trying to make them more generic in nature
–Can process more Non-Residential programs through the
entire IRP process as opposed to modifying a historical base
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 315 of 729
3
Assess market
characteristics & past
program results
Preliminary cost-
effectiveness evaluation
"Red""Yellow""Green"Terminate
Specify as "must
take" for PRiSM
Characterize for
interactive
evaluation within
AURORA/PRiSM
Yellow - fail Yellow - Pass
Review existing
DSM business
plan
Additional analysis
of programs as
necessary
Development of a
revised DSM business
plan
Initiate new programs.
Continue, modify or terminate
existing programs per
business plan
Develop energy savings,
system coincident peak,
load shapes, NEB's,
measure lives
Develop cost
characteristics
Identify
potential
measures
Develop technical
and economic
potential
DSM
acquisition
goal
Business Plan
acquisition
goal
Outside of the Scope of the Integrated Resource Planning Process
Represented within the Integrated Resource Planning Process
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 316 of 729
4
Categories of Savings and Benefits
ƒObtain savings, system coincident peak savings, incremental
customer cost, non-energy benefits and life of each measure
–Used to calculate a levelized sub-TRC cost
–Sorted based on results into “reds,” “yellows” and “greens”
–Band of “yellow” energy only measures to be tested in
AURORA is projected to be $70-150/MWh
–PRiSM automatically selects “greens”
–Remainder of need is selected from passing “yellows”
–Establishes the 2009 DSM acquisition goal
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 317 of 729
5
Integration of DSM into the 2009 IRP
ƒLast year was the first focus on deferring summer space
cooling-driven load
–Load profiles were assigned to each measure
–Measures categorized by impact to cooling load
•Zero impact – measures received no additional value
regardless of their load profile
•Non-Drivers – measures unrelated to space cooling but
contribute to system load during a cooling-driven peak
receive a capacity value based upon the average demand
of their specific load profile during peak periods
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 318 of 729
6
Space Cooling
ƒDrivers – measures that drive a space cooling peak received a
capacity valuation based upon the maximum hourly demand for
that load profile
ƒImproving method of addressing the space cooling driven peak
–Using the Council’s system coincident peak estimates
–Measures with capacity savings will be tested in PRiSM
against the avoided costs inclusive of risk and capacity
–PRiSM will select measures and they will be incorporated
into the final DSM acquisition goal
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 319 of 729
7
Incorporating DSM in the 2009 IRP
Integration by Price Signal
AURORA
Resource
Stacks
WECC
Supply-side
Resources
+
DSM Energy Only
Supply Curves
Deferrable
Resource
Avoided Cost
DSM
Department
Acquires
Resource
Decrement
Deferrable
Resource by
Amount of DSM
PRiSM Adds
Risk
and Capacity
DSM with
Capacity
Savings
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 320 of 729
8
What Works – What Doesn’t
ƒDSM is acquired in small annual amounts relative to the
overall load requirement
–“Snowballing” effect over time
ƒHistorically Avista’s DSM has been non-dispatchable
–Demand Response pilot
–When enough data is available, modifications to this
existing process may need to be made to accommodate
demand response technologies and applications
ƒAllows continuous modification and testing of new
opportunities between IRPs in a consistent manner
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 321 of 729

Avista’s 2009 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 3 Agenda
October 22, 2008

Topic Time Staff

1. Introduction 10:30 Vermillion

2. Load Forecast 10:35 Barcus

3. Lunch 11:45

4. Natural Gas Price Forecast 12:30 Rahn

5. Electric Price Forecast 1:30 Gall

6. Legislative Update 2:30 Sprague

7. Adjourn 3:30

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 322 of 729
F2009 Sales and Load Forecast
July 21, 2008 Operations Council Meeting
Randy Barcus
Edited for 2009 Electric Integrated Resource Plan
Third Technical Advisory Committee Meeting
October 22, 2008
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 323 of 729
Summary of Results
Electricity Sales Forecast
ƒ2009 Forecast 9,138 million kWh
ƒ2009 in F2008 9,134 million kWh
ƒ5 Year Growth Rate 2009-2014 +1.8%
ƒ10 Year Growth Rate 2009-2019 +1.7%
ƒ20 Year Growth Rate 2009-2029 +1.7%
ƒLast Year 20 Yr. GR 2009-2029 +1.8%
Natural Gas Firm Sales Forecast
ƒ2009 Firm Forecast 338.5 million therms
ƒ2009 in F2008 352.0 million therms
ƒ5 Year Growth Rate 2009-2014
- Washington -0.2%
- Idaho +1.0%
- Oregon +0.8%
- System +0.3%
ƒ10 Year GR System +0.9%
ƒ20 Year GR System +1.3%
ƒ20 Year Customer GR +2.5%
2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 324 of 729
Significant Assumptions
Economy—slower growth in
near term, returns to trend
ƒTight credit, housing bubble, but strong commodity prices for agriculture and metals
ƒRegional economy returns to long term trend in 2012
Avista Retail Prices
ƒElectric prices increase 10% in 2009 and thereafter until 2015, and at inflation plus real income growth thereafter
ƒNatural gas prices increase 20% in 2009 and 10% thereafter until 2015, and at inflation plus real income growth thereafter
ƒCarbon taxes are included in the 2012-2015 price increases
Global Warming Degree Days
ƒ2009 Heating and Cooling at NOAA Normal (1971-2000 avg.)
ƒ2010-2019 ramps to trend, 2020-2029 on trend
3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 325 of 729
3a
http://www.cpc.ncep.noaa.gov/products/predictions//multi_season/13_seasonal_outlooks/color/churchill.php
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 326 of 729
Winter will be much colder and drier than normal, on average, with
snowfall above normal in the north and below normal in the south. The
coldest temperatures will occur in late December; early, mid-, and late
January; and early February. The snowiest periods will be in mid-
November, early and mid-December, mid- and late January, and late
February.
April and May will be cooler than normal, with slightly above-normal
precipitation.
Summer will be cooler than normal, with slightly above-normal rainfall.
The hottest periods will be in mid- and late June and early and mid- to
late July.
September and October will be warmer and drier than normal.
Intermountain
Annual Weather Summary
November 2008 to October 2009
3b
http://www.almanac.com/weatherforecast/us/13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 327 of 729
Other Assumptions
ƒDSM and Conservation—included in forecast at new levels
ƒMulti-Family Natural Gas—assuming successful penetration
ƒInland Empire Paper—12 average MW added load in 2010
ƒMining Loads—continued high silver prices lead to modest growth
ƒLumber Loads—low levels through 2009, some bounce in 2010
ƒPlug-In Hybrid Cars—included in forecast
ƒOther implicit assumptions
ƒHousing mix 40% single family, 30% condo/townhome, 30% multifamily rentalƒAverage new construction size is 30% larger than present averageƒGrowing plug loads (largely digital TV’s) offset Energy Star savings
ƒThe Energy Independence and Security Act of 2007 contains provisions that significantly impact electricity use, particularly residential
lighting usage, over the next 5 to 10 years. The key lighting-related provisions that related to energy forecasters are:
– Incandescent Light Bulb Standard. Requires roughly 25 percent greater efficiency for light bulbs, phased in from 2012 through
2014. This effectively bans the sale of most current incandescent light bulbs. The initial targets will be met by advanced
incandescent lamps, which the major manufacturers are just introducing to the market, using halogen capsules with infrared
reflective coatings. The longer-term targets will likely be met by compact fluorescent lamps and other advanced technologies,
such as light emitting diodes and very advanced incandescent lamps now in development.
– Lighting Efficiency Standard. Requires a minimum 45 lumens/watt efficiency standard for general service lamps by 2020.
– Federal Building Lighting Standard. Requires that all lighting in Federal buildings use Energy Star products.
ƒThe Energy Information Administration’s 2008 Annual Energy Outlook (AEO) forecast provides insight into the impact that these
provisions will have on residential lighting use. The 2008 Residential AEO forecast projects that lighting’s share of total residential
electricity usage will drop from 14.4% in 2011, the year before the incandescent light bulb standard takes place, to 10.7% in 2016. Over
this five year period, lighting’s share of electricity usage is projected to drop by approximately 25%.
ƒThe long-run effect of the lighting standards on residential electricity usage is to decrease residential lighting share of usage to 8.3% by
2030, a reduction of over 40% from its 2011 level of 14.4%.
4
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 328 of 729
2008 Forecast Residential New Construction
Kootenai & Spokane County Combined
3,520 3,4433,266
6,082
4,710
3,763
5,
6
0
0
5,
4
0
0
5,
6
0
0
5,
7
0
0
6,
1
0
0
2,
7
0
0
2,
9
0
0
4,
5
0
0
5,
2
0
0
5,
7
0
0
6,
0
0
0
6,
1
0
0
6,
2
0
0
6,
2
0
0
6,
2
0
0
6,
2
0
0
6,
1
0
0
6,
0
0
0
3,585
3,501
2,472
2,768
2,800
4,282
5,617
5,
4
0
0
6,
0
0
0
6,
1
0
0
5,
6
0
0
5,
0
0
0
4,
7
1
0
6,
0
0
0
5,
5
0
0
6,
0
0
0
6,
2
0
0
2,000
2,500
3,000
3,500
4,000
4,500
5,000
5,500
6,000
6,500
7,000
7,500
8,000
8,500
19
9
5
19
9
6
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
Re
s
i
d
e
n
t
i
a
l

B
u
i
l
d
i
n
g

P
e
r
m
i
t
s
Actual 2007 Forecast 2008r Forecast
5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 329 of 729
Spokane NWS Global Warming Degree Day Trends
2007-2038
95
.
2
%
95
.
0
%
94
.
7
%
94
.
4
%
94
.
1
%
93
.
9
%
93
.
6
%
93
.
3
%
93
.
1
%
92
.
8
%
92
.
5
%
92
.
2
%
92
.
0
%
91
.
7
%
91
.
4
%
91
.
1
%
90
.
9
%
90
.
6
%
90
.
3
%
90
.
1
%
89
.
8
%
89
.
5
%
89
.
2
%
89
.
0
%
88
.
7
%
88
.
4
%
88
.
1
%
87
.
9
%
87
.
6
%
87
.
3
%
87
.
1
%
86
.
8
%
10
9
.
5
%
11
0
.
8
%
11
2
.
0
%
11
3
.
3
%
11
4
.
6
%
11
5
.
8
%
11
7
.
1
%
11
8
.
3
%
11
9
.
6
%
12
0
.
9
%
12
2
.
1
%
12
3
.
4
%
12
4
.
6
%
12
5
.
9
%
12
7
.
2
%
12
8
.
4
%
12
9
.
7
%
13
0
.
9
%
13
2
.
2
%
13
3
.
5
%
13
4
.
7
%
13
6
.
0
%
13
7
.
2
%
13
8
.
5
%
13
9
.
8
%
14
1
.
0
%
14
2
.
3
%
14
3
.
5
%
14
4
.
8
%
14
6
.
1
%
14
7
.
3
%
14
8
.
6
%
80%
100%
120%
140%
160%
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
Heating Degree Days Cooling Degree Days
6
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 330 of 729
7
Electric Average Use per Average Customer
y = -42x + 12175
y = 183x + 79577
9,000
10,000
11,000
12,000
13,000
14,000
15,000
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
An
n
u
a
l

k
W
h

R
e
s
i
d
e
n
t
i
a
l
40,000
50,000
60,000
70,000
80,000
90,000
100,000
An
n
u
a
l

k
W
h

C
o
m
m
e
r
c
i
a
l
Residential Commercial Linear (Residential)Linear (Commercial)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 331 of 729
Global Warming Impact
Normal minus Warming HDD and CDD
(4,500,000)
(3,500,000)
(2,500,000)
(1,500,000)
(500,000)
500,000
1,500,000
Ja
n
-
0
9
Ma
r
-
0
9
Ma
y
-
0
9
Ju
l
-
0
9
Se
p
-
0
9
No
v
-
0
9
Ja
n
-
1
0
Ma
r
-
1
0
Ma
y
-
1
0
Ju
l
-
1
0
Se
p
-
1
0
No
v
-
1
0
Ja
n
-
1
1
Ma
r
-
1
1
Ma
y
-
1
1
Ju
l
-
1
1
Se
p
-
1
1
No
v
-
1
1
kW
h
Residential Commercial Industrial System Total
8
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 332 of 729
MW Difference
Normal minus Warming HDD & CDD0.0
-0.6
-1.9
-2.7
-3.5
-4.3
-5.2
-6.1
-7.0
-7.9
-8.9 -9.3 -9.8 -10.3
-10.7
-11.2
-11.7
-12.3
-12.8
-13.3
-13.8
-14.4
-16.0
-14.0
-12.0
-10.0
-8.0
-6.0
-4.0
-2.0
0.0
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
Av
e
r
a
g
e

M
W
9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 333 of 729
Electric Sales Forecast Base w/ GW vs. Normal Weather
7,000,000,000
8,000,000,000
9,000,000,000
10,000,000,000
11,000,000,000
12,000,000,000
13,000,000,000
14,000,000,000
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
an
n
u
a
l

k
W
h
Electric Base Electric Normal
Compound Growth Rates
2009-2029 Base 1.68%
2009-2029 Normal 1.73%
Reduction in avg MW
2019 9
2029 14
10
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 334 of 729
11
Avista Residential by Schedule
Therm Use Per Customer
400
500
600
700
800
900
1,000
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
An
n
u
a
l

T
h
e
r
m
s
WN WA Res
Sch 101 UPC
WN ID Res
Sch 101 UPC
Oregon
Residential
UPC
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 335 of 729
WA-ID & Oregon Natural Gas Base w/GW vs. Normal Weather
50,000,000
100,000,000
150,000,000
200,000,000
250,000,000
300,000,000
350,000,000
400,000,000
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
an
n
u
a
l

t
h
e
r
m
s
WA-ID Total Base WA-ID Total Normal Oregon Firm Base Oregon Firm Normal
Compound Growth Rates
2009-2029 Base 1.18%
2009-2029 Normal 1.83%
Compound Growth Rates
2009-2029 Base 1.67%
2009-2029 Normal 2.15%
13
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 336 of 729
Avista Electric Service Area Plug-In Hybrid Car Sales Forecast
12
Market
Share
Hybrid
Vehicles
Served
Incremental
Sales of
Hybrid
Vehicles
kWh Energy
Consumption
Average
MW
Base Case
Residential
Sales Forecast
Cumulative
Percent
Boost to
Residential
Residential
Sales with
Hybrid
Vehicles
2010 3.5% 1,000 1,000 2,500,000 0.3 3,761,638,997 0.1% 3,764,138,997
2011 6.0% 2,000 1,000 5,000,000 0.6 3,788,118,462 0.1% 3,793,118,462
2012 8.5% 3,500 1,500 8,750,000 1.0 3,842,900,187 0.2% 3,851,650,187
2013 11.0% 5,500 2,000 13,750,000 1.6 3,893,034,524 0.4% 3,906,784,524
2014 14.0% 8,000 2,500 20,000,000 2.3 3,941,757,508 0.5% 3,961,757,508
2015 18.0% 11,000 3,000 27,500,000 3.1 3,988,061,420 0.7% 4,015,561,420
2016 24.0% 15,000 4,000 37,500,000 4.3 4,034,409,825 0.9% 4,071,909,825
2017 26.0% 20,000 5,000 50,000,000 5.7 4,079,468,146 1.2% 4,129,468,146
2018 26.0% 25,000 5,000 62,500,000 7.1 4,123,323,408 1.5% 4,185,823,408
2019 26.0% 30,000 5,000 75,000,000 8.6 4,167,601,524 1.8% 4,242,601,524
2020 26.0% 35,000 5,000 87,500,000 10.0 4,215,588,573 2.1% 4,303,088,573
2021 26.0% 40,000 5,000 100,000,000 11.4 4,261,378,267 2.3% 4,361,378,267
2022 26.0% 45,000 5,000 112,500,000 12.8 4,306,622,849 2.6% 4,419,122,849
2023 26.0% 50,000 5,000 125,000,000 14.3 4,351,888,063 2.9% 4,476,888,063
2024 26.0% 55,000 5,000 137,500,000 15.7 4,396,064,205 3.1% 4,533,564,205
2025 26.0% 60,000 5,000 150,000,000 17.1 4,439,711,711 3.4% 4,589,711,711
2026 26.0% 65,000 5,000 162,500,000 18.6 4,481,771,729 3.6% 4,644,271,729
2027 26.0% 70,000 5,000 175,000,000 20.0 4,523,907,789 3.9% 4,698,907,789
2028 26.0% 75,000 5,000 187,500,000 21.4 4,564,967,067 4.1% 4,752,467,067
2029 26.0% 80,000 5,000 200,000,000 22.8 4,605,531,184 4.3% 4,805,531,184
2030 26.0% 85,000 5,000 212,500,000 24.3 4,645,605,390 4.6% 4,858,105,390
2,500 kWh per car 80% WA 20% ID 2010-2030 CGR 1.06%1.28%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 337 of 729
14
2009 ELECTRIC RETAIL SALES FORECAST
0
1,000,000,000
2,000,000,000
3,000,000,000
4,000,000,000
5,000,000,000
6,000,000,000
7,000,000,000
8,000,000,000
9,000,000,000
10,000,000,000
11,000,000,000
12,000,000,000
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
calendar year
Potlatch
Generation
Street
Lights
Industrial
Commercial
Residential
2009-2019 growth rate = 1.75%, 2009-2029 growth rate =1.68%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 338 of 729
15
Load Growth Comparisons
(plug-in hybrid car consumption is included)
5,000,000,000
6,000,000,000
7,000,000,000
8,000,000,000
9,000,000,000
10,000,000,000
11,000,000,000
12,000,000,000
13,000,000,000
14,000,000,000
15,000,000,000
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
F2009 F2008 F2007 F2006
Growth Rates 2005-2025
F2006 2.36%
F2007 2.14%
F2008 1.85%
F2009 1.72%
Growth Rates 2009-2029
F2006 n/a
F2007 1.83%
F2008 1.83%
F2009 1.68%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 339 of 729
16
Net Native Load
with Potlatch, with Electric Cars
900
1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
19
9
7
19
9
9
20
0
1
20
0
3
20
0
5
20
0
7
20
0
9
20
1
1
20
1
3
20
1
5
20
1
7
20
1
9
20
2
1
20
2
3
20
2
5
20
2
7
20
2
9
Av
e
r
a
g
e

M
W

i
n
c
l
u
d
i
n
g

l
o
s
s
e
s
F2009 F2008 F2007IRP F2006 F2005 F2004
F2009 929 954 989 1,013 965 995 1,013 1,021 1,046 1,069 1,088 1,113 1,119 1,148 1,171 1,188 1,202 1,222 1,252 1,270 1,289 1,311 1,329 1,347 1,367 1,386 1,405 1,428 1,452 1,491 1,511 1,533 1,553 1,573
F2008 1,087 1,104 1,118 1,141 1,161 1,182 1,202 1,229 1,274 1,299 1,316 1,333 1,356 1,376 1,401 1,416 1,434 1,466 1,489 1,541 1,556 1,577 1,604 1,627
F2007IRP 1,091 1,124 1,163 1,196 1,229 1,255 1,274 1,306 1,325 1,358 1,379 1,399 1,426 1,449 1,477 1,497 1,518 1,556 1,582 1,606 1,626 1,646 1,674 1,699
F2006 1,043 1,086 1,122 1,159 1,198 1,232 1,270 1,299 1,327 1,360 1,388 1,417 1,440 1,461 1,491 1,516 1,545 1,566 1,590 1,619 1,643
F2005 1,029 1,067 1,099 1,122 1,152 1,185 1,215 1,246 1,270 1,296 1,323 1,354 1,379 1,395 1,417 1,447 1,472 1,499 1,517 1,549 1,577 1,605
F2004 1,000 1,035 1,061 1,085 1,109 1,135 1,164 1,196 1,225 1,247 1,270 1,293 1,327 1,356 1,384 1,412 1,444 1,474 1,509 1,546 1,585 1,625 1,667
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Forecast 2009-2019
Actual 1997-2007
2008 is 6 months actual, 6 months forecast
Growth Rates
5 yr=1.8%, 10 yr=1.8%, 20 yr=1.7%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 340 of 729
17
Calendar Year, January & July Peak Demands
Megawatts
1,000
1,200
1,400
1,600
1,800
2,000
2,200
2,400
2,600
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
Jan 1,508 1,575 1,357 1,458 1,474 1,388 1,393 1,766 1,563 1,475 1,685 1,705 1,739 1,779 1,812 1,839 1,862 1,893 1,937 1,967 1,998 2,033 2,062 2,091 2,124 2,154 2,185 2,222 2,261 2,320 2,352 2,387 2,419 2,452
Jul 1,202 1,521 1,405 1,454 1,382 1,457 1,487 1,477 1,495 1,642 1,629 1,619 1,628 1,667 1,699 1,720 1,737 1,761 1,796 1,818 1,842 1,867 1,889 1,912 1,936 1,959 1,982 2,010 2,039 2,085 2,109 2,135 2,160 2,185
Calendar 1,508 1,663 1,434 1,561 1,490 1,457 1,509 1,766 1,660 1,656 1,685 1,733
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
Actual 1997-2007+
Forecast 2009-2019
Growth rates
5 yr=1.7%, 10 yr=1.7%, 20yr=1.7%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 341 of 729
Peak Load Planning
•Winter based on average coldest day
•Summer based on average hottest day
Data from 1890 to 2007 Temp HDD
Average Coldest Day (December & January)11.7 53.3
Standard Deviation 10.2
5% chance of exceedance 1.645 16.779 -5.1 70.1
1% chance of exceedance 2.330 23.766 -12.1 77.1
0.25% chance of exceedance 2.814 28.7 -17.0 82.0
Data from 1890 to 2007 Temp CDD
Average Hottest Day (July & August)80.0 15.0
Standard Deviation 3.405
5% chance of exceedance 1.645 5.601 85.6 20.6
1% chance of exceedance 2.330 7.933 87.9 22.9
0.16% chance of exceedance 2.950 10.0 90.0 25.0
18
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 342 of 729
19
Peak Demand Trends
Actual Monthly Peaks through June 2008
1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
2,100
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 343 of 729
Questions & Answers
20
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 344 of 729
Natural Gas Price Forecast
Greg Rahn, Manager Natural Gas Planning
James Gall, Senior Power Supply Analyst
2009 Electric Integrated Resource Plan
Third Technical Advisory Committee Meeting
October 22, 2008
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 345 of 729
2
US Supply Growth Forecast through 2015
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 346 of 729
3
Source: Wood Mackenzie
Generation Forecasted to Lead National Demand for Natural Gas
ActualActual
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 347 of 729
4
Regional Natural Gas Demand Forecast
Source: Northwest Gas Association
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 348 of 729
5
Interstate Pipeline Flow
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 349 of 729
6
Shale Gas Plays
Source: Wood Mackenzie
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 350 of 729
7
Henry Hub Short Term Price Forecasts
$3.00
$5.00
$7.00
$9.00
$11.00
$13.00
$15.00
Ja
n
-
0
8
Ma
r
-
0
8
Ma
y
-
0
8
Ju
l
-
0
8
Se
p
-
0
8
No
v
-
0
8
Ja
n
-
0
9
Ma
r
-
0
9
Ma
y
-
0
9
Ju
l
-
0
9
Se
p
-
0
9
No
v
-
0
9
Ja
n
-
1
0
Ma
r
-
1
0
Ma
y
-
1
0
Ju
l
-
1
0
Se
p
-
1
0
No
v
-
1
0
Ja
n
-
1
1
Ma
r
-
1
1
Ma
y
-
1
1
Ju
l
-
1
1
Se
p
-
1
1
No
v
-
1
1
$/
D
e
k
a
t
h
e
r
m
Wood Mackenzie 9/22/2008 Consultant 9/22/2008 NYMEX 9/30/2008 EIA 9/10/2008
Actuals
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 351 of 729
8
Forecast Assumptions
2021Alaska Pipeline
12.208.401.28LNG Imports (bcf\d)
55.2157.3656.82US Gas Prod. (bcf\d)
$ 68.17 $ 60.40 $ 72.25 WTI Oil Price (2008$)
26.4122.8819.33EG Demand (bcf\d)
70.6768.4464.85US Gas Demand (bcf/d)
2.73%2.84%2.55%US Economic Growth (% GDP)
202020152009
Source: Wood Mackenzie
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 352 of 729
9
Annual Gas Price Forecast (Henry Hub)
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
$16.00
$18.00
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
2009 Nominal 2009 Real 2007 Nominal 2007 Real
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 353 of 729
10
Basin Differentials as a % of Henry Hub*
97.9%
100.8%
98.6%
98.3%
96.7%
88.9%
100.8%So Cal
97.9%San Juan
88.9%Opal
98.6%Malin
98.3%Sumas
96.7%AECO
100.0%Henry Hub
%Location
* Based on forecasted 20 year levelized
nominal prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 354 of 729
11
Monthly Gas Shape*
98%Jul103%Jan
105%Dec98%Jun
104%Nov97%May
100%Oct96%Apr
99%Sep97%Mar
99%Aug104%Feb
% of AnnualMonth% of AnnualMonth
* Based on 5 year average of monthly differentials to annual average (AECO)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 355 of 729
12
-10.0%
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
Pe
r
c
e
n
t

I
n
c
r
e
a
s
e

I
n

N
G

P
r
i
c
e
s
-$25
$0
$25
$50
$75
$100
$125
Ca
r
b
o
n

P
r
i
c
e

p
e
r

T
o
n

(
2
0
0
8
$
)
Bingaman Proposal NG Change Lieberman-Warner NG Change
Bingaman Proposal CO2 Price Lieberman-Warner CO2 Price
Wood Mackenzie Green House Gas Scenarios
New Technology
(Nuclear/Sequestration)
Lowers Demand for
Natural Gas
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 356 of 729
13
Carbon Cost & LT Natural Gas Prices Relationship
2012-2021 CO2 & NG Prices
y = 0.0028x - 0.0121
R2 = 0.9755
0%
5%
10%
15%
20%
25%
30%
35%
$-$20 $40 $60 $80 $100 $120
CO2 Price (2008$ per metric ton)
%
C
h
a
n
g
e

t
o

H
H

g
a
s

p
r
i
c
e
s
For every $10 of CO2 Cost
= +2.8% Increase in
Natural Gas Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 357 of 729
14
Carbon Impact to Natural Gas Conclusion
ƒCarbon Legislation will increase natural gas demand and price.
ƒTo meet a national 1990 Carbon Emissions levels; gas prices
could be 30% higher than without Carbon Legislation, unless
new technology (Nuclear or Carbon Sequestration) is available
in high supply.
ƒ’09 IRP will use the discussed relationship to develop the Base
Case natural gas price forecast, until 2025 (first year
sequestration is available to the market), post 2025 prices
differentials will flatten.
ƒIncreases to natural gas prices will allow existing coal resources
to compete with natural gas at higher Carbon cost levels (see
Price Forecast Presentation)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 358 of 729
15
Levelized Natural Gas Costs ($/Dth)*
$9.75$9.11$11.71$10.94Henry Hub
w/CO2WMw/CO2WM
$9.82$9.18$11.80$11.02Southern Cal
$9.56$8.92$11.48$10.71San Juan
$8.74$8.10$10.49$9.72Opal
$9.62$8.98$11.56$10.79Malin
$9.60$8.96$11.53$10.76Sumas
$9.45$8.81$11.35$10.58AECO
Real (2008$)NominalLocation
* Levelized 20 Years (2010-2029)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 359 of 729
Mid-Columbia Electric Market
Forecast
James Gall
2009 Electric Integrated Resource Plan
Third Technical Advisory Committee Meeting
October 22, 2008
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 360 of 729
2
Why Is This Forecast Relevant?
ƒUsed to value future energy costs
ƒUsed to determine resources financial value given
different market conditions
ƒForecasts when and under what conditions a
resource is likely to dispatch
ƒTest regional market conditions and policies
ƒTime for changes- recommendations are welcome!
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 361 of 729
3
Historical Mid-Columbia Market Prices
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
Ja
n
-
9
7
Ja
n
-
9
8
Ja
n
-
9
9
Ja
n
-
0
0
Ja
n
-
0
1
Ja
n
-
0
2
Ja
n
-
0
3
Ja
n
-
0
4
Ja
n
-
0
5
Ja
n
-
0
6
Ja
n
-
0
7
Ja
n
-
0
8
$/
M
W
h
1997
13.78/
MWh
1999
23.31/
MWh
2000
121.01/
MWh
2001
129.05/
MWh
2002
22.42/
MWh
2003
38.06/
MWh
2005
58.64/
MWh
1998
23.22/
MWh
2006
45.55/
MWh
2007
51.48/
MWh
2004
42.41/
MWh
2008
52.82/
MWh
$525 Dec 2000
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 362 of 729
4
Historical Market Implied Heat Rate
-
2,000
4,000
6,000
8,000
10,000
12,000
14,000
1/
1
/
2
0
0
4
4/
1
/
2
0
0
4
7/
1
/
2
0
0
4
10
/
1
/
2
0
0
4
1/
1
/
2
0
0
5
4/
1
/
2
0
0
5
7/
1
/
2
0
0
5
10
/
1
/
2
0
0
5
1/
1
/
2
0
0
6
4/
1
/
2
0
0
6
7/
1
/
2
0
0
6
10
/
1
/
2
0
0
6
1/
1
/
2
0
0
7
4/
1
/
2
0
0
7
7/
1
/
2
0
0
7
10
/
1
/
2
0
0
7
1/
1
/
2
0
0
8
4/
1
/
2
0
0
8
7/
1
/
2
0
0
8
Bt
u
/
k
W
h
Mid C Daily Firm/Stanfield Prices x 1000
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 363 of 729
5
Historical Market Implied Heat Rate
-
2,000
4,000
6,000
8,000
10,000
12,000
1 2 3 4 5 6 7 8 9 10 11 12
An
n
u
a
l
Bt
u
/
k
W
h
2004 2005 2006 2007 2008
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 364 of 729
6
Regional Demand (20 Year AAGR)
ƒSource: Wood Mackenzie
-NW- 0.84%
-DSW- 2.09%
-CA- 1.61%
-RM- 1.78%
-UT- 2.19% (PAC IRP)
ƒWill evaluate using NPCC after GRAC meeting
ƒEvaluate NW IRP Forecasts
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 365 of 729
7
RPS Assumptions (Nameplate Capacity)
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Na
m
e
p
l
a
t
e

(
M
W
)
Solar
Hydro
Geothermal
Biomass
Wind
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 366 of 729
8
RPS Assumptions (Energy)
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
50,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
En
e
r
g
y

(
a
M
W
)
Solar
Hydro
Geothermal
Biomass
Wind
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 367 of 729
9
New Transmission Assumptions
3,000
600
1,500 3,000
1,500
1,500
1,500
3,000
500
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 368 of 729
10
Regional Resource Options
(First Year Available)
ƒCombined Cycle Combustion Turbine (2011)
ƒSingle Cycle Combustion Turbine (2010)
ƒWind (2010)
ƒSolar (2010)
ƒPulverized Coal (2015)
ƒIGCC Coal (2015)
ƒIGCC Coal w/ Sequestration (2025)
ƒCombine Cycle Combustion Turbine w/ Sequestration (2025)
ƒNuclear (2022)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 369 of 729
11
Carbon Adder
$-
$10
$20
$30
$40
$50
$60
$70
$80
$90
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
$/
T
o
n
Nominal
Real (2008$)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 370 of 729
12
New Resources by Type in the WECC
Retired 1,300 MW of High Heat Rate Natural Gas Plants between 2011-2013
0
10,000
20,000
30,000
40,000
50,000
60,000
70,000
80,000
90,000
100,000
110,000
120,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW

(
N
a
m
e
p
l
a
t
e
)
Wind SolarGeothermalBiomassHydroCCCTSCCTPulverized CoalIGCC Coal
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 371 of 729
13
Western Interconnect System Costs
(Nominal -Excludes Carbon Trading Costs)
-
20,000
40,000
60,000
80,000
100,000
120,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Mi
l
l
i
o
n
s
Other New Resources (Cap + O&M)
New Resource per RPS (Cap + O&M)
Variable O&M
Fuel Cost
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 372 of 729
14
Resource Dispatch Contribution
-
20,000
40,000
60,000
80,000
100,000
120,000
140,000
160,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
aM
W
Hydro Coal Nuclear Geothermal Wind
Solar Gas Gas Peakers Gas Seq IGCC Coal
IGCC Coal Seq Oil Other Renewable
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 373 of 729
15
Greenhouse Gas Forecast- US Western Interconnect
200
220
240
260
280
300
320
340
360
380
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
WE
C
C
-
U
S

M
i
l
l
i
o
n
s

S
h
o
r
t

To
n
s
IRP Forecast
1990 Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 374 of 729
16
Greenhouse Gas Forecast
U.S. Western Interconnect
CA
14%
TX
0%
UT
12%
SD
0%
OR
3%NV
5%ID
0%
WA
4%
WY
15%
NM
8%MT
6%
CO
15%
AZ
18%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 375 of 729
17
Greenhouse Gas Forecast- WA/OR/ID
-
5
10
15
20
25
30
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
WE
C
C
-
U
S

M
i
l
l
i
o
n
s

S
h
o
r
t

To
n
s
Northwest Forecast
Northwest 1990
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 376 of 729
18
Carbon Adder High Enough, 2020 Example?
Carbon Price to Remove Existing Coal
2020 Example
0
50
100
150
200
250
0 10 20 30 40 50 60 70 80 90
10
0
11
0
12
0
13
0
14
0
15
0
16
0
17
0
18
0
19
0
20
0
CO2 Cost per Short Ton ($)
$
p
e
r

M
W
h
Coal
CCCT- IRP
CCCT- $4 NG
CCCT- $6 NG
CCCT- $8 NG
$133
$70
$42
$14
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 377 of 729
19
Carbon Price to Remove Existing Coal
2020 Example
0
50
100
150
200
250
0 10 20 30 40 50 60 70 80 90
10
0
11
0
12
0
13
0
14
0
15
0
16
0
17
0
18
0
19
0
20
0
CO2 Cost per Short Ton ($)
$
p
e
r

M
W
h
Coal
CCCT- IRP
CCCT- IRP-No CO2 Adder
How about a Coal Carbon “adder” Instead
$133
$75
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 378 of 729
20
Greenhouse Gas Forecast- US Western Interconnect
250
270
290
310
330
350
370
390
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Mi
l
l
i
o
n
s

o
f

C
O
2

S
h
o
r
t

To
n
s
CO2 Adder to all Resources
CO2 Adder only to Coal/Oil Resources
1990 CO2 Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 379 of 729
21
Market Implied Heat Rates
(Mid-C/Stanfield)
5,000
6,000
7,000
8,000
9,000
10,000
11,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Bt
u
/
k
W
H
Mid-Columbia/Stanfield Mid-Columbia (adj)/Stanfield
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 380 of 729
22
Annual On-Off Peak Mid-Columbia Prices
$-
$50
$100
$150
$200
$250
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$/
M
W
h
Average
Off-Peak
On-Peak
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 381 of 729
23
Mid-Columbia Prices would be lower if not for Carbon Costs
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$/
M
W
h
Average
Avg Price Adjust for CO2
$99.84
$81.36
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 382 of 729
24
Mid-Columbia Levelized Prices ($/MWh)
2010-2029
72.1391.4183.1520-Year (2008$)
86.60109.7799.8420-Year (Nominal)
Off-PeakOn-PeakAverage
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 383 of 729
Legislative Update
Collins Sprague
2009 Electric Integrated Resource Plan
Third Technical Advisory Committee Meeting
October 22, 2007
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 384 of 729
2
Western Climate Initiative
ƒRegional cap and trade implementation
ƒElectricity sector obligations
ƒCost containment mechanisms
ƒAllowances
ƒMarket regulation and enforcement
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 385 of 729
3
Feed-In Tariff
ƒSolar – Renewable Rate Recovery and Control Act
ƒAnaerobic Digester ($0.12/kWh), landfill gas
($0.08/kWh), and “organic” combined heat and power
($0.09/kWh)
- Will not qualify for utility compliance with I-937
ƒRenewable energy credit (public utility tax) for solar
expanded to include other technologies
ƒWheeling requirement for output from digesters
- Transmission cost capped at 5%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 386 of 729
4
Energy Efficiency
ƒExisting, new and renovated buildings
ƒUpdate Energy Code to achieve 30% reduction from
current edition
ƒ“State Building Efficiency and Carbon Reduction
Strategy” – targets for building energy use intensity
ƒEnergy benchmark disclosure requirement at time of
structure sale
ƒPartial public utility credit for non-residential energy
performance
ƒExpansion of Local Improvement Districts to finance
energy efficiency and district heating/cooling
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 387 of 729
5
Other Topics
ƒTax incentives
- Broad tax incentives for combined heat and
power, distributed generation, and water systems
- Renewable energy tax incentives for large-scale
generation
ƒ“Product Stewardship” – collection and recycling of
incandescent lighting by manufacturers
ƒVegetation Management
ƒEmissions Performance standard revisions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 388 of 729

Avista’s 2009 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
January 28, 2009

Topic Time Staff
1. Introduction 9:30 Storro
2. 2008 Peak Load Event 9:35 Heath
3. Natural Gas & Electric Price Update 10:00 Rahn / Gall

4. Lunch 11:30

5. Resource Assumptions 12:30 Lyons

6. Transmission 1:00 Gibson

7. Draft Preferred Resource Strategy 2:00 Gall

8. Adjourn 3:00

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 389 of 729
2008 Peak Load Event
Heidi Heath
2009 Electric Integrated Resource Plan
Fourth Technical Advisory Committee Meeting
January 28, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 390 of 729
2
Top Ten Highest Hourly Loads
Date Load
1 12/16/2008 1821
2 12/16/2008 1809
3 12/16/2008 1791
4 2/1/1996 1796
5 12/15/2008 1781
6 12/15/2008 1776
7 2/2/1996 1770
8 1/5/2004 1766
9 12/16/2008 1759
10 12/14/2008 1752
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 391 of 729
3
Daily Average Loads
1989-2008
400
600
800
1000
1200
1400
1600
1800
1/
1
/
1
9
8
9
1/
1
/
1
9
9
0
1/
1
/
1
9
9
1
1/
1
/
1
9
9
2
1/
1
/
1
9
9
3
1/
1
/
1
9
9
4
1/
1
/
1
9
9
5
1/
1
/
1
9
9
6
1/
1
/
1
9
9
7
1/
1
/
1
9
9
8
1/
1
/
1
9
9
9
1/
1
/
2
0
0
0
1/
1
/
2
0
0
1
1/
1
/
2
0
0
2
1/
1
/
2
0
0
3
1/
1
/
2
0
0
4
1/
1
/
2
0
0
5
1/
1
/
2
0
0
6
1/
1
/
2
0
0
7
1/
1
/
2
0
0
8
MW
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 392 of 729
4
Thermal Generation
0
200
400
600
800
1000
1200
1400
1600
1800
2000
De
c

1
5

1
:
0
0
De
c

1
5

9
:
0
0
De
c

1
5

1
7
:
0
0
De
c

1
6

1
:
0
0
De
c

1
6

9
:
0
0
De
c

1
6

1
7
:
0
0
De
c

1
7

1
:
0
0
De
c

1
7

9
:
0
0
De
c

1
7

1
7
:
0
0
Peakers
Thermal
Native Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 393 of 729
5
Hydro Generation
0
200
400
600
800
1000
1200
1400
1600
1800
2000
De
c

1
5

1
:
0
0
De
c

1
5

9
:
0
0
De
c

1
5

1
7
:
0
0
De
c

1
6

1
:
0
0
De
c

1
6

9
:
0
0
De
c

1
6

1
7
:
0
0
De
c

1
7

1
:
0
0
De
c

1
7

9
:
0
0
De
c

1
7

1
7
:
0
0
Mid C Hydro
Clark Fork Hydro
Spokane River Hydro
Peakers
Thermal
Native Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 394 of 729
6
River icing was a problem!
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
20000
12/12/2008
12/14/2008
12/16/2008
12/18/2008
12/20/2008
12/22/2008
12/24/2008
12/26/2008
12/28/2008
12/30/2008
Fl
o
w

(
c
f
s
)
Noxon Rapids Inflow
Kerr Discharge
Noxon inflow dropped from about 15K to
about 11K, an effective disappearance of
about 27%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 395 of 729
7
Contracts
0
200
400
600
800
1000
1200
1400
1600
1800
2000
De
c

1
5

1
:
0
0
De
c

1
5

9
:
0
0
De
c

1
5

1
7
:
0
0
De
c

1
6

1
:
0
0
De
c

1
6

9
:
0
0
De
c

1
6

1
7
:
0
0
De
c

1
7

1
:
0
0
De
c

1
7

9
:
0
0
De
c

1
7

1
7
:
0
0
Contracts
Mid C Hydro
Clark Fork Hydro
Spokane River Hydro
Peakers
Thermal
Native Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 396 of 729
8
Market Purchases
0
200
400
600
800
1000
1200
1400
1600
1800
2000
De
c

1
5

1
:
0
0
De
c

1
5

9
:
0
0
De
c

1
5

1
7
:
0
0
De
c

1
6

1
:
0
0
De
c

1
6

9
:
0
0
De
c

1
6

1
7
:
0
0
De
c

1
7

1
:
0
0
De
c

1
7

9
:
0
0
De
c

1
7

1
7
:
0
0
Market
Contracts
Mid C Hydro
Clark Fork Hydro
Spokane River Hydro
Peakers
Thermal
Native Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 397 of 729
Natural Gas & Electric Price
Forecast- Update
Greg Rahn & James Gall
2009 Electric Integrated Resource Plan
Fourth Technical Advisory Committee Meeting
January 28, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 398 of 729
2
Study Changes Since Last TAC
ƒWood Mackenzie released its “Carbon Case #3”
-Mid-range greenhouse gas mitigation scenario
-Natural gas price impact from greenhouse legislation
-Demand reductions due to greenhouse gas legislation
ƒUpdated Natural Gas Price Forecast
-Integrates near term economy
-Short-term price collapse
-Credit markets
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 399 of 729
3
Natural Gas Price Forecast Update
Supply Increase to Soften Price of Natural Gas
ƒEdinburgh, Scotland-based energy consultancy Wood Mackenzie said it
expects spot prices for natural gas between $5 and $6 per million British
thermal units for the next few years, with periods when prices will slip
even lower.
ƒ"We are now in a position of significant potential oversupply brought
about by the huge success experienced in the development of shale
gas plays," says Jen Snyder, head of North American gas research at
Wood Mackenzie.
- Russell Gold, The Wall Street Journal
November 25, 2008
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 400 of 729
4
$5.00
$7.00
$9.00
$11.00
$13.00
$15.00
$17.00
$19.00
$21.00
$
p
e
r

D
t
h
2009 IRP 6.66 6.69 6.69 6.69 7.05 7.87 8.63 9.20 10.05 10.69 10.89 10.86 10.94 11.26 11.50 11.76 12.04 12.49 12.72 12.96
Oct TAC 7.64 7.69 8.53 9.14 9.90 10.00 10.52 11.13 11.67 12.41 12.82 12.94 13.60 14.79 16.57 17.84 18.30 18.77 19.26 19.75
2007 IRP 6.23 5.91 6.00 6.15 6.30 6.59 6.98 7.47 7.95 8.44 8.94 9.43 9.95 10.50 11.08 11.70 12.35 13.04 13.77 14.55
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Annual Natural Gas Price Comparison
Henry Hub Nominal $
Levelized Costs
2009 IRP: $9.05
Oct TAC: $11.71
2007 IRP: $8.44
2009 IRP: 2010-2013 Average Price of Consultants, EIA, and Forward Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 401 of 729
5
$5.00
$7.00
$9.00
$11.00
$13.00
$15.00
$17.00
$19.00
$21.00
$
p
e
r

D
t
h
2009 IRP 6.53 6.43 6.29 6.17 6.37 6.98 7.52 7.87 8.44 8.81 8.82 8.64 8.55 8.64 8.66 8.70 8.74 8.90 8.90 8.90
Oct TAC 7.49 7.39 8.03 8.43 8.96 8.88 9.17 9.52 9.80 10.23 10.38 10.29 10.63 11.35 12.48 13.20 13.29 13.37 13.47 13.56
2007 IRP 6.23 5.80 5.77 5.79 5.81 5.96 6.19 6.50 6.80 7.09 7.37 7.63 7.91 8.20 8.50 8.81 9.14 9.47 9.81 10.17
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Annual Natural Gas Price Comparison
Henry Hub 2009 $
Levelized Costs
2009 IRP: $7.68
Oct TAC: $9.95
2007 IRP: $7.07
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 402 of 729
6
Greenhouse Gas Price Assumptions
ƒBased on the most recent ‘discussion draft’ proposal by Reps. Dingell and
Boucher of the House Energy and Commerce Committee
ƒWood Mackenzie made assumptions on the key components of the analysis
such as caps on carbon prices, the allocation of carbon credits, the use of
carbon offsets, and, nuclear and CCS technology availability.
ƒWood Mackenzie’s proprietary upstream oil, gas, and coal data and analysis are
the cost and availability of fuel supplies, particularly to support an assumption to
increase reliance on natural gas to meet near term emission reduction
requirements.
ƒCarbon offsets/other industry represent difference between forecasted
emissions and legislative goals
Source: Wood Mackenzie Carbon Case 3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 403 of 729
7
$-
$0.50
$1.00
$1.50
$2.00
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$
p
e
r

D
t
h
2009 IRP
Oct TAC
Annual GHG Adder to Natural Gas Prices
2008 $
Levelized Costs
2009 IRP: $0.54
Oct TAC: $0.51
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 404 of 729
8
-
20.0
40.0
60.0
80.0
100.0
120.0
$/

S
h
o
r
t

T
o
n
Oct TAC 23 26 28 30 33 36 39 41 43 47 51 55 59 60 65 70 76 81
2009 IRP 7 12 18 24 33 35 50 54 57 61 66 70 75 80 86 92 98 105
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Annual GHG Adder per Ton of CO2
Nominal $
Levelized Costs
2009 IRP: $46.14
Oct TAC: $41.30
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 405 of 729
9
-
10
20
30
40
50
60
70
80
$/

S
h
o
r
t

T
o
n
Oct TAC 22 23 25 27 28 30 32 34 34 36 39 41 44 43 46 49 52 55
2009 IRP 6 11 16 21 28 30 41 43 46 48 50 53 55 58 61 64 67 71
2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Annual GHG Adder per Ton of CO2
2009 $
Levelized Costs
2009 IRP: $35.83
Oct TAC: $32.92
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 406 of 729
10
100,000
110,000
120,000
130,000
140,000
150,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Base Loads
2009 IRP
Western Interconnect Load Growth
Change with Greenhouse Gas Legislation
Annualized Load Growth
2009 IRP: 1.57%
Load Base: 1.80%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 407 of 729
11
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$/
M
W
h
Oct TAC
2009 IRP
Last TAC Price Forecast vs 2009 IRP
Levelized Costs
2009 IRP: $ 86.37
Oct TAC: $103.59
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 408 of 729
12
US Western Interconnect Greenhouse Gas Comparison
200
250
300
350
400
450
Mi
l
l
i
o
n
s

o
f

S
h
o
r
t

T
o
n
s
2009 IRP 336 337 335 332 334 333 330 332 325 329 323 317 312 314 314 309 310 309 307 303
Oct TAC 319 321 314 319 325 324 331 337 338 345 343 347 351 357 367 371 375 377 385 385
2005 Levels 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334
1990 Levels 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 409 of 729
13
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
19
9
7
19
9
8
19
9
9
20
0
0
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
20
0
6
20
0
7
20
0
8
20
0
9
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$
p
e
r

M
W
h
Mid-Columbia Actual & Forecast
Actual Mid-Columbia Firm Index 2009 IRP Forecast-Deterministic
20
0
9

F
o
r
w
a
r
d
s
Dashes are
2009$ Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 410 of 729
14
Implied Market Heat Rate
(Mid-Columbia/Stanfield*1000)
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Bt
u
/
k
W
h
Implied Market Heat Rate
(Power/Gas*1000)
Implied Market Heat Rate
(Exclude GHG Cost
@8,000HR)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 411 of 729
15
Western Interconnect New Resources
(5)
5
15
25
35
45
55
65
75
85
95
105
115
125
GW
Hydro - - - - - - 0 0 0 0 0 0 0 0 0 0 0 0 0 0
Solar 2 3 3 4 5 6 7 8 9 10 12 12 13 13 14 15 15 16 16 16
Geothermal 0 0 0 1 1 1 1 1 1 2 2 2 2 2 2 2 2 2 2 2
Biomass 0 0 0 0 1 1 1 1 1 1 2 2 2 2 2 2 2 2 2 2
Wind 3 4 5 6 7 10 13 15 18 19 24 25 25 26 26 28 29 29 29 30
SCCT 10 12 14 15 15 16 16 17 17 17 17 17 17 17 17 17 17 17 17 17
Coal Seq - - - - - - - - - - - - - - - - 1 1 1 1
CCCT - 2 7 8 9 12 14 16 18 21 22 25 29 32 35 38 41 44 47 49
Oil- retire (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0) (0)
NG- retire (0) (0) (1) (1) (2) (2) (2) (2) (2) (2) (2) (2) (2) (2) (2) (2) (2) (2) (2) (2)
Coal- retire - - - (0) (0) (0) (0) (0) (0) (0) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1)
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 412 of 729
16
Colstrip Generation & CO2 Legislation
0
50
100
150
200
250
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
$-
$20
$40
$60
$80
$100
$
p
e
r

S
h
o
r
t

T
o
n
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 413 of 729
Stochastic Analysis
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 414 of 729
18
Stochastic Study CPU Requirements
ƒ20-year hourly simulations, 250 times (tested as high as 500)
ƒUses 25 CPU and 1 data server
ƒ26.5 GB output database per study
ƒ6 hours per simulation, 1,500 hours of computing time
ƒ2.5 days to complete a study
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 415 of 729
19
Long-Term Correlation Matrix
Lancaster
1.001.000.500.50Hog Fuel Prices
1.001.00-0.25-0.25-0.25New Coal Prices
1.001.001.000.75SO2Prices
1.001.000.75NOXPrices
1.00-0.50Hg Prices
1.000.50GHG Prices
1.00Gas Prices
Load
Growth
Hog
Fuel
Prices
New
Coal
Prices
SO2Prices
NOXPrices
GHG
Prices
Gas
Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 416 of 729
20
Annual Henry Hub Prices
$4.00
$5.00
$6.00
$7.00
$8.00
$9.00
$10.00
$11.00
$12.00
$13.00
$14.00
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$
p
e
r

D
t
h
Deterministic
Stochastic Mean
Stochastic Median
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 417 of 729
21
Annual Henry Hub Prices
Select Years
$-
$5
$10
$15
$20
$25
$30
$35
$40
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%
Percent of Draws
$
p
e
r

D
t
h
2010 2014
2017 2020
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 418 of 729
22
Annual Henry Hub Stochastic Price Ranges
Mean
Min
99 Percentile
90% Con. Int.
$-
$5.00
$10.00
$15.00
$20.00
$25.00
$30.00
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$
p
e
r

D
t
h
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 419 of 729
23
Annual Mid-Columbia Electric Prices
Deterministic vs. Stochastic Prices
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$/
M
W
h
Deterministic
Stochastic- Mean
Levelized Costs
Stochastic: $93.68
Deterministic: $86.37
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 420 of 729
24
Annual Avg Mid-Columbia Prices
Select Years
$-
$50
$100
$150
$200
$250
$300
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%
Percent of Draws
$
p
e
r

M
W
h
2010 2014
2017 2020
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 421 of 729
25
Annual Mid-Columbia Stochastic Price Results
Mean
Min
99 Percentile
90% Con. Int.
$-
$50
$100
$150
$200
$250
$300
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$
p
e
r

M
W
h
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 422 of 729
26
US- Western Interconnect Greenhouse Gas Emissions By Year
200
250
300
350
400
450
Mi
l
l
i
o
n
s

o
f

S
h
o
r
t

T
o
n
s
Deterministic 336 337 335 332 334 333 330 332 325 329 323 317 312 314 314 309 310 309 307 303
Mean 323 326 326 322 323 321 315 324 316 320 316 312 311 317 320 319 326 326 328 333
Upper End Int 80% 363 366 365 369 376 385 382 393 395 397 400 395 398 403 402 403 415 417 415 424
Low er End Int 80% 284 286 287 276 270 257 249 256 238 243 233 228 223 232 238 234 237 236 240 241
2005 Levels 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334 334
1990 Levels 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259 259
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 423 of 729
2009 IRP Resource Assumptions
John Lyons, Ph.D.
2009 Electric Integrated Resource Plan
Fourth Technical Advisory Committee Meeting
January 28, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 424 of 729
2
Supply Side Resources
ƒResource lists and data are developed from a variety of sources
including: internal research, Power Council, consulting firms,
published reports, and government studies
ƒData is used to develop generic resource costs
ƒFewer types of coal resources are included – only ultra critical
and IGCC plants are being modeled for the 2009 IRP
ƒAlberta oil sands are not included as a resource option
ƒAdding more specifics for the Other Renewable Resources
category – various geothermal, biomass, and solar resource
technologies are being modeled separately for the 2009 IRP
ƒPipeline cogeneration has been dropped due to lack of sufficient
data
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 425 of 729
3
Non-Renewable Supply Side Resources
ƒNatural Gas Combined Cycle (CCCT)
–2 x 1 and 1 x 1 with duct burner water cooled (1x1 for PRS)
–2 x 1 and 1 x 1 with duct burner air cooled
–600 MW with sequestration
ƒNatural Gas-Fired Simple Cycle – Aero, Frame, and Hybrid
ƒSmall cogeneration (< 5 MW)
ƒCoal: ultra critical, IGCC, and IGCC with sequestration
ƒNuclear: only alllowed in scenario studies
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 426 of 729
4
Renewable Supply Side Resources
ƒGeothermal
ƒWind – 100 MW, < 5 MW, and offshore
ƒCCCT Wood Boiler
ƒWood Gasification Conversion
ƒOpen Loop Biomass – landfill gas, wood, waste, etc.
ƒClosed Loop Biomass
ƒSolar Photovoltaic
ƒSolar Thermal
ƒRoof Top Solar
ƒTidal Power
ƒHydrokinetics
ƒRun of River Hydro
ƒPumped Storage
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 427 of 729
5
Avista Resources and Upgrades
Hydro resources included as resource options
ƒLittle Falls Unit #1 – 4 Upgrades
ƒPost Falls Unit #6 Upgrade
ƒUpper Falls Upgrade
Hydro resources considered for further study
ƒLong Lake new unit and new powerhouse
ƒCabinet Gorge #5
Scheduled upgrades and resources presently included in the L&R
ƒNoxon Rapids Units #1 – 4 Upgrades (2009 – 2012)
ƒLancaster Generation Facility Tolling Agreement (2010)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 428 of 729
Transmission & Distribution Efficiencies
John Gibson
2009 Electric Integrated Resource Plan
Fourth Technical Advisory Committee Meeting
January 28, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 429 of 729
2
Introduction – System Efficiencies
ƒDistribution System
•Analysis Methodology
•Analysis Criteria
•Prioritization Tabulation
•Pilot Project: 9CE12F4
ƒTransmission System
•Load Density
•Grid Topology
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 430 of 729
3
Distribution Efficiency Programs
ƒSplit feeders
ƒDistribution transformers efficiency – no load loss
ƒSecondary districts
ƒReconductoring
ƒReactive loading
ƒVoltage regulation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 431 of 729
4
Distribution Analysis Criteria
ƒEnergy efficiency upgrades (acquisition cost)
ƒCapital offset (5year capital budget)
ƒReliability Index
ƒEquipment age profile
ƒOperational requirements
Capital Offset
Reliability
A ge
Operational
Requirements
Acquisition Cost
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 432 of 729
5
Distribution Prioritization Tabulation
0.481Low$780,833$125.8129830.06CLV12F2
0.483High$0$125.0329131.73SUN12F1
0.490Low$0$109.1931723.29STM631
0.499Low$0$102.9129921.71LF34F1
0.502Low$28,333$108.4732330.43CLV12F4
0.502Low$250,000$108.7730330.44COB12F1
0.508Low$0$102.5930927.39LAT421
0.519Low$0$94.8128327.32COB12F2
0.522High$0$112.7831225.20SUN12F3
0.533Low$0$78.9719730.33ORO1281
0.544Low$0$94.1033123.34PRV4S40
0.558Low$220,000$90.7631027.57SPI12F1
0.591Low$0$73.3028527.44ORI12F3
0.596Low$400,000$85.0732825.32KET12F2
Overall
Score
Operational
RequirementsCapital Offset
Avoided
CostReliabilityAge
Feeder
Project
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 433 of 729
6
Feed Efficiency Upgrade – Pilot Project
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 434 of 729
7
Feed Efficiency Upgrade – Pilot Project
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 435 of 729
8
Feed Efficiency Upgrade – Pilot Project
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 436 of 729
9
Feed Efficiency Upgrade – Pilot Project
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 437 of 729
10
Feed Efficiency Upgrade – Pilot Project
230125$1,100,0009thand Central 12F4
Peak Power kWCapital Investment Average Power kWFeeder
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 438 of 729
11
Transmission Efficiency Initiatives
ƒLoad density and forecasted load growth
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 439 of 729
12
Transmission Efficiency Initiatives
ƒLoad density and forecasted load growth
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 440 of 729
13
Transmission Efficiency Initiatives
ƒLoad density and forecasted load growth
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 441 of 729
14
Transmission Efficiency Initiatives
ƒTransmission topology
ƒTransmission archetypes
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 442 of 729
15
Transmission Efficiency Initiatives
ƒTransmission topology
ƒTransmission archetypes
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 443 of 729
16
Transmission Efficiency Initiatives
ƒTransmission topology
ƒTransmission archetypes
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 444 of 729
Preferred Resource Strategy-
DRAFT
James Gall
2009 Electric Integrated Resource Plan
Fourth Technical Advisory Committee Meeting
January 28, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 445 of 729
2
Resource Needs (Energy)
Annual Average Energy Resources vs Load
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
aM
W
Hydro Base Thermal Contracts Peakers Load Load w/ Cont.
Load is net 2007 Conservation Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 446 of 729
3
Resource Needs (Winter Capacity)
Annual Resource Capacity at Winter Peak Load
0
500
1,000
1,500
2,000
2,500
3,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
Hydro Base Thermal Contracts
Peakers Load Load w/PM, w/o Maint
Load is net 2007 Conservation Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 447 of 729
4
Resource Needs (Summer Capacity)
Annual Resource Capacity at August Peak Load
0
500
1,000
1,500
2,000
2,500
3,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
Hydro Base Thermal Contracts
Peakers Load Load w/PM, w/o Maint
Load is net 2007 Conservation Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 448 of 729
5
Resource Needs (Energy)
Energy Positions
(1,000)
(800)
(600)
(400)
(200)
0
200
400
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
aM
W
Energy Position
Energy Position (No Q2)
Lancaster Tolling
Contract Expires
100MW Flat
Market Purchase
Contracts Expire
Net 2007 Conservation Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 449 of 729
6
Resource Needs (Capacity)
Capacity Positions
(1,000)
(800)
(600)
(400)
(200)
0
200
400
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
Winter Peak Position
August Peak Position
WNP-3 Purchase
Contract Expires
PGE Capacity
Sale Expires
Lancaster Tolling
Contract Expires
100MW Flat
Market Purchase
Contracts Expire
Net 2007 Conservation Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 450 of 729
7
PRiSM Objective Function
ƒLinear program solving for the optimal resource strategy to meet
resource deficits over planning horizon.
ƒModel selects its resources to reduce cost, risk, or both.
Minimize:Total Power Supply Cost on NPV basis (2010-2050 with
emphasis on first 11 years of the plan
Subject to:
•Risk Level
•Capacity Need +/- deviation
•Energy Need +/- deviation
•Renewable Portfolio Standards
•Resource Limitations and Timing
•Greenhouse Gas Limits
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 451 of 729
8
PRiSM Data Requirements
ƒExpected load & resource balance for next 20 years
ƒ20 year by 250 iteration matrix of resource values
ƒAvista’s current resource portfolio cost
ƒEach new resource alternatives market value (electric price
less fuel costs, variable O&M, and emissions costs)
ƒExisting resource market value
ƒConservation estimates
ƒGeneration capital costs, fixed operating costs, transmission
costs, revenue requirements
ƒAvailability assumptions (size, when, where)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 452 of 729
9
PRiSM New Enhancements
ƒResources selections must be blocks of resources such as 50
MW wind, 75 MW SCCT, 125 MW CCCT (half unit)
ƒUse more precise method to estimate frontier curve
ƒMeets both summer & winter capacity requirements
ƒAbility to account for greenhouse gas levels
ƒMore accurate ability to take into account post IRP time period
ƒAbility to retire resources (used for sensitivity analysis only)
ƒHigher cost conservation measures can be selected by the
model (available for final draft)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 453 of 729
10
Efficient Frontier
ƒDemonstrates the trade off of cost and risk
ƒAvoided Cost Method
Ri
s
k
Least Cost Portfolio
Least Risk Portfolio
Find least cost portfolio
at a given level of risk
Short-term
Market Only
Market Capacity Risk+ = Avoided Cost+
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 454 of 729
11
Portfolio Scenarios
1) Base Case
2) Case 1 + Small Renewable as Options
3) Case 2 + Large Hydro Upgrades as Options
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 455 of 729
12
$160
$165
$170
$175
$180
$185
$190
$195
$200
$205
$3,400 $3,450 $3,500 $3,550 $3,600 $3,650
Expected PV (2010-2020) (2009$)
20
2
0

S
t
d
e
v

(
2
0
0
9
$
)
Efficient Frontier (millions)
2009 PRS
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 456 of 729
13
-20%
-18%
-16%
-14%
-12%
-10%
-8%
-6%
-4%
-2%
0%
0.0% 0.5% 1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 4.0%
Incremental Cost
De
c
r
e
m
e
n
t
a
l

R
i
s
k
Change From Least Cost Portfolio
8% Reduction
5% Reduction
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 457 of 729
14
Preferred Resource Strategy (2020-2029
DRAFT- Base Case
“Yellow Light” conservation not modeled yet
Year CCCT SCCT Reardan Wind
Other
Renew Solar
Hydro
Upgrades Coal
IGCC
w/ Seq Co-Gen DSM T&D Total Cumulative
2010 7.8 1.0 8.8 8.8
2011 7.9 1.0 8.9 17.6
2012 50.0 8.0 1.0 59.0 76.6
2013 100.0 8.2 1.0 109.2 185.8
2014 8.3 1.0 9.3 195.1
2015 125.0 1.0 8.4 1.0 135.4 330.5
2016 8.6 8.6 339.1
2017 1.0 8.7 9.7 348.8
2018 100.0 8.9 108.9 457.7
2019 100.0 2.5 9.0 111.5 569.2
2020 250.0 100.0 4.0 5.0 9.2 368.2 937.3
2021 9.3 9.3 946.7
2022 9.5 9.5 956.1
2023 9.6 9.6 965.8
2024 9.8 9.8 975.6
2025 125.0 10.0 135.0 1,110.6
2026 125.0 10.1 135.1 1,245.7
2027 250.0 10.3 260.3 1,506.0
2028 50.0 10.5 60.5 1,566.5
2029 100.0 7.0 10.7 117.7 1,684.2
2010-2019 125.0 - 50.0 300.0 - - 2.0 - - 2.5 83.7 6.0 569.2
2010-2029 875.0 - 50.0 550.0 7.0 - 6.0 - - 7.5 182.7 6.0 1,684.2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 458 of 729
15
PRS: Winter Capacity
0
200
400
600
800
1,000
1,200
1,400
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
Conservation CCCT
CCCT w/ Seq SCCT
Wind Other Renewables
Solar Hydro Upgrades
Coal IGCC w/ Seq
Co-Gen Nuclear
Market T&D Efficiencies
Need
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 459 of 729
16
PRS: Summer Capacity
0
200
400
600
800
1,000
1,200
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
Conservation CCCTCCCT w/ Seq SCCTWindOther RenewablesSolarHydro Upgrades
Coal IGCC w/ SeqCo-Gen NuclearMarketT&D EfficienciesNeed
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 460 of 729
17
PRS: Annual Average Energy
0
200
400
600
800
1,000
1,200
1,400
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
aM
W
Conservation CCCTCCCT w/ Seq SCCTWindOther RenewablesSolarHydro UpgradesCoalIGCC w/ SeqCo-Gen NuclearMarketT&D EfficienciesTotal
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 461 of 729
18
PRS: WA RPS Requirement
0
20
40
60
80
100
120
140
160
180
200
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
aM
W
Wind Other RenewablesSolarHydro UpgradesPurchased REC Sold RECCurrent Shortfall
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 462 of 729
19
PRS: Greenhouse Gas Emissions
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Sh
o
r
t

T
o
n
s

(
T
h
o
u
s
a
n
d
s
)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 463 of 729
20
2020: Portfolios on the Efficient Frontier
-
200
400
600
800
1,000
1,200
Na
m
e
p
l
a
t
e

C
a
p
a
c
i
t
y
T&D Efficiencies 5 5 5 5 5 5 5 5 4
Co-Gen 5 - 8 5 8 8 - - 8
IGCC w/ Seq - - - - - - - - -
Coal - - - - - - - - -
Hydro Upgrades 4 4 6 6 6 4 2 2 6
Solar - - - - - - - - -
Other Renewables - - - - 1 - - - -
Wind 600 550 500 450 450 400 350 300 450
SCCT - - - - - - - - -
CCCT 375 375 375 375 375 375 375 375 375
Least Risk ------++++Least Cost PRS
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 464 of 729
21
2029: Portfolios on the Efficient Frontier
-
200
400
600
800
1,000
1,200
1,400
1,600
Na
m
e
p
l
a
t
e

C
a
p
a
c
i
t
y
T&D Efficiencies 5 5 5 5 5 5 5 5 4
Co-Gen 10 8 8 5 10 8 8 8 8
IGCC w/ Seq 400 400 400 400 - - - - -
Coal - - - - - - - - -
Hydro Upgrades 4 6 6 6 6 5 5 5 6
Solar - - - - - - - - -
Other Renewables - - - - 1 7 7 7 7
Wind 600 550 500 550 600 500 350 350 600
SCCT - - - - - - - - -
CCCT 500 500 500 500 875 875 875 875 875
Least Risk ------++++Least Cost PRS
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 465 of 729
22
Efficient Frontier: Capital Requirements
$-
$1.0
$2.0
$3.0
$4.0
$5.0
$6.0
$7.0
Least
Risk
--- -- - + ++ + Least
Cost
PRS
Bi
l
l
i
o
n
s

(
N
o
t

D
i
s
c
o
u
n
t
e
d
)
2020-2029
2010-2019
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 466 of 729
23
Efficient Frontier Scenario Analysis
$125
$150
$175
$200
$225
$3,400 $3,450 $3,500 $3,550 $3,600 $3,650 $3,700 $3,750 $3,800 $3,850
Expected PV (2010-2020)
St
a
n
d
a
r
d

D
e
v
i
a
t
i
o
n

(
2
0
2
0
)
Scenario 1: Base Case
Scenario 2: Small Renewables
Scenario 3: + Hydro Upgrades
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 467 of 729
24
Scenario 2- Resource Selection
Small Renewables an Option
Year CCCT SCCT Reardan Wind
Other
Renew Solar
Hydro
Upgrades Coal
IGCC
w/ Seq Co-Gen DSM T&D Total Cumulative
2010 7.8 1.0 8.8 8.8
2011 7.9 1.0 8.9 17.6
2012 10.0 8.0 1.0 19.0 36.6
2013 50.0 50.0 5.0 8.2 1.0 114.2 150.8
2014 8.3 1.0 9.3 160.1
2015 125.0 1.0 8.4 1.0 135.4 295.5
2016 10.0 8.6 18.6 314.1
2017 8.7 8.7 322.8
2018 100.0 5.0 8.9 113.9 436.7
2019 100.0 9.0 109.0 545.7
2020 250.0 100.0 4.0 1.0 9.2 364.2 909.8
2021 5.0 9.3 14.3 924.2
2022 1.0 5.0 9.5 15.5 939.6
2023 9.6 9.6 949.3
2024 9.8 9.8 959.1
2025 125.0 10.0 135.0 1,094.1
2026 125.0 10.1 135.1 1,229.2
2027 125.0 10.3 135.3 1,364.5
2028 10.5 10.5 1,375.0
2029 100.0 100.0 10.7 210.7 1,585.7
2010-2019 125.0 - 50.0 250.0 30.0 - 1.0 - - - 83.7 6.0 545.7
2010-2029 750.0 100.0 50.0 450.0 30.0 4.0 3.0 - - 10.0 182.7 6.0 1,585.7
2010-2019 (Delta) - - - (50.0) 30.0 - (1.0) - - (2.5) - - (23.5)
2010-2029 (Delta) (125.0) 100.0 - (100.0) 23.0 4.0 (3.0) - - 2.5 - - (98.5)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 468 of 729
25
Scenario 3- Resource Selection
Scenario 2 + Hydro Upgrades an Option
Year CCCT SCCT Reardan Wind
Other
Renew Solar
Hydro
Upgrades Coal
IGCC
w/ Seq Co-Gen DSM T&D Total Cumulative
2010 7.8 1.0 8.8 8.8
2011 7.9 1.0 8.9 17.6
2012 10.0 8.0 1.0 19.0 36.6
2013 50.0 50.0 4.0 8.2 1.0 113.2 149.8
2014 4.0 8.3 1.0 13.3 163.1
2015 4.0 60.0 8.4 1.0 73.4 236.5
2016 5.0 1.0 8.6 14.6 251.1
2017 1.0 8.7 9.7 260.8
2018 100.0 8.9 108.9 369.7
2019 100.0 4.0 9.0 113.0 482.7
2020 250.0 100.0 4.0 64.0 5.0 9.2 432.2 914.8
2021 9.3 9.3 924.2
2022 9.5 9.5 933.6
2023 9.6 9.6 943.3
2024 9.8 9.8 953.1
2025 125.0 10.0 135.0 1,088.1
2026 125.0 10.1 135.1 1,223.2
2027 250.0 5.0 10.3 265.3 1,488.5
2028 100.0 10.5 110.5 1,599.0
2029 100.0 10.7 110.7 1,709.7
2010-2019 - - 50.0 250.0 15.0 16.0 126.0 - - - 83.7 6.0 482.7
2010-2029 750.0 - 50.0 550.0 20.0 20.0 126.0 - - 5.0 182.7 6.0 1,709.7
2010-2019 (Delta) (125.0) - - (50.0) 15.0 16.0 124.0 - - (2.5) - - (86.5)
2010-2029 (Delta) (125.0) - - - 13.0 20.0 120.0 - - (2.5) - - 25.5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 469 of 729
26
Greenhouse Gas Scenario Comparison
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Th
o
u
s
a
n
d

S
h
o
r
t
-
T
o
n
s
Base Case
Scenario 2
Scenario 3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 470 of 729
27
Next Steps
ƒAdd “Yellow Light” conservation projects as resource options
ƒPerform capital cost sensitivity analysis
ƒStudy portfolios with renewable requirement changes
ƒResource Availability
ƒNational RPS
ƒHigher WA state RPS target
ƒStudy portfolio options with alternative market futures
ƒTest “Preferred Resource Strategies” against market scenarios
ƒFurther evaluate large hydro upgrades
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 471 of 729

Avista’s 2009 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
March 25, 2009

Topic Time Staff
1. Introduction 9:30 Storro
2. Conservation 9:35 Hermanson
3. Lunch 11:30

4. Preferred Resource Strategy 12:30 Gall

5. Scenarios and Futures 1:30 Gall/Lyons

6. 2009 IRP Topics 2:30 Lyons

7. Adjourn 3:00

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 472 of 729
DSM in the 2009 Electric IRP
Technical Advisory Committee Meeting
Lori Hermanson
March 25, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 473 of 729
Presentation Highlights
• D SM History
• O verview of DSM
ƒWhat, why, how and who of DSM
• Customer segments reached and offerings
• Messaging and outreach through EveryLittleBit and Website
• Tariff Rider Funding
• M etrics
• Stakeholders
• 2008 Results and 2009 Focus
• Integration of DSM into IRP
• Business planning to program development
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 474 of 729
Brief DSM History
• Offered DSM since 1978
ƒEnergy exchanger – converted over 20,000 homes from
electric to natural gas for space and water
ƒPioneered the country’s first system benefit charge for energy
efficiency in 1995
ƒImmediate conservation response to 2001 Western energy
crisis through expanded programs and enhanced incentives
– Tripled annual savings at twice the cost
ƒDuring the past 30 years, we acquired 138.5 aMW of energy
savings
– 109 aMW still online
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 475 of 729
Deep and broad energy efficiency
programs with strong messaging for all
customers.
We provide financial rebates for all com-
mercial and industrial electric and natural
gas savings measures with a payback
over one year and we offer rebates for
weatherization and efficient appliances
as well as low-cost/no-cost
tips.
We provide renewable options
and are testing end-use
demand response pilots.
What We Do
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 476 of 729
Why We Do It
Acquire lower cost resources to benefit all
customers (IRP implementation)
Customer assistance
ƒReduction in customers' bills
ƒGives customers some control in a
higher energy cost environment
Regulatory obligation and sensibility
Reduced pressure on, or alternatives for,
the capital budget
Carbon reduction and environmental
focus
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 477 of 729
How We Do It
Pursue the Best Delivery Mechanisms for
the Targeted Market
¾Standard Offers (“Prescriptive”) for residential & small
commercial customers through mass marketing
¾Custom (“Site Specific”) for C&I customers with one
point of contact through our Account Executive Team
¾Low Income through community action agencies
¾Regional through the NW Energy Efficiency Alliance
¾Special projects—RFPs, Pilot Programs, etc.
¾Promotion of Codes and Standards
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 478 of 729
Who Does It
Program Managers and Coordinators
Catherine Bryan
Renee Coelho
Leona Doege
Chris Drake
Camille Martin
Lisa McGarity
Debby Reid
Kerry Shroy
Greta Zink
Tom Lienhard
Mike Dillon
Damon Fisher
Carlos Limon
Ron Welch
Jon Powell
Lori Hermanson
Pat Lynch
Bruce Folsom
Rachelle McGrath
Administration
Engineering Team
Analytical Group
Students
Virginia Luka
Rachael Roig
Nate Thompson
Kayla Trabun
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 479 of 729
Who Does It (cont.)
<<<Site Specific: Account Executive Team
Prescriptive: Marketing Team>>>
Contact Center assists customers with energy efficiency information
Corporate Communications provides earned media expertise
Community Relations partners with education and community
involvement
State and Federal Regulation Department assists with PUC filings
and communications
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 480 of 729
C/I Energy Efficiency
Site Specific
• Custom Projects
• Technical Assistance
• Free Energy Audits
and Analysis
• Design Review
• Cash Incentives
Avista Customer
Summary of Proposed
Energy Efficiency Measures
Listed in order of Simple Payback
OptionNo.Brief EEM Descripti on
EEM Cost Ele ctri c kW
h
Sav
ings
Dema nd kW Savin
gs
Nat. Gas Ther m
Savin
gs
Energy Cost Saving s
Simple Payba ck before
incenti
ve
Potenti al Incenti ve
Simple
Payback
After
Incentive
1 Site Lighting Retrofit
$179,
335
519
,44
1
76 (4,01
4)
$33,20
6 5.4 yrs $
62,333 3.5 Years
2
Warehou se Heater replacem ent
$53,3
95 --2,665 $2,804 19.0
yrs
$
7,995 16.2 yrs
3
Roof
insulatio
n
$180,
000 --7,742 $8,146 22.1
yrs
$
23,226 19.2 yrs
4 Office HVAC retrofits
$404,
240
93,
842 -6,069 $11,89
3
34.0
yrs
$
21,961 32.1 yrs
Scope of Work:•The above incentives are based on information provided by vendor. The costs for the insulation were based on $1.50 per square foot. Any higher costs will need verification, but may increase the incentive. •The warehouse HVAC system change is based on a building model using a warehouse setting and the insulation having already been complete. •The office HVAC changes are based on the complete sq.ft. of the office space increasing SEER/EER values to new construction standards and a slight increase in AFUE for heating.
•All reports are attached.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 481 of 729
C/I Energy Efficiency
Prescriptive
Standard Offer Programs
ƒMeasures that have
relatively uniform savings
ƒPre-determined amount
ƒStreamlined approach
ƒMarketability
ƒEase of understanding for
customers and contractors
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 482 of 729
C/I Prescriptive (Standard
Offer) Programs
¾Lighting
¾Food Service Equipment
¾PC Network Controls
¾Premium Efficiency Motors
¾Steam Trap Repair/ Replacement
¾Demand Controlled Ventilation
¾Side Stream Filtration
¾Retro-Commissioning
¾LEED Certification
¾Vending Machine Controllers
¾Refrigerated Warehouse
¾Electric to Gas Water Heater
Conversions
¾Variable Frequency Drives
¾Commercial Clothes
Washers
¾Energy Smart Grocer
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 483 of 729
Residential Prescriptive Offerings
•High efficiency equipment
•CFL lighting
•Refrigerator recycling
•Conversions from Straight
Resistance
•Weatherization
•Rooftop dampers
•Ductless heat pump pilot
•UCONS Multi-family direct install
•www.everylittlebit.com (visit our
house of rebates)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 484 of 729
Limited Income Offerings
• Weatherization
• Windows/Doors
• Conversions
• Equipment Upgrades
• Health & Human Safety
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 485 of 729
Regional Programs (NEEA)
• Acquisition of electric efficiency through market transformation
• Funded by 5 IOUs, ETO, generating publics and BPA
ƒAvista’s portion – 3.94%
• Regional leaders are discussing expansion of efforts
ƒAvista’s portion will increase to 5.6%
ƒSavings acquisition increase from 1.5 aMW to 2.94 aMW
• Historically been a cost-effective option to acquire resources
ƒLevelized TRC cost of about 10 mills
ƒNot necessarily representative of future costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 486 of 729
Messaging and Outreach: Every Little Bit
Market research done in 2007 found that Avista’s customers
believed they “were already efficiency, that energy efficiency is too
expensive, and it doesn’t make much difference.”
In response, the EveryLittleBit campaign was launched with a
website, broadcast and print media, and collateral materials in a
multi-channel, multi-year approach.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 487 of 729
Messaging and Outreach: Online Resources
•www.everylittlebit.com
•www.avistautilities.com
•Energy Saving Tips
•House of Rebates
•Downloadable Forms
•Energy Audit
•Bill Analyzer
•RDN Dealer List
•Efficiency Ave for Business
– in process
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 488 of 729
Funding of Energy Efficiency Programs
DSM Tariff Rider
A percentage of every dollar paid goes to
energy efficiency
Has multiple regulatory requirements for
implementation
Provides for $23 million annual budget
Moving towards an annual “true-up”
First “System Benefit Charge” in North
America in 1995
Continue to evaluate its efficacy and options
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 489 of 729
Potential Stimulus Funding
• Funding available for energy conservation and smart grid
development
• Avista is currently evaluating possible programs that could be
offered with additional funding from the stimulus bill
ƒOne possible project – regional smart grid pilot
– Utility and non-utility sponsors
– Scope includes everything from Advanced Metering
Infrastructure (AMI), software and support, to demand
response
– Avista still considering participation but still has not
committed to participation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 490 of 729
Resource Portfolio Standards (RPS)
• Previously I-937, requires large utilities to obtain a fixed
percentage of their electricity from qualifying renewable resources
in addition to all cost-effective and acquirable energy conservation
ƒ3% by 2012
ƒ9% by 2016
ƒ15% by 2020
• Avista is working with others to change this legislation to allow
utilities to use energy conservation acquisition above the cost-
effective levels in lieu of renewables
ƒBenefits the customer
ƒTruly lower cost resource
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 491 of 729
Metrics
Cost-Effectiveness, Measurement and Evaluation, Post-Verification,
Triple E Reports, Prudence Findings in General Rate Cases
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 492 of 729
Stakeholder Involvement
Avista External Energy Efficiency Board
Lynn Anderson – Idaho Public Utilities Commission
Nick Beamer –Aging and Long-Term Care of Eastern Washington
Sheryl Carter – Natural Resource Defense Council
Chris Davis – Spokane Neighborhood Action Programs
Carrie Dolwick – Northwest Energy Coalition
Michael Early – Industrial Customers of Northwest Utilities
Chuck Eberdt – The Energy Project
Tom Eckman – Northwest Power Planning Council
Donn English – Idaho Public Utilities Commission
Claire Fulenwider – Northwest Energy Efficiency Alliance
Stefanie Johnson – Washington Public Counsel
Steven Johnson – Washington Utilities and Transportation Commission
Lisa LaBolle – Idaho Office of Energy Resources
John Kaufman – Oregon Department of Energy
Mary Kimball – Washington Public Council
Lynn Kittilson – Oregon Public Utility Commission
Phil Kercher – Sacred Heart Medical Center
Ron Oscarson - Spokane County
Paula Pyron – Northwest Industrial Gas Users
Deborah Reynolds – Washington Utilities and Transportation Commission
Michael Shepard – E-Source
External Energy Efficiency Board
(Triple E)
Non-binding oversight, technical
advisory committee
Meets twice a year
Regular reporting
Periodic Newsletters
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 493 of 729
Incentives/Rebates Paid in 2008
• Slightly over $15 million paid to Avista customers.
ƒ$7.65 million to commercial/industrial customers
– 768 projects received an incentive
ƒ$6.1 million to residential customers
– 12,890 residential customers received
incentives
ƒ$1.2 million to limited income customers
– More than 450 households assisted
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 494 of 729
Avista’s 2008 Energy Efficiency Results
• Exceeded electric IRP goal by 41% and natural gas IRP goal by
32%
• Total electric savings over 74.8 million kilowatt hours
ƒCommercial/Industrial over 41.8 million kwh
ƒResidential over 31.1 million kwh
ƒLimited Income over 1.8 million kwh
• Total natural gas savings over 1.8 million therms
ƒCommercial/Industrial over 1.0 million therms
ƒResidential – 749,199 therms
ƒLimited Income – 102,438 therms
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 495 of 729
2009 Focus
Continued personalization, presence, and
participation for and by customers
New Programs Under Consideration:
Small Commercial Initiative, Energy
Champion, Energy Coaching,
Behavioral Programs, Bundling
Potential changes in Resource Portfolio
Standards in Washington, Energy Trust
of Oregon, Decoupling in all states
Earnings opportunities and potential for
expansion
Increasing electric and natural gas
savings targets
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 496 of 729
From Planning to Customer Programs
2009 Washington / Idaho DSM Business Plan
A Working Document to Plan and Guide our 2009 Strategy and Operations
Avista Washington / Idaho DSM staff Catherine Bryan Renee Coelho Mike Dillon Leona Doege Chris Drake Damon Fisher Bruce Folsom Lori Hermanson Tom Lienhard Carlos Limon-Granados Camille Martin Rachelle McGrath Jon Powell Ron Welch Greta Zink Avista External Energy Efficiency Board Lynn Anderson – Idaho Public Utilities Commission Nick Beamer –Aging and Long-Term Care of Eastern Washington Sheryl Carter – Natural Resource Defense Council Chris Davis – Spokane Neighborhood Action Programs Carrie Dolwick – Northwest Energy Coalition Michael Early – Industrial Customers of Northwest Utilities Chuck Eberdt – The Energy Project Tom Eckman – Northwest Power Planning Council Donn English – Idaho Public Utilities Commission Claire Fulenwider – Northwest Energy Efficiency Alliance Stefanie Johnson – Washington Public Counsel Steven Johnson – Washington Utilities and Transportation Commission Lisa LaBolle – Idaho Office of Energy Resources
John Kaufman – Oregon Department of Energy Mary Kimball – Washington Public Council Lynn Kittilson – Oregon Public Utility Commission Phil Kercher – Sacred Heart Medical Center Ron Oscarson - Spokane County Paula Pyron – Northwest Industrial Gas Users Deborah Reynolds – Washington Utilities and Transportation Commission Michael Shepard –E-Source
Total Company Planning From Planning >30 Programs
with >3000 DSM measures to Tariffs and and >300 measures
considered Programs offered
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 497 of 729
Integration of DSM into the 2009 Electric IRP
• Interactive process that meets regulatory requirements and
produces results for the business planning process
ƒIdentify all commercially available technologies or measures
– “Acceptance” or “rejection” within the IRP will not remove
any technology or application from potentially being
included
– Nearly 2,500 measures were evaluated for this IRP
ƒRe-evaluate existing residential measures and evaluate the
inclusion of addition measures
– May change the menu of residential offerings
– Nearly 800 measures were evaluated for this IRP
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 498 of 729
Integration of DSM into the 2009 Electric IRP (cont.)
• Inclusion of limited income and non-residential site specific
programs are done by modifying the historical baseline
ƒNot necessarily limited to modifying baseline for price elasticity
and load growth
ƒSite specific measures that fit into the 3,000+ measures
evaluated are evaluated through the normal IRP process
outside of this modified historical baseline approach
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 499 of 729
Assess market
characteristics & past
program results
Preliminary cost-
effectiveness evaluation
"Red""Yellow""Green"Terminate
Yellow - fail Yellow - Pass
Review existing
DSM business
plan
Additional analysis
of programs as
necessary
Development of a
revised DSM business
plan
Initiate new programs.
Continue, modify or terminate
existing programs per
business plan
Develop energy savings,
system coincident peak,
load shapes, NEB's,
measure lives
Develop cost
characteristics
Identify
potential
measures
Develop technical
and economic
potential
DSM
acquisition
goal
Business Plan
acquisition
goal
Outside of the Scope of the Integrated Resource Planning Process
Represented within the Integrated Resource Planning Process
Ran measures against the avoided
costs produced from model
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 500 of 729
Evaluation of Measures
• Based on levelized TRC, measures are categorized into “greens”,
“yellows” and “reds”
ƒ“Greens” automatically selected and entered into model
ƒ“Yellows” are tested - range ended up being $90-$140/MWh
ƒ“Reds” – no further testing
• IRP process results in DSM goal and updated avoided costs
y 63,119,081 kWh for 2010
y 65,643,844 kWh for 2011
y Avoided costs are used to evaluate new measures or
technologies that may arise between IRPs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 501 of 729
Business Planning Process
• Selected measures are further evaluated by program managers
ƒMarket research
ƒProgram bundling
ƒProgram development
• Budgets is prepared for individual programs
ƒUpdate economic potential savings acquisition
ƒProjection of FTE
ƒEstimate of participation levels, incentives, and other expenses
• Business plan goal
ƒHistorically, has been at or above IRP goal
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 502 of 729
Where Are We At in the IRP Process?
• Goals complete for 2010/2011
• Projection of 20 year DSM acquisition complete
0
2
4
6
8
10
12
14
16
18
20
201
0
201
2
201
4
2016
201
8
202
0
202
2
202
4
2026
202
8
regional
local
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 503 of 729
Where Are We At in the IRP Process? (cont.)
• Written contribution for the IRP document
ƒDrafts to J. Powell and B. Folsom for review and edits
ƒInsert final numbers and changes
ƒFinal document due end of March
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 504 of 729
2009 Preferred Resource Strategy
James Gall
2009 Electric Integrated Resource Plan
Fifth Technical Advisory Committee Meeting
March 25, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 505 of 729
2
January Capacity L&R Balance
Annual Resource Capacity at Winter Peak Load
0
500
1,000
1,500
2,000
2,500
3,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
Hydro Base Thermal Contracts
Peakers Load Load w/PM, w/o Maint
Load is net 2007 Conservation Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 506 of 729
3
August Capacity L&R Balance
Annual Resource Capacity at August Peak Load
0
500
1,000
1,500
2,000
2,500
3,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
Hydro Base Thermal Contracts
Peakers Load Load w/PM, w/o Maint
Load is net 2007 Conservation Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 507 of 729
4
Annual Energy L&R Balance
Annual Average Energy Resources vs Load
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
aM
W
Hydro Base Thermal Contracts Peakers Load Load w/ Cont.
Load is net 2007 Conservation Levels
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 508 of 729
5
PRiSM Objective Function
ƒLinear program solving for the optimal resource strategy to meet
resource deficits over planning horizon.
ƒModel selects its resources to reduce cost, risk, or both.
Minimize: Total Power Supply Cost on NPV basis (2010-2050 with
emphasis on first 11 years of the plan)
Subject to:
• Risk Level
• Capacity Need +/- deviation
• Energy Need +/- deviation
• Renewable Portfolio Standards
• Resource Limitations and Timing
• Greenhouse Gas Limits
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 509 of 729
6
Efficient Frontier
ƒDemonstrates the trade off of cost and risk
ƒAvoided Cost Calculation
Ri
s
k
Least Cost Portfolio
Least Risk Portfolio
Find least cost portfolio
at a given level of risk
Short-Term
Market
Market + Capacity + RPS = Avoided Cost
Capacity
Need
+ Risk Cost
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 510 of 729
7
$200
$220
$240
$260
$280
$300
$320
$340
$360
3,320 3,340 3,360 3,380 3,400 3,420 3,440 3,460 3,480 3,500 3,520
2010-2020 Total Cost NPV
20
2
0

S
t
a
n
d
a
r
d

D
e
v
i
a
t
i
o
n
Efficient Frontier
No New
Resources
(No DSM)Build to Capacity
Requirements (No DSM)
Build to Capacity/RPS
Requirements (No DSM)Preferred Resource
Strategy
Risk Reduction
Strategies on Efficient
Frontier
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 511 of 729
8
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$
p
e
r

M
W
h
Carbon Cost
RPS
Capacity
Mid-Columbia
Avoided Resource Cost
Levelized Costs
Mid-C: $68.22
Capacity: $11.66
RPS: $5.76
Carbon: $25.52
Total: $111.15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 512 of 729
9
2007 Preferred Resource Strategy
(Capacity MW)
Year CCCT SCCT Wind
Hydro
Upgrades
Non-Wind
Renewables
Low
Carbon
Baseload DSM
T&D
Efficiency
2008 - - - - - - 9 -
2009 - - - - - - 10 -
2010 275 - - - - - 11 -
2011 - - - - 20 - 12 -
2012 - - - - 10 - 13 -
2013 - - - - - - 14 -
2014 - - 100 - 5 - 15 -
2015 - - - - - - 15 -
2016 - - 100 - - - 16 -
2017 - - 100 - - - 16 -
2018 - - - - - - 16 -
2019 - - - - - - 16 -
2020 81 - - - 10 - 17 -
2021 32 - - - 10 - 17 -
2022 38 - - - 5 - 17 -
2023 15 - - - - - 18 -
2024 58 - - - - - 18 -
2025 38 - - - - - 18 -
2026 35 - - - - - 19 -
2027 305 - - - - - 19 -
2008-2017 275 - 300 - 35 - 130 -
2008-2027 877 - 300 - 60 - 304 -
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 513 of 729
10
Preferred Resource Strategy
(Capacity MW)
Year CCCT SCCT Wind
Hydro
Upgrades
Low
Carbon
Baseload DSM T&D Effic.
2010 - - - - - 12 1
2011 - - - - - 12 1
2012 - - - - - 12 1
2013 - - 150 - - 12 1
2014 - - - 1 - 14 1
2015 - - - 1 - 14 -
2016 - - - - - 15 -
2017 - - - 1 - 15 -
2018 - - - - - 15 -
2019 - - - - - 17 -
2020 250 - 150 - - 17 -
2021 - - - 2 - 18 -
2022 - - - - - 18 -
2023 - - 50 - - 20 -
2024 - - - - - 20 -
2025 250 - - - - 21 -
2026 - - - - - 21 -
2027 250 - - - - 23 -
2028 - - - - - 23 -
2029 - - - - - 24 -
2010-2019 - - 150 3 - 137 5
2010-2029 750 - 350 5 - 339 5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 514 of 729
11
January Capacity L&R w/ New Resources
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
Existing Resources & Contacts
New Gas CCCT
Conservation
Little/Upper
Falls
Upgrades
Distribution
Efficiencies
Peak Load +
Planning Margin
Peak
Load
Market
Purchases
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 515 of 729
12
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
MW
August Capacity L&R w/ New Resources
Existing Resources & Contacts
New Gas CCCT
Conservation
Little/Upper
Falls
Upgrades
Distribution
Efficiencies
Peak Load +
Planning Margin
Peak
Load
Market
Purchases
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 516 of 729
13
Annual Energy L&R w/ New Resources
0
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
aM
W
Existing Resources & Contacts
New Gas CCCT
Wind (350 MW)
Conservation
Little/Upper
Falls
Upgrades
Distribution
Efficiencies
Avg Load at 80%
Confidence &
Hydro at 80
Percentile
Avg
Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 517 of 729
14
Washington State RPS Compliance
-
20
40
60
80
100
120
140
160
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
aM
W
Reardan
Clark Fork River Upgrades
Spokane River Upgrades
REC Purchase
REC Purchase
Renewable
Requirement
Little/Upper Falls Upgrades
REC Sales
New Wind
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 518 of 729
15
Greenhouse Gas Emissions
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Sh
o
r
t

T
o
n
s

(
T
h
o
u
s
a
n
d
s
)
-
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
0.45
0.50
CO
2

T
o
n
s

p
e
r

M
W
h
Total Resources
Existing Resources
Tons per MWh of Load
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 519 of 729
16
Total Cost of Carbon Legislation
$-
$50
$100
$150
$200
$250
$300
$350
$400
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Mi
l
l
i
o
n
s

(
2
0
0
9
$
)
100% Allocation
80% Allocation
60% Allocation
40% Allocation
20% Allocation
0% Allocation
Drivers of Higher Costs:
•Reduction in Colstrip energy
•Higher electric market prices
•Higher natural gas prices
•Potential to be 30% of Power Costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 520 of 729
17
Portfolio Cost Duration Curve (2009$)
$-
$0.5
$1.0
$1.5
$2.0
$2.5
$3.0
$3.5
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%
In
c
r
e
m
e
n
t
a
l

P
o
w
e
r

S
u
p
p
l
y

E
x
p
e
n
s
e

(
B
i
l
l
i
o
n
s
)
2020
2015
2010
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 521 of 729
Scenarios
James Gall & John Lyons
2009 Electric Integrated Resource Plan
Fifth Technical Advisory Committee Meeting
March 25, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 522 of 729
2
Market Scenarios
Market Futures (Stochastic)
ƒBase Case
ƒNo Carbon Costs
Market Scenarios (Deterministic)
ƒHigh Natural Gas Prices
ƒLow Natural Gas Prices
ƒSolar Saturation (“Buck-a-Watt”)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 523 of 729
3
No Carbon Cost Scenario
Avista Portfolio Cost versus Risk Analysis
Portfolios:
ƒMarket reliance
ƒBuild to capacity requirements
ƒLeast cost strategy
ƒEfficient frontier
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 524 of 729
4
Avista Portfolio Scenarios
Fundamental Changes
ƒNo State RPS
ƒAlternative load forecasts (High/Low)
ƒLeast carbon emissions
Capital Cost Sensitivities
ƒRequired capital cost to build wind in 2010
ƒRequired capital cost to move from CCCT to SCCT
Resource Availability
ƒLarge hydro upgrades, with capital cost sensitivities
ƒOther renewables (Biomass/Geothermal/Hydro Upgrades)
ƒNuclear
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 525 of 729
Market Scenarios
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 526 of 729
6
Malin Natural Gas Prices (Nominal $)
$-
$2
$4
$6
$8
$10
$12
$14
$16
$18
$20
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$
p
e
r

D
t
h
Base Case- Deterministic Base Case- Stochastic
No GHG Reductions- Deterministic No GHG Reductions- Stochastic
Solar Saturation High Gas Prices
Low Gas Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 527 of 729
7
Malin Nominal Levelized Price Forecast (2010-2029)
Scenario $/Dth
Base Case- Deterministic $8.63
Base Case- Stochastic $8.67
No GHG Reductions- Deterministic $7.86
No GHG Reductions- Stochastic $7.87
Solar Saturation $8.63
High Gas Prices $10.52
Low Gas Prices $6.88
2007 IRP Base Case $7.15
2007 Climate Stewardship Act Future $7.15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 528 of 729
8
Mid-Columbia Electric Price Forecasts (2010-2029, Nominal $)
$-
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
$
p
e
r

M
W
h
Base Case- Deterministic Base Case- Stochastic
No GHG Reductions- Deterministic No GHG Reductions- Stochastic
Solar Saturation High Gas Prices
Low Gas Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 529 of 729
9
Mid-Columbia Nominal Levelized Price Forecast
Scenario $/MWh
Base Case- Deterministic $86.36
Base Case- Stochastic $93.74
No GHG Reductions- Deterministic $63.93
No GHG Reductions- Stochastic $68.22
Solar Saturation $82.87
High Gas Prices $102.61
Low Gas Prices $67.48
2007 IRP Base Case $62.16
2007 Climate Stewardship Act Future $73.50
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 530 of 729
10
More on Solar Saturation Scenario
ƒReduce capital cost by 80%
ƒIncreased solar energy in 2029 from 4,243 aMW to 20,486 aMW
or 75 GW of capacity
ƒReduced Western Interconnect fuel costs by 18% or $10 billion in
2029 or $36.4 billion (PV 2009$)
ƒReduced 2029 power generation greenhouse gas emissions by
10%
ƒSmall reduction in Q2 and Q3 on-peak power prices, although
higher solar saturation rates could further reduce on-peak power
prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 531 of 729
11
Implied Market Heat Rates
6,000
7,000
8,000
9,000
10,000
11,000
12,000
13,000
14,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
bt
u
/
k
w
h

(
(
M
i
d
-
C
/
M
A
L
I
N
-
0
.
0
8
)
/
1
0
0
0
Base Case- Deterministic Base Case- Stochastic No GHG Reductions
Solar Reliance High Gas Prices Low Gas Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 532 of 729
12
Mid-Columbia Levelized Price (2010-2029) Duration Curve
$-
$50
$100
$150
$200
$250
0% 10% 20% 30% 40% 50% 60% 70% 80% 90%
$/
M
W
h
Base Case- Stochastic
No GHG Reductions- Stochastic
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 533 of 729
13
Greenhouse Gas Prices ($/Ton)
$-
$20
$40
$60
$80
$100
$120
$140
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
2009 IRP Base Case
No Carbon Costs
Low Gas
High Gas
2007 IRP Base Case
2007 IRP Climate Stew ardship Act Future
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 534 of 729
14
US WECC Greenhouse Gas Levels
250
270
290
310
330
350
370
390
410
430
450
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Mi
l
l
i
o
n
s

o
f

S
h
o
r
t

To
n
s
Base Case- Deterministic
No GHG Reductions
Solar Saturation
High Gas Prices
Low Gas Prices
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 535 of 729
No Carbon Costs Scenario
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 536 of 729
16
$100
$120
$140
$160
$180
$200
$220
$240
$260
$280
$300
2,400 2,600 2,800 3,000 3,200 3,400 3,600
2010-2020 Total Cost NPV
20
2
0

S
t
a
n
d
a
r
d

D
e
v
i
a
t
i
o
n
No Carbon Costs Scenario
Base Case
Efficient Frontier
No Carbon Costs
Efficient Frontier
Market
Reliance
Capacity
Only
Least
Cost
Strategy
PRS
PRS
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 537 of 729
17
No CO2 Costs: Least Cost Strategy (MW)
Year CCCT SCCT Wind
Hydro
Upgrades
Low
Carbon
Baseload DSM
T&D
Effic.
2010 - - - - - 12 1
2011 - - - - - 12 1
2012 - - - - - 12 1
2013 - - 150 - - 12 1
2014 - - - - - 14 1
2015 - - - - - 14 -
2016 - - - - - 15 -
2017 - - - 1 - 15 -
2018 - - - - - 15 -
2019 - - - 1 - 17 -
2020 - 200 150 - - 17 -
2021 - - - - - 18 -
2022 - - - 2 - 18 -
2023 - 100 50 - - 20 -
2024 - - - - - 20 -
2025 - - - - - 21 -
2026 - 100 - - - 21 -
2027 - 300 - - - 23 -
2028 - - - - - 23 -
2029 - 100 - - - 24 -
2010-2019 - - 150 2 - 137 5
2010-2029 - 800 350 4 - 339 5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 538 of 729
Fundamental Portfolio Changes
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 539 of 729
19
Alternative Load Forecasts (Energy)
1,000
1,100
1,200
1,300
1,400
1,500
1,600
1,700
1,800
1,900
2,000
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
aM
W
Base Load
High Load
Low Load
1.6%
2.6%
0.6%
AAGR
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 540 of 729
20
High Load Least Cost Strategy (MW)
Year CCCT SCCT Wind
Hydro
Upgrades
Low
Carbon
Baseload DSM
T&D
Effic.
2010 - - - - - 12 1
2011 - - - - - 12 1
2012 - 60 - - - 14 1
2013 - - 200 - - 14 1
2014 - 100 - 1 - 15 1
2015 - - - 1 - 15 -
2016 - - - - - 17 -
2017 - - - 1 - 17 -
2018 - 100 - - - 18 -
2019 - - - - - 18 -
2020 - 100 200 - - 20 -
2021 250 - - 2 - 20 -
2022 - - - - - 21 -
2023 - - 50 - - 23 -
2024 - - - - - 23 -
2025 250 - 50 - - 24 -
2026 - - - - - 26 -
2027 500 - - - - 27 -
2028 - - 50 - - 29 -
2029 - - - - - 29 -
2010-2019 - 260 200 3 - 150 5
2010-2029 1,000 360 550 5 - 389 5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 541 of 729
21
Low Load Least Cost Strategy (MW)
Year CCCT SCCT Wind
Hydro
Upgrades
Low
Carbon
Baseload DSM
T&D
Effic.
2010 - - - - - 12 1
2011 - - - - - 12 1
2012 - - - - - 12 1
2013 - - 150 - - 12 1
2014 - - - 1 - 14 1
2015 - - - 1 - 14 -
2016 - - - - - 15 -
2017 - - - 1 - 15 -
2018 - - - - - 15 -
2019 - - - - - 17 -
2020 - - 100 - - 17 -
2021 - - - - - 18 -
2022 - - - - - 18 -
2023 - - - - - 20 -
2024 - - - - - 20 -
2025 - - - - - 21 -
2026 250 - - - - 21 -
2027 - - - - - 23 -
2028 - 100 - - - 23 -
2029 - - - 2 - 24 -
2010-2019 - - 150 3 - 137 5
2010-2029 250 100 250 5 - 339 5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 542 of 729
22
Least Avista Greenhouse Gas Emissions Scenario
ƒModel selected small renewable and hydro upgrades, simple
cycle gas turbines and low carbon emitting resource
(nuclear/carbon sequestration)
ƒWind resources reduce Western Interconnect emissions, but
likely would not significantly reduce Avista’s greenhouse gas
emissions
ƒCarbon reductions could be from retiring resources such as
Colstrip and Coyote Springs 2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 543 of 729
Capital Cost Sensitivities
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 544 of 729
24
Wind Capital Cost Sensitivity
Starting Point: 150 MW Wind by December 31, 2012
ƒ50 MW Reardan ($2,423 per kW) [2009$: $2,262]
ƒ100 MW Generic Wind ($2,513 kW) [2009$: $2,183]
– Assumes Avista can only take advantage of 90% of tax credit
beginning in 2011, due to not enough tax liability
Scenario: At what capital cost does PRiSM select Reardan earlier?
– Model selected Reardan in 2010, if capital costs are less
than $1,877 per kW [2009$: $1,832]
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 545 of 729
25
CCCT Capital Cost Sensitivity
Starting Point: 250 MW CCCT beginning January 1, 2020
ƒGeneric CCCT ($1,949 per kW) [2009$: $1,461]
Scenario: At what price is CCCT no longer preferred on a least
cost basis, if SCCT cost remain equal.
– If cost are above ($2,051 per kW) [2009$: $1,535] the least cost
strategy includes 300MW of LMS 100 in 2020-21
– Although, the 2020 standard deviation of power supply
expense increases by 3.5%
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 546 of 729
Resource Availability Scenarios
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 547 of 729
27
Large Hydro Upgrades
ƒBase Case does not include Cabinet Gorge Unit 5 or Long Lake
2nd PH/Unit 5 as options.
ƒThese units were not considered options at this time, due to
cost uncertainty.
ƒAssumption (2009$):
- Cabinet Gorge 5: $1,478 kW- Long Lake U5: $2,168 kW- Long Lake 2nd PH: $2,000 kW
This analysis first allows these units to be available at estimated
costs, then studies how cost change impacts the PRS.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 548 of 729
28
Least Cost Strategy: With Large Hydro Options (MW)
Year CCCT SCCT Wind
Hydro
Upgrades
Low
Carbon
Baseload DSM T&D Effic.
2010 - - - - - 12 1
2011 - - - - - 12 1
2012 - - - - - 12 1
2013 - - 150 - - 12 1
2014 - - - 1 - 14 1
2015 - - - 1 - 14 -
2016 - - - - - 15 -
2017 - - - 1 - 15 -
2018 - - - - - 15 -
2019 - - - - - 17 -
2020 - 100 100 60 - 17 -
2021 250 - - - - 18 -
2022 - - - - - 18 -
2023 - - 50 - - 20 -
2024 - - - - - 20 -
2025 - - - - - 21 -
2026 - - - - - 21 -
2027 400 - - - - 23 -
2028 - - - - - 23 -
2029 - - - 2 - 24 -
2010-2019 - - 150 3 - 137 5
2010-2029 650 100 300 65 - 339 5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 549 of 729
29
Least Cost Strategy With Cabinet 4 and Long Lake 2nd PH (MW)
Year CCCT SCCT Wind
Hydro
Upgrades
Low
Carbon
Baseload DSM T&D Effic.
2010 - - - - - 12 1
2011 - - - - - 12 1
2012 - - - - - 12 1
2013 - - 150 - - 12 1
2014 - - - 1 - 14 1
2015 - - - 61 - 14 -
2016 - - - - - 15 -
2017 - - - 1 - 15 -
2018 - - - - - 15 -
2019 - - - - - 17 -
2020 - - 100 60 - 17 -
2021 250 - - - - 18 -
2022 - - - - - 18 -
2023 - - 50 - - 20 -
2024 - - - - - 20 -
2025 - - - - - 21 -
2026 - - - - - 21 -
2027 400 - - - - 23 -
2028 - - - - - 23 -
2029 - - - 2 - 24 -
2010-2019 - - 150 63 - 137 5
2010-2029 650 - 300 125 - 339 5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 550 of 729
30
Large Hydro Upgrade Capital Cost Analysis
Long Lake 2nd Powerhouse is favored by PRiSM, due to larger
capacity size and similar cost per MWh
- The plant is selected as least cost resource until the cost
reaches $2,150 kW
Cabinet Gorge U5 is not selected as a least cost resource, due to
low capacity factor, if costs were less than $1,100 per kW, the plant
would be selected
While these resources have capital cost uncertainty, they are a
viable alternative to reduce carbon emissions
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 551 of 729
31
Non-Wind Renewable Resources Available
$180
$200
$220
$240
$260
$280
$300
3,300 3,400 3,500 3,600 3,700 3,800 3,900
2010-2020 Total Cost NPV
20
2
0

S
t
a
n
d
a
r
d

D
e
v
i
a
t
i
o
n
Non-wind renewables:
- May lower cost
-May lower annual cost volatility
-But, are resources available at these costs?
Base Case
Efficient Frontier
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 552 of 729
32
Least Cost Strategy- Small Renewables Available (MW)
Year CCCT SCCT Wind
Non-Wind
Renewable
Hydro
Upgrades
Low
Carbon
Baseload DSM T&D Effic.
2010 - - - - - - 12 1
2011 - - - - - - 12 1
2012 - - - 10 - - 12 1
2013 - - 100 5 - - 12 1
2014 - - - 5 1 - 14 1
2015 - - - - - - 14 -
2016 - - - - 1 - 15 -
2017 - - - - 1 - 15 -
2018 - - - 5 - - 15 -
2019 - - - - - - 17 -
2020 - 100 100 7 2 - 17 -
2021 250 - - - - - 18 -
2022 - - - - - - 18 -
2023 - - - - - - 20 -
2024 - - 50 - - - 20 -
2025 - - - - - - 21 -
2026 - - - - - - 21 -
2027 400 - - - - - 23 -
2028 - - - - - - 23 -
2029 - - - - - - 24 -
2010-2019 - - 100 25 3 - 137 5
2010-2029 650 100 250 32 5 - 339 5
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 553 of 729
33
Nuclear
If Nuclear was allowed as a resource beginning in 2020 at a 2009$
capital cost of $5,500 per kW in 250 MW sizes.
ƒAt this cost it would not be selected in the Least Cost Strategy.
ƒAlthough, if costs were $3,800 per kW the resource would be
selected
ƒIf Avista were to acquire the plant in 100MW quantities it would
be least cost at $4,000 per kW.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 554 of 729
34
Capital Expense in Billions Dollars (Nominal 2010-29)
$-
$2
$4
$6
$8
$10
$12
$14
Pref
e
r
r
e
d Re
s
o
u
r
c
e

S
t
r
a
t
e
gy
Base Ca
se- M
a
r
k
e
t
Re
liance
High Lo
a
d
-
LCS
Low Load- LCS
No RP
S
-

L
C
S
Large Hy
dro Available- LCS
LCS

+

Cabin
e
t

#5
Least CO
2 (no

r
e
t
ire)
Least CO2 (w/
r
e
tire)
LCS a
l
l
o
w

o
t
h
e
r
ren
e
w
a
b
l
e
s
No CO2 Cost (PR
S
)
No CO
2

C
o
s
t

(
L
CS)
No CO
2 Co
st (Market Reliance)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 555 of 729
35
$4,000
$4,500
$5,000
$5,500
$6,000
$6,500
$7,000
$7,500
$8,000
$8,500
$9,000
Prefe
rred Resou
rce Strate
g
y
Base Ca
s
e
-
Mark
e
t

R
e
l
i
a
n
c
e
High Load- LCS
Low Load- LCS
No R
P
S
-

L
C
S
Large

H
y
dro Avai
l
a
b
le- LCS
LCS

+
Cab
i
net #5
Least CO2 (no retire)
Least C
O2 (w/ re
t
i
r
e
)
LCS

a
l
low o
ther renewables
No CO
2 Co
st (PRS)
No C
O
2

C
o
st (LCS)
No CO2 Cost (Market Relian
ce)
PV
R
R

2
0
1
0
-
2
9
(M
i
l
l
i
o
n
s
)
$-
$50
$100
$150
$200
$250
$300
$350
$400
20
2
0

S
t

D
e
v

(
M
i
l
l
i
o
n
s
)
Portfolio Cost/Risk Comparison
PVRR
Standard Deviation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 556 of 729
36
Avista Greenhouse Gas Emissions (2029)
- 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500
Preferred Resource Strategy
Base Case- Market Reliance
High Load- LCS
Low Load- LCS
No RPS- LCS
Large Hydro Available- LCS
LCS + Cabinet #5
Least CO2 (no retire)
Least CO2 (w/ retire)
LCS allow other renewables
No CO2 Cost (PRS)
No CO2 Cost (LCS)
No CO2 Cost (Market Reliance)
Greenhouse Gas (Thousands Tons)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 557 of 729
2009 IRP Topics
John Lyons
2009 Electric Integrated Resource Plan
Fifth Technical Advisory Committee Meeting
March 25, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 558 of 729
2
Executive Summary
ƒResource needs
ƒModeling and results
ƒElectricity and natural gas market price forecasts
ƒDemand side management
ƒPreferred Resource Strategy
ƒEnvironmental issues
ƒAction items
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 559 of 729
3
Introduction & Stakeholder Involvement
ƒIRP process
ƒPublic involvement
ƒ2009 IRP chapter overview
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 560 of 729
4
Loads and Resources
ƒEconomic forecast
ƒLoad forecast
ƒForecast scenarios
ƒOverview of current resources
ƒPlanning margins and resource requirements
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 561 of 729
5
Demand Side Management
ƒOverview of DSM programs
– Historical
– Residential
– Commercial and Industrial
ƒDSM programs for 2009 IRP
– Programs considered
– Analytics
– DSM business plan and future commitments
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 562 of 729
6
Environmental Issues
ƒEnvironmental initiatives and policies
ƒAvista’s Climate Change Committee
ƒState and federal renewable portfolio standards
issues
ƒState and federal greenhouse gas legislation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 563 of 729
7
Transmission & Distribution Planning
ƒOverview of Avista’s transmission system
ƒRegional transmission issues
ƒTransmission cost estimates
ƒDistribution efficiency projects
ƒTransmission efficiency projects
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 564 of 729
8
Modeling Approach
ƒMarket modeling
ƒKey assumptions and inputs
– Hydro
– Fuel prices: coal and natural gas
– Emissions: SO2 , NOx and greenhouse gases
– Risk modeling
– Resource alternatives
ƒPRiSM model
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 565 of 729
9
Market Modeling Results
ƒBase Case
ƒMarket Scenarios
ƒPortfolio Scenarios
– Fundamental changes
– Capital cost sensitivities
– Resource availability
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 566 of 729
10
Preferred Resource Strategy
ƒ2009 Preferred Resource Strategy
ƒComparisons with prior plans
ƒPortfolio strategies and performance across
scenarios
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 567 of 729
11
2009 IRP Action Items
ƒProgress on 2007 IRP Action Items
ƒ2009 Action Items
– Renewables
– DSM
– Greenhouse gas issues
– Modeling and forecasting enhancements
– Transmission planning
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 568 of 729

Avista’s 2009 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 6 Agenda
June 24, 2009

Topic Time Staff
1. Introductions 10:00 Storro
2. IRP Section Highlights 10:05 Kalich
3. Preferred Resource Strategy 10:30 Gall
4. Lunch 11:30

5. Preferred Resource Strategy 12:30 Kalich/Gall

6. IRP Action Items 1:30 Lyons

7. Adjourn 2:00

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 569 of 729
Draft Chapter Highlights

Loads & Resources
ƒ Weak economic growth is expected until 2011 in the service territory.
ƒ Historic conservation acquisitions are included in the load forecast; higher
acquisition levels anticipated in this IRP reduce the load forecast further.
ƒ Annual electricity sales growth from 2010-2020 averages 1.6 percent over the
next decade (199 aMW) and 1.8 percent over the entire 20-year forecast.
ƒ Peak loads are expected to grow at 1.6 percent annual rate over the next 10
years (312 MW) and also 1.6 percent over the entire 20-year forecast.
ƒ Avista’s resource deficits begin 2018; without conservation resources deficits
would begin in 2016.
ƒ Capacity deficiencies now are the predominate driver of resource need.

Energy Efficiency
ƒ Avista has offered conservation programs for over 30 years.
ƒ The Company has acquired 138.5 aMW of electric-efficiency in the past three
decades; an estimated 109 aMW is still in service, reducing overall load by
approximately 10 percent.
ƒ 20,000 additional customers heat their homes with natural gas today because
of Avista’s first fuel-switching program.
ƒ The Company has developed and maintains the infrastructure necessary to
respond quickly to an energy efficiency ramp-up if another energy crisis or
opportunity occurs.
ƒ Approximately 3,000 concepts were evaluated by Avista’s demand-side
management analysts for the 2009 IRP.
ƒ 7 aMW of local and 2.9 aMW of regional conservation is expected in 2010
ƒ Conservation additions provide 26 percent of new supplies through 2020.
ƒ 2009 IRP includes 0.3 aMW (3.3%) more annual conservation acquisition
than 2007 plan, building on a 50% increase in the 2005 and another 25% in
the 2007 IRP.

Transmission & Distribution
ƒ Avista has completed a $130 million transmission improvement project.
ƒ Avista has over 2,200 miles of high voltage transmission.
ƒ Avista remains actively involved in regional transmission planning efforts.
ƒ The cost of selected new transmission lines and upgrades are included in the
2009 Preferred Resource Strategy.
ƒ 2.7 aMW of distribution efficiencies are included in this IRP.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 570 of 729

Generation Resource Options
ƒ Only resources with well known costs were considered in the PRS analysis, other
resources were studied in sensitivities.
ƒ Federal tax credits were extended to 1/1/2013 for wind and 1/1/2014 for non-
wind renewables with a choice of the PTC ($20/mwh or 30% ITC)
ƒ Large hydro upgrades at Long Lake and Cabinet Gorge are not considered as
new resources, but will be further studied for inclusion in the 2011 IRP analysis.
ƒ Small hydro upgrades and wood fired upgrades were considered in this IRP.
ƒ Solar is included as resource option for this first time.

Market Analysis
ƒ Mid-Columbia electric and Malin natural gas prices are 27 and 20 percent higher
than the 2007 IRP, primarily due to carbon legislation impacts
ƒ Mid-Columbia electric prices are expected to be $79.56 per megawatt-hour over
the next 20 years
ƒ Malin natural gas prices are expected to be $7.36 per decatherm over the next
20 years
ƒ Gas-fired resources continue to serve most new loads and take the place of coal
generation to reduce greenhouse gas emissions
ƒ Future carbon credit prices will depend on reduction goals and the differential
between natural gas and coal prices
ƒ Carbon legislation increases total fuel expenses in the Western Interconnect by
over 16 percent

Preferred Resource Strategy
ƒ Avista’s physical energy needs begin in 2018; capacity needs begin in 2016.
ƒ Near-term resource acquisitions are driven by pending environmental regulation
and risk reduction.
ƒ The first supply-side resource acquisitions are 150 MW of wind by 2012.
ƒ Conservation additions provide 26 percent of new supplies through 2020.
ƒ A 250 MW natural gas-fired combined cycle project is required by 2020.
ƒ Large hydro upgrades have the potential to change the preferred resource mix.
ƒ The 2020 CCCT acquisition could be moved forward to as soon as 2015 without
a significant impact on the preferred resource strategy.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 571 of 729
Draft Action Items Highlights

Resource Additions & Analysis
ƒ Continue to explore the potential for wind and non-renewable resources.
ƒ Issue an RFP for turbines at Reardan and up to 100 MW of wind or other
renewables in 2009.
ƒ Finish studies regarding the costs and environmental benefits of the large
hydro upgrades at Cabinet Gorge, Long Lake, Post Falls, and Monroe Street.
ƒ Study potential locations for the natural gas fired resource identified to be on-
line between 2015 and 2020.

Demand Side Management
ƒ Pursue American Reinvestment and Recovery Act funding and its affect on
the amount of low income weatherization.
ƒ Analyze and report on the results of the July 2007 through December 2009
demand response pilot in Moscow and Sandpoint.

Environmental Policy
ƒ Continue to study the potential impact of state and federal climate change
legislation.
ƒ Continue and report on the work of Avista’s Climate Change Committee.

Modeling and Forecasting Enhancements
ƒ Refine the stochastic model for cost driver relationships.
ƒ Continue to refine the PRiSM model.
ƒ Continue developing Loss of Load Probability and Sustained Peaking
analysis for inclusion in the IRP process

Transmission Planning
ƒ Work to maintain/retain existing transmission rights on the Company’s
transmission system, under applicable FERC policies, for transmission
service to bundled retail native load.
ƒ Continue involvement in BPA transmission practice processes and rate
proceedings to minimize costs of integrating existing resources outside of the
company’s service area.
ƒ Continue participation in regional and sub-regional efforts to establish new
regional transmission structures (ColumbiaGrid and other forums) to facilitate
long-term expansion of the regional transmission system.
ƒ Evaluate costs to integrate new resources across Avista’s service territory
and from regions outside of the Northwest.
ƒ Further study and implement distribution feeder rebuild projects to reduce
system losses.
ƒ Study transmission re-configurations to economical reduce system losses.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 572 of 729
2009 IRP
Preferred Resource Strategy
2009 Electric Integrated Resource Plan
Sixth Technical Advisory Committee Meeting
June 24, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 573 of 729
2
L&R Balances
Load is net 2007 Conservation Levels

(1,000)
(800)
(600)
(400)
(200)
-
200
400
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Winter Capacity
Summer Capacity
Annual Energy
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 574 of 729
3
Preferred Resource Strategy Approach
Least Cost Strategy that meets
1. Capacity Needs
2. Energy Needs
3. RPS Requirements
4. Conservation Requirements
5. Emissions Regulation
6. Actionable
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 575 of 729
4
Flexible Strategy
Preferred Resource Strategy Large Hydro Upgrades
Are Cost Effective
Non-Wind Renewables
Become Abundant
Is Nuclear a Solution
Load Growth Rate Changes
Capital Costs Change
But, what if?
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 576 of 729
5
Conceptual Efficient Frontier
Cost
Ri
s
k
Least Cost
Least Risk
PRSIn
v
a
l
i
d

P
o
r
t
f
o
l
i
o
s
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 577 of 729
6
Efficient Frontier
$150
$170
$190
$210
$230
$250
$270
$290
3,300 3,350 3,400 3,450 3,500 3,550 3,600
2010-2020 PV of Power Supply Cost
20
2
0

S
t
a
n
d
a
r
d

D
e
v
i
a
t
i
o
n

P
o
w
e
r

S
u
p
p
l
y

C
o
s
t
Capacity Only
Least Cost
Least Risk
Efficient Frontier
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 578 of 729
7
Efficient Frontier Portfolios
-
200
400
600
800
1,000
1,200
1,400
1,600
Least Cost - Mid Range + Least Risk
MW
CCCT T&D Efficiencies
Wind Hydro Upgrades
IGCC Coal IGCC Coal w/ Seq
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 579 of 729
8
2009 Preferred Resource Strategy
Resource
By the End
of Year
Nameplate
(MW)Energy (aMW)
NW Wind 2012 150.0 50.0
Distribution Efficiencies 2010-2015 5.0 2.0
Little Falls 1 2013 1.0 0.3
Little Falls 2 2014 1.0 0.3
Little Falls 4 2016 1.0 0.3
NW Wind 2019 150.0 50.0
CCCT 2019 250.0 225.0
Upper Falls 2020 2.0 1.0
NW Wind 2022 50.0 17.0
CCCT 2024 250.0 225.0
CCCT 2027 250.0 225.0
Conservation All Years 339.0 226.0
Total 1,449.0 1,019.9
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 580 of 729
9
Annual Conservation Acquisition

-
2
4
6
8
10
12
14
16
18
20
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
regional
local
Local
90 aMW over first 10 years
226 aMW over 20 years
Regional
29 aMW over first 10 years
59 aMW over 20 years
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 581 of 729
10
Local Energy Efficiency Targets
Portfolio 2010 Target 2011 Target
Limited Income Residential 1,977,099 2,056,183
Residential 20,518,584 21,339,327
Prescriptive Non-Residential 18,211,396 18,939,852
Site-Specific Non-Residential 24,936,765 25,934,236
Total Local Acquisition (kWh)65,643,844 68,269,598
Local 7.5 7.8
Regional 2.9 2.9
Total Acquisition (aMW)10.4 10.7
Draft NPCC 6th Plan Goal 11.2 12.4
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 582 of 729
11
Rate Base Additions for Capital Expenditures (Millions)
Year Investment Year Investment
2010 4.9 2020 942.1
2011 5.0 2021 10.6
2012 5.1 2022 0.0
2013 278.1 2023 163.3
2014 7.7 2024 0.0
2015 2.3 2025 542.0
2016 0.0 2026 0.0
2017 1.7 2027 0.0
2018 0.0 2028 571.6
2019 0.0 2029 0.0
Totals *
$0.3 billion thru 2019
$2.5 billion thru 2029 **
* Excludes conservation funding
** $1.0 billion NPV @ 8% discount rate
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 583 of 729
12
January Capacity L&R w/ New Resources
MW
-
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Existing Resources Conservation
Distribution Efficiencies Hydro Upgrades
CCCT Wind
Load + Planning Margin
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 584 of 729
13
August Capacity L&R w/ New Resources
MW
-
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Existing Resources Conservation
Distribution Efficiencies Hydro Upgrades
CCCT Wind
Load + Planning Margin
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 585 of 729
14
Annual Energy L&R w/ New Resources
aM
W
-
500
1,000
1,500
2,000
2,500
3,000
3,500
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
Existing Resources Conservation
Distribution Efficiencies Hydro Upgrades
CCCT Wind
Load + Contingency
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 586 of 729
15
-
20
40
60
80
100
120
140
160
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
aM
W
Washington State RPS Compliance
Reardan
50- 100 MW
Clark Fork River Upgrades
Spokane River Upgrades
REC
Purchase
REC Purchase/BankRenewable
Requirement
Little/Upper Falls Upgrades
REC Sales
New Wind
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 587 of 729
16
Power Supply Cost Variation
$-
$200
$400
$600
$800
$1,000
$1,200
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
80% CL Low
Expected Cost
Tail Var 90
80% CL High
Mi
l
l
i
o
n
s

(
N
o
m
i
n
a
l
)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 588 of 729
17
Power Supply Cost Ranges
Present Value (Billions)
0% 20% 40% 60% 80% 100% 120% 140%
80% CL (Low End)
Low Gas Price Forecast
Base Case- Stochastic
Base Case- Deterministic
High Gas Price Forecast
80% CL (High End)
$0.0 $2.0 $4.0 $6.0 $8.0 $10.0
Percent of 20 Year PV
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 589 of 729
18
Avista Generator GHG Emissions

-
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
-
0.05
0.10
0.15
0.20
0.25
0.30
0.35
0.40
New Resources
Existing Resources
Tons per MWh of Load
Mi
l
l
i
o
n

S
h
o
r
t

T
o
n
s
Sh
o
r
t

T
o
n
s

p
e
r

M
W
h

o
f

L
o
a
d
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 590 of 729
19
Total Cost GHG Legislation
Mi
l
l
i
o
n
s

(
N
o
m
i
n
a
l
)
$-
$50
$100
$150
$200
$250
$300
$350
$400
20
1
0
20
1
1
20
1
2
20
1
3
20
1
4
20
1
5
20
1
6
20
1
7
20
1
8
20
1
9
20
2
0
20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
100% Allocation
80% Allocation
40% Allocation
0% Allocation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 591 of 729
20
Future Power Supply Costs
(Index: 2010= 100)

-
50
100
150
200
250
300
20
0
0
20
0
2
20
0
4
20
0
6
20
0
8
20
1
0
20
1
2
20
1
4
20
1
6
20
1
8
20
2
0
20
2
2
20
2
4
20
2
6
20
2
8
Base Case
No CO2 Costs
Actual
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 592 of 729
21
Flexible Strategy
What if large hydro
upgrades are viable?
What if non-wind
renewables are abundant?
Is Nuclear a solution?
What are the impacts
of load growth changes?
What are the tipping points
for key capital costs?
wind capital cost <$1,830/kW, build early
CCCT cost >$1,610/kW, consider SCCT
High: 260/100 MW more gas/wind next 10 years
Low: 250/50 MW less gas/wind in next 10 years
eliminate 50/100 MW of wind/gas over 20 years?
non-wind renewables replace some
wind; could reduce gas by 100 MW
least-cost if <=$4,000/kW (current range $5-$10k)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 593 of 729
22
Schedule
June 22: Internal draft released
June 24: Final Technical Advisory Committee meeting
July 1: “Big Picture” internal comments
July 6: External draft released
July 20: Comment deadline
Aug 31: IRP Filed with Commissions
~April 2010: Begin 2011 IRP Process
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 594 of 729
2009 IRP Action Items
John Lyons
2009 Electric Integrated Resource Plan
Sixth Technical Advisory Committee Meeting
June 24, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 595 of 729
2
2007 IRP Action Items
ƒRenewable Energy
ƒDemand Side Management
ƒEmissions
ƒModeling and Forecasting Enhancements
ƒTransmission Planning
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 596 of 729
3
Renewable Energy
ƒContinue studying wind potential in the Company’s service
territory, possibly including the placement of anemometers at the
most promising wind sites.
ƒCommission a study of Montana wind resources that are
strategically located near existing Company transmission assets
ƒLearn more about non-wind renewable resources to satisfy
renewable portfolio standard requirements and decrease the
Company’s carbon footprint.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 597 of 729
4
Demand Side Management
ƒUpdate processes and protocols for integrating energy efficiency
programs into the IRP to improve and streamline the process.
ƒStudy and quantify transmission and distribution efficiency
concepts.
ƒDetermine the potential impacts and costs of load management
options currently being reviewed as part of the Heritage Project.
ƒDevelop and quantify the long-term impacts of the newly signed
contractual relationship with the Northwest Sustainable Energy
for Economic Development organization.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 598 of 729
5
Emissions
ƒContinue to evaluate the implications of new rules and
regulations affecting power plant operations, most notably
greenhouse gases.
ƒContinue to evaluate the merits of various carbon quantification
methods and emissions markets.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 599 of 729
6
Modeling and Forecasting Enhancements
ƒStudy the potential for fixing natural gas prices through financial
instruments, coal gasification, investments in gas fields, or other
means.
ƒContinue studying the efficient frontier modeling approach to
identify more and better uses for its information.
ƒFurther enhance and refine the PRiSM LP model
ƒContinue to study the impact of climate on the load forecast.
ƒMonitor the following conditions relevant to the load forecast:
large commercial load additions, Shoshone county mining
developments, and the market penetration of electric cars.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 600 of 729
7
Transmission Planning
ƒWork to maintain/retain existing transmission rights on the
Company’s transmission system, under applicable FERC
policies, for transmission service to bundled retail native load.
ƒContinue involvement in BPA transmission practice processes
and rate proceedings to minimize costs of integrating existing
resources outside of the company’s service area.
ƒContinue participation in regional and sub-regional efforts to
establish new regional transmission structures (ColumbiaGrid
and other forums) to facilitate long-term expansion of the regional
transmission system.
ƒEvaluate costs to integrate new resources across Avista’s
service territory and from regions outside of the Northwest.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 601 of 729
8
2009 IRP Action Items
ƒResource Additions and Analysis
ƒDemand Side Management
ƒEnvironmental Policies
ƒModeling and Forecasting Enhancements
ƒTransmission and Distribution Planning
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 602 of 729
9
Resource Additions and Analysis
ƒContinue to explore the potential for wind and non-renewable
resources.
ƒIssue an RFP for turbines at Reardan and up to 100 MW of wind
or other renewables in 2009.
ƒFinish studies regarding the costs and environmental benefits of
the large hydro upgrades at Cabinet Gorge, Long Lake, Post
Falls, and Monroe Street.
ƒStudy potential locations for the natural gas fired resource
identified to be on-line between 2015 and 2020.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 603 of 729
10
Demand Side Management
ƒPursue American Reinvestment and Recovery Act funding
ƒAnalyze and report on the results of the demand response pilot in
Moscow and Sandpoint
ƒProcessing and implementing I-937 requirements
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 604 of 729
11
Environmental Policies
ƒContinue to study the potential impact of state and federal
climate change and renewable portfolio legislation
ƒWestern Climate Initiative
ƒWaxman-Markey – American Clean Energy and Security Act
of 2009
ƒContinue to report on Avista’s Climate Change Committee
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 605 of 729
12
Modeling and Forecasting Enhancements
ƒRefine the stochastic model for cost driver relationships
ƒContinue to refine the PRiSM model
ƒContinue developing Loss of Load Probability and Sustained
Peaking analysis for inclusion in the IRP process
ƒStudy cooling degree day trend coefficient for inclusion in the
load forecast
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 606 of 729
13
Transmission and Distribution Planning
ƒWork to maintain and retain existing transmission rights on
Avista’s transmission system
ƒContinued involvement in BPA transmission processes and rate
proceedings
ƒContinued participation in regional and sub-regional efforts to
establish new regional transmission structures and to facilitate
long-term expansion of the regional transmission system
ƒEvaluate costs to integrate new resources across Avista’s
service territory and from regions outside of the Northwest
ƒStudy and implement distribution feeder rebuild projects
ƒStudy transmission re-configurations to reduce system losses
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 607 of 729
Clint Kalich
Manager of Resource Planning & Power Supply Analyses
[e-mail]
October 21, 2008
Defining Wind Integration &
Overview of Avista Study
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 608 of 729
•Defining Wind Integration
•Overview of Avista’s System
•Evaluating Overall Cost of Wind
•Methodology Overview
•Wind Integration Cost Components
•Impact of Shorter Market Time Step
•Benefit of Wind Feathering
•Hydro Re-Dispatch Costs
•Next Steps/Modeling Enhancements
•Other Wind Integration Study Results
Outline of Presentation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 609 of 729
Defining Wind Integration
•Incremental Reserves (Avista Study Method)
ƒRegulation (<1 minute)
ƒLoad following
−covers timeframe from end of regulation up to next ramp (1 hour in WECC)
ƒForecast error
−difference between forecast and actual generation
•Other Things Sometimes Called Wind Integration
ƒShape of delivered energy
ƒFuel savings from wind operations
ƒCapital costs
ƒEnvironmental attributes
Bottom Line: Be Careful When Assuming 2 Studies are “Apples-to-Apples”
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 610 of 729
Defining Wind Integration — A Graphical View
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 611 of 729
Defining Wind Integration — A Graphical View
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 612 of 729
Defining Wind Integration — A Graphical View
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 613 of 729
Overview of Avista’s System (2010)
•2,200 MW Control Area Peak
•875 MW Minimum Load
•1,200 MW Hydro
ƒVery flexible with generous short-term storage
ƒProvides majority of reserves for wind
–regulation, spinning, supplemental
•785 MW Gas Turbines
ƒ550 MW CCCT with 100 MW of spinning & supplemental reserves
ƒ210 MW (4 units) provide only supplemental reserves
ƒRemaining 7 (small) units cannot provide reserves
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 614 of 729
Overview of Avista’s System, Cont
•230 MW Coal & 50 MW Biomass
ƒDo not provide reserves
•35 MW of Stateline Wind
•~750 MW Contracts Rights
ƒ350 MW for “native load”
ƒ400 MW 3rd party resources to serve 3rd party loads in control area
ƒNo reserve capabilities
•~200 MW Capacity Contract Obligations
ƒSales of AGC and spinning reserves for 3rd party load and wind
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 615 of 729
Evaluating Overall Cost of Wind
•Commodity Value of Energy
ƒConsider hourly pattern
ƒWind doesn’t generate flat or at the operator’s control
•Transmission Cost ~ 3 Times Traditional Resources
•Impact on Operation of Other Owned Resources
ƒFuel savings and/or impact on market sales & purchases
•Incremental Reserve Obligations
ƒAvista definition of wind integration
ƒRegulation, load following, forecast error
−load following and forecast error are greatly affected by spot market timeframe
•Capital Recovery and Operation Costs
•Environmental Attribute Values (green tags, reduced CO2)
•Capacity Contribution (or lack thereof)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 616 of 729
Methodology Overview
•Develop Hourly LP Model Of Avista System
ƒModel of both Real-Time and Pre-Schedule timeframes
–pre-schedule commitment and market transactions “honored” in Real-Time
ƒRepresent inherent flexibility and constraints
–hydro storage and minimum flow
–minimum up/down requirements
–reserve capabilities and ramping rates
–transmission paths
–hydro spill and wind “feathering”
ƒAccess to energy market for balancing and optimization
–pre-schedule and real-time markets
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 617 of 729
Methodology Overview (Cont.)
•Run Model With and Without Wind Variability
ƒOver same historical timeframe (2002-04)
–using actual loads
–wind is priced in each hour at market
–eliminates potential for wind shape to bias result
–carry additional reserves in “With Wind” case
•Compare System Values
ƒChange is spread over wind deliveries to arrive at an integration cost
–per MWh (absolute or % of market price)
–per kW-month (absolute or % of market price)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 618 of 729
Pre-Schedule Wind Model Delivery Schematic
Generation Summary
Resource Power Res Modeled Hour
Noxon 402 152 2
Cabinet 236 0
Spokane 163 N/A
Kettle Falls 50 N/A
Colstrip 222 N/A Load
Boulder 0 N/A Boulder Park 801 MW Noxon
Rathdrum 0 24 0 MW 402 MW
NE 0 0 Spokane River 152 R
Total Wind 103 N/A Kettle Falls 163 MW 98 SPL
Mid-C Hy 138 0 50 MW -44 MW
CS2 0 0 SP Contracts Cab Gorge
LT Purch 334 N/A KFalls CT 209 MW 236 MW
Total 1,648 176 0 MW 0 R
Feathered 0 540 SP Wind 168 SPL
0 MW
Mid-C Market
0 MW Rathdrum 0 MW
103 0 MW 0 R
103 MW 24 R
0 FTR
138 MW 125 MW 0 MW
0 R 0 0 FTR 0 MW
0 SPL 0 FTR
0
-803 MW 0
MW
0 0 MW
0 R

222
Contracts Wind
Northeast
Hydro
Market
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 619 of 729
0.00 2.00 4.00 6.00 8.00 10.00
100 MW
C.Basin
200 MW 50/50
Mix
400 MW
Div ersified
600 MW
Div ersified
$/
M
W
h
W ind Shape Regulation
Load Following Forecast Error
Wind Integration Cost Components
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 620 of 729
-
1.00
2.00
3.00
4.00
5.00
6.00
7.00
8.00
9.00
10.00
100 MW
C.Basin
200 MW
50/50 Mix
400 MW
Div ersified
600 MW
Div ersified
$/
M
W
h
One Hour
Market
10-Minute
Market
Impact of Shorter Market Time Step
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 621 of 729
-
2.00
4.00
6.00
8.00
10.00
12.00
100 MW
C. Basin
200 MW
50/50 Mix
400 MW Div erse 600 MW Div erse
$/
M
W
h
$0.28MM
$270/MW h
$3.00MM
$152/MW h
$1.43MM
$165/MW h
$0.80MM
$164/MW h
Benefit of Wind Feathering
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 622 of 729
Hydro Re-Dispatch Costs
30.0%
32.0%
34.0%
36.0%
38.0%
40.0%
42.0%
44.0%
100 MW
C.Basin
200 MW
50/50 Mix
400 MW
Div ersified
600 MW
Div ersified
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 623 of 729
Next Steps/Modeling Enhancements
•Update With Latest Data
ƒAugment limited NW data sets with data from outside the NW
ƒUpdate to data through 2006
ƒUse NPCC/BPA 3-Tier meso-scale wind data when available
•Evaluate Regulation, Load Following, Forecast Errors
Using Root-Mean-Squares Method
•Search For Better Wind Forecasting Algorithms
•Enhance Start-Up Cost Logic For Thermal Plants
•Model Reserve Capabilities of Coal-Fired Plants
•Evaluate Real-Time to Pre-Schedule Relationships
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 624 of 729
Other Integration Study Results
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 625 of 729
The End
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 626 of 729
Clint Kalich
Manager of Resource Planning & Power Supply Analyses
[e-mail]
May 22, 2009
Defining Wind Integration in the
2009 Integrated Resource Plan
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 627 of 729
Agenda
10:00 Introductions
10:15 Wind Integration and the 2009 IRP
11:15 Questions/Suggestions for Further Work
12:00 Adjourn
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 628 of 729
Defining Wind Integration and Its Costs
2009 Integrated Resource Plan
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 629 of 729
•Defining Wind Integration
•Wind Integration Cost Components
•Preferred Resource Strategy Model (PRiSM)
ƒWhat is PRiSM?
ƒThe Efficient Frontier
−

covers timeframe from end of regulation up to next ramp (1 hour in WECC)
ƒWind modeling in 2009 IRP
ƒRecent enhancements to PRiSM
•Questions
Outline of Presentation
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 630 of 729
Defining Wind Integration
•

Incremental Reserves (Avista Study Method)
ƒRegulation (<1 minute)
ƒLoad following
−

covers timeframe from end of regulation up to next ramp (1 hour in WECC)
ƒForecast error
−

difference between forecast and actual generation
•

Other Things Sometimes Called Wind Integration
ƒShape of delivered energy
ƒFuel savings from wind operations
ƒCapital costs
ƒEnvironmental attributes
Bottom Line: Be Careful When Assuming 2 Studies are “Apples-to-Apples”
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 631 of 729
Defining Wind Integration — A Graphical View
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 632 of 729
Defining Wind Integration — A Graphical View
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 633 of 729
Defining Wind Integration — A Graphical View
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 634 of 729
0.00 2.00 4.00 6.00 8.00 10.00
100 MW
C.Basin
200 MW 50/50
Mix
400 MW
Div ersified
600 MW
Div ersified
$/
M
W
h
W ind Shape Regulation
Load Following Forecast Error
Wind Integration Cost Components
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 635 of 729
PRiSM
(Preferred Resource Strategy Model)
2009 Integrated Resource Plan
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 636 of 729
What is PRiSM?
ƒPreferred Resource Strategy Model
– Selects resource & conservation opportunities on an optimal cost
and risk basis using a linear program (What’s Best!)
ƒObjective function is to either select resource strategies to meet
our energy/capacity/market/RPS/CO2 requirements on a least
cost and/or least risk basis
ƒCost is measured by the present value of incremental fuel &
O&M expenses and new capital investment
ƒRisk is measured by the variation in fuel, emissions, load, wind,
forced outages, and variable O&M expenses in years 2019/29
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 637 of 729
Efficient Frontier- An Introduction 1 (stock portfolios)
Ri
s
k
Expected Return
Stocks
Bonds
T-Bills
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 638 of 729
Efficient Frontier- An Introduction (Avista IRP)
Present Value of Cost
Ma
r
k
e
t

R
i
s
k
Nuclear
CCCT
Market/SCCT
Wind
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 639 of 729
Wind Modeling in 2009 IRP
ƒVarious Wind Resource Options
– Small wind (DG)
– Northwest Wind (Tier 1 and Tier 2)
– Montana Wind
– Reardan Wind Project
ƒWind Integration Cost of $3.50 per MWh (2009$)
– Reflective of low penetration rate presently on system
– Rates will rise as penetration increases
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 640 of 729
New Enhancements
ƒConservation measures are selected in model rather than an
input (only measures that are between $xx/MWh & $xxx/MWh)
ƒResources are now added in increments rather than any amount
ƒUse more precise method to estimate frontier curve
ƒMeets both summer & winter capacity requirements
ƒAbility to retire resources
ƒAbility to account for greenhouse gas caps
ƒMore accurate ability to take into account post IRP time period
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 641 of 729
Questions/Open Discussion
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 642 of 729
2009

Electric
Integrated Resource Plan

Appendix B – 2009 Integrated Resource
Planning Work Plan

August 31, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 643 of 729

1
2009 Integrated Resource Planning Work Plan

This Work Plan is provided in response to the WUTC’s Integrated Resource Planning (IRP)
rules (WAC 480-100-238). It outlines the process Avista will follow to develop its 2009
Integrated Resource Plan to be filed with Washington and Idaho Commissions by August 31,
2009. Avista uses a public process to obtain technical expertise and guidance throughout
the planning period through a series of public Technical Advisory Committee (TAC)
meetings. The first of these meetings was held on May 14, 2008.

The 2009 Integrated Resource Plan process will be similar to those used to produce the
previous three published plans. Avista will be using AURORAxmp for electric market
forecasting, resource valuation, and for conducting Monte-Carlo style risk analyses. Results
from AURORAxmp will be used to select the Preferred Resource Strategy using the
proprietary PRiSM 2.0 model. This tool fills future capacity and energy deficits using an
efficient frontier approach to evaluate quantitative portfolio risk versus portfolio cost while
accounting for environmental legislation. Qualitative risk will be evaluated in a separate
analysis. The process to identify the Preferred Resource Strategy is shown in Exhibit 1 and
the process time line is shown in Exhibit 2.

For this plan, Avista intends to use more detailed and site-specific resource assumptions to
be determined by an ongoing process to evaluate renewable, gas, and other supply-side
resources. This plan will also study environmental costs, sustained peaking requirements,
and detailed analyses of demand-side management programs. This IRP will develop a
strategy that meets or exceeds renewable portfolio standards and greenhouse gas
emissions legislation.

It is Avista’s intention to “stress” or test the Preferred Resource Strategy against a variety of
scenarios and stochastic futures. The TAC will be an important factor to determine the
underlying assumptions used in the scenarios and futures. The IRP process is a very
technical and data intensive process; public comments are welcome and will require input in
a timely manner for appropriate inclusion into the process so the plan can be submitted
according to the contemplated schedule.

Tentative timeline for public Technical Advisory Committee meetings:
 May 14, 2008 – Load & resource balance, climate change, loss of load probability
analysis, work plan, and analytical process changes
 August 27, 2008 – Risk and resource assumptions, scenarios and futures, and
demand side management
 October 22, 2008 – Load forecast, electric and gas price forecasts, load & resource
forecast balance, and transmission cost studies
 January 28, 2009 – Review of final modeling and assumptions, and draft PRS
 March 25, 2009 – Review of scenarios and futures, and portfolio analysis
 April 22, 2009 – Review of final PRS and action items
 June 24, 2009 – Review of the 2009 IRP

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 644 of 729

2
2009 Electric IRP Draft Outline

This section provides a draft outline of the major sections in the 2009 Electric IRP. This
outline will be updated as IRP studies are completed and input from the Technical Advisory
Committee has been received.

1. Executive Summary
2. Introduction and Stakeholder Involvement
3. Loads and Resources
a. Economic Conditions
b. Load Forecast
c. Forecast Scenarios
d. Supply Side Resources
e. Reserve Margins
f. Resource Requirements
4. Demand Side Management
5. Environmental Issues
6. Transmission Planning
7. Modeling Approach
a. Assumptions and Inputs
b. Risk Modeling
c. Resource Alternatives
d. The PRiSM Model
8. Market Modeling Approach
a. Futures
b. Scenarios
c. Avoided Costs
9. Preferred Resource Strategy & Stress Analysis
10. Action Items

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 645 of 729

3
Resource Option Analysis

Mark to market all generation and
conservation opportunities

Levelized Cost Calculation

Base Case

Expected Fuel
Prices, Load,
Transmission,
Resources

Develop Capacity
Expansion for
Western
Interconnect

Generate electric
price forecast
Intrinsic resource
market valuation
Preferred Resource Strategy

Given constraints arrives at a least-cost solution defined
in terms of present value of expected power supply
expenses and risk, and generates an efficient frontier
analysis.

Model selects resources and conservation measures to
meet capacity and energy deficits, greenhouse gas
limits, and renewable & conservation portfolio standards

Risk is defined as the variation in power supply
expenses derived from stochastic variables

Market Futures
Stochastic

Load, fuel price, hydro,
wind generation,
emissions, thermal forced
outages.

Market Scenario
Deterministic

Implicit market scenarios
Separate capacity
expansion for each
scenario

AURORAXMP
Exhibit 1: Avista’s 2009 IRP Modeling Process
PRiSM 2.1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 646 of 729

4

Task Target Date
Preferred Resource Strategy (PRS)
Finalize load forecast 7/31/2008
Identify regional resource options for electric market price forecast 8/15/2008
Identify Avista’s supply & conservation resource options 8/31/2008
Update AURORAxmp database for electric market price forecast 9/29/2008
Select natural gas price forecast 9/29/2008
Finalize deterministic base case 10/17/2008
Finalize datasets/statistics variables for risk studies 10/31/2008
Draft transmission study due 10/31/2008
Demand-side management load shapes input into AURORA 10/31/2008
Base case stochastic study complete 11/30/2008
Finalize PRiSM 2.1 model 12/19/2008
Final transmission study due 12/31/2008
Develop efficient frontier & PRS 1/30/2009
Simulation of risk studies “futures” complete 2/10/2009
Simulate market scenarios in AURORAxmp 2/27/2009
Evaluate resource strategies against market futures & scenarios 3/20/2009
Present to TAC preliminary study and PRS 3/31/2009

Writing Tasks
File 2009 integrated resource planning work plan 8/30/2008
Prepare report and appendix outline 9/15/2008
Prepare text drafts 4/15/2009
Prepare charts and tables 4/15/2009
Internal draft released 5/1/2009
External draft released 6/15/2009
Final editing and printing 8/1/2009
Final report distribution 8/30/2009

Exhibit 2: Avista’s 2009 IRP Timeline
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 647 of 729
2009

Electric
Integrated Resource Plan

Appendix C – Residential and Non-residential
Load Profiles

August 31, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 648 of 729
Load Shape Description
1 Res Space Heat
2 Res AC
3 Res Lighting
4 Res Refrigeration
5 Res Water Heating
6 Res Dishwasher
7 Res Washer Dryer
8 Res Misc
9 Res Furnace Fan
10 NonRes Comp Air
11 NonRes Cooking
12 NonRes Space Cooling
13 NonRes Ext Lighting
14 NonRes Space Heating
15 NonRes Water Heating
16 NonRes Int Lighting
17 NonRes Misc
18 NonRes Motors
19 NonRes Office Equipment
20 NonRes Process
21 NonRes Refrigeration
22 NonRes Ventillation
23 Flat
24 NonRes Space Heat/Cool
25 NonRes Space Heat/Cool/Vent
26 NonRes LEED
27 NonRes Refrigerated Warehouses
28 Traffic Signal Red
29 Traffic Signal Green
30 Renewables
31 Multifamily Market Transformation
32 Res Heat/Cool
33 Res Energy Star Homes

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 649 of 729
2009

Electric
Integrated Resource Plan

Appendix D – DSM Concepts Reaching the
Evaluation Stage

August 31, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 650 of 729
Segment Measure
Non-Res Anti-Sweat Heat Controls
Non-Res Auto-Closers for Coolers and Freezers
Non-Res Built-Up HVAC Controls Optimization-Anchor-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Anchor-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Anchor-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Big Box-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Big Box-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Big Box-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-High End-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-High End-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-High End-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Hospital-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Hospital-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Hospital-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-K-12-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-K-12-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-K-12-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Large Off-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Large Off-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Large Off-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Lodging-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Lodging-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Lodging-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Medium Off-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Medium Off-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Medium Off-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-MIniMart-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-MIniMart-GasHt-Retro
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 651 of 729
Non-Res Built-Up HVAC Controls Optimization-Other-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Other-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-OtherHealth-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-OtherHealth-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-OtherHealth-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Other-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Restaurant-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Restaurant-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Restaurant-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Small Box-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Small Box-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Small Box-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Small Off-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Small Off-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Small Off-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Supermarket-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Supermarket-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Supermarket-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-University-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-University-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-University-HtPmpHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Warehouse-ElecHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Warehouse-GasHt-Retro
Non-Res Built-Up HVAC Controls Optimization-Warehouse-HtPmpHt-Retro
Non-Res Controls Commission-New
Non-Res EE Ice Maker from FEMP Baseline
Non-Res EE Reach-In Freezer from E-Star Baseline
Non-Res EE Reach-In Refrigerator from E-Star Baseline
Non-Res EE Vending Machine from Average Baseline
Non-Res EE Vending Machine from E-Star Baseline
Non-Res Evaporative fan controller on walk-in
Non-Res F96T12 to T8HP-Anchor-New-GasHt
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 652 of 729
Non-Res F96T12 to T8HP-Anchor-Retro-ElecHt-PRE1987
Non-Res F96T12 to T8HP-Anchor-Retro-ElecHt-V1987_1994
Non-Res F96T12 to T8HP-Anchor-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Anchor-Retro-GasHt-PRE1987
Non-Res F96T12 to T8HP-Anchor-Retro-GasHt-V1987_1994
Non-Res F96T12 to T8HP-Anchor-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Anchor-Retro-HtPmpHt-PRE1987
Non-Res F96T12 to T8HP-Anchor-Retro-HtPmpHt-V1987_1994
Non-Res F96T12 to T8HP-Anchor-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-Big Box-Retro-ElecHt-V1987_1994
Non-Res F96T12 to T8HP-Big Box-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Big Box-Retro-GasHt-V1987_1994
Non-Res F96T12 to T8HP-Big Box-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Big Box-Retro-HtPmpHt-V1987_1994
Non-Res F96T12 to T8HP-Big Box-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-High End-Retro-ElecHt-V1987_1994
Non-Res F96T12 to T8HP-High End-Retro-GasHt-V1987_1994
Non-Res F96T12 to T8HP-High End-Retro-HtPmpHt-V1987_1994
Non-Res F96T12 to T8HP-Hospital-New-GasHt
Non-Res F96T12 to T8HP-Hospital-Retro-ElecHt-PRE1987
Non-Res F96T12 to T8HP-Hospital-Retro-ElecHt-V1987_1994
Non-Res F96T12 to T8HP-Hospital-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Hospital-Retro-GasHt-PRE1987
Non-Res F96T12 to T8HP-Hospital-Retro-GasHt-V1987_1994
Non-Res F96T12 to T8HP-Hospital-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Hospital-Retro-HtPmpHt-PRE1987
Non-Res F96T12 to T8HP-Hospital-Retro-HtPmpHt-V1987_1994
Non-Res F96T12 to T8HP-Hospital-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-K-12-Retro-ElecHt-V1995_2001
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 653 of 729
Non-Res F96T12 to T8HP-K-12-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-K-12-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-Large Off-Retro-ElecHt-PRE1987
Non-Res F96T12 to T8HP-Large Off-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Large Off-Retro-GasHt-PRE1987
Non-Res F96T12 to T8HP-Large Off-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Large Off-Retro-HtPmpHt-PRE1987
Non-Res F96T12 to T8HP-Large Off-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-Lodging-New-GasHt
Non-Res F96T12 to T8HP-Lodging-Retro-ElecHt-PRE1987
Non-Res F96T12 to T8HP-Lodging-Retro-ElecHt-V1987_1994
Non-Res F96T12 to T8HP-Lodging-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Lodging-Retro-GasHt-PRE1987
Non-Res F96T12 to T8HP-Lodging-Retro-GasHt-V1987_1994
Non-Res F96T12 to T8HP-Lodging-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Lodging-Retro-HtPmpHt-PRE1987
Non-Res F96T12 to T8HP-Lodging-Retro-HtPmpHt-V1987_1994
Non-Res F96T12 to T8HP-Lodging-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-Medium Off-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Medium Off-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Medium Off-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-MIniMart-New-GasHt
Non-Res F96T12 to T8HP-MIniMart-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-MIniMart-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-MIniMart-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-OtherHealth-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-OtherHealth-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-OtherHealth-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-Other-Retro-ElecHt-PRE1987
Non-Res F96T12 to T8HP-Other-Retro-ElecHt-V1987_1994
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 654 of 729
Non-Res F96T12 to T8HP-Other-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Other-Retro-GasHt-PRE1987
Non-Res F96T12 to T8HP-Other-Retro-GasHt-V1987_1994
Non-Res F96T12 to T8HP-Other-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Other-Retro-HtPmpHt-PRE1987
Non-Res F96T12 to T8HP-Other-Retro-HtPmpHt-V1987_1994
Non-Res F96T12 to T8HP-Other-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-Restaurant-New-GasHt
Non-Res F96T12 to T8HP-Restaurant-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Restaurant-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Restaurant-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-Small Box-New-GasHt
Non-Res F96T12 to T8HP-Small Box-Retro-ElecHt-PRE1987
Non-Res F96T12 to T8HP-Small Box-Retro-ElecHt-V1987_1994
Non-Res F96T12 to T8HP-Small Box-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Small Box-Retro-GasHt-PRE1987
Non-Res F96T12 to T8HP-Small Box-Retro-GasHt-V1987_1994
Non-Res F96T12 to T8HP-Small Box-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Small Box-Retro-HtPmpHt-PRE1987
Non-Res F96T12 to T8HP-Small Box-Retro-HtPmpHt-V1987_1994
Non-Res F96T12 to T8HP-Small Box-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-Small Off-New-GasHt
Non-Res F96T12 to T8HP-Small Off-Retro-ElecHt-V1987_1994
Non-Res F96T12 to T8HP-Small Off-Retro-GasHt-V1987_1994
Non-Res F96T12 to T8HP-Small Off-Retro-HtPmpHt-V1987_1994
Non-Res F96T12 to T8HP-Supermarket-New-GasHt
Non-Res F96T12 to T8HP-Supermarket-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Supermarket-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Supermarket-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-University-Retro-ElecHt-PRE1987
Non-Res F96T12 to T8HP-University-Retro-ElecHt-V1995_2001
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 655 of 729
Non-Res F96T12 to T8HP-University-Retro-GasHt-PRE1987
Non-Res F96T12 to T8HP-University-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-University-Retro-HtPmpHt-PRE1987
Non-Res F96T12 to T8HP-University-Retro-HtPmpHt-V1995_2001
Non-Res F96T12 to T8HP-Warehouse-New-GasHt
Non-Res F96T12 to T8HP-Warehouse-Retro-ElecHt-PRE1987
Non-Res F96T12 to T8HP-Warehouse-Retro-ElecHt-V1987_1994
Non-Res F96T12 to T8HP-Warehouse-Retro-ElecHt-V1995_2001
Non-Res F96T12 to T8HP-Warehouse-Retro-GasHt-PRE1987
Non-Res F96T12 to T8HP-Warehouse-Retro-GasHt-V1987_1994
Non-Res F96T12 to T8HP-Warehouse-Retro-GasHt-V1995_2001
Non-Res F96T12 to T8HP-Warehouse-Retro-HtPmpHt-PRE1987
Non-Res F96T12 to T8HP-Warehouse-Retro-HtPmpHt-V1987_1994
Non-Res F96T12 to T8HP-Warehouse-Retro-HtPmpHt-V1995_2001
Non-Res F96T12VHO to T8HP-4-K-12-Retro-ElecHt-PRE1987
Non-Res F96T12VHO to T8HP-4-K-12-Retro-ElecHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-K-12-Retro-GasHt-PRE1987
Non-Res F96T12VHO to T8HP-4-K-12-Retro-GasHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-K-12-Retro-HtPmpHt-PRE1987
Non-Res F96T12VHO to T8HP-4-K-12-Retro-HtPmpHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Large Off-Retro-ElecHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Large Off-Retro-GasHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Large Off-Retro-HtPmpHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Medium Off-Retro-ElecHt-PRE1987
Non-Res F96T12VHO to T8HP-4-Medium Off-Retro-ElecHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Medium Off-Retro-GasHt-PRE1987
Non-Res F96T12VHO to T8HP-4-Medium Off-Retro-GasHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Medium Off-Retro-HtPmpHt-PRE1987
Non-Res F96T12VHO to T8HP-4-Medium Off-Retro-HtPmpHt-V1987_1994
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 656 of 729
Non-Res F96T12VHO to T8HP-4-MIniMart-Retro-ElecHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-MIniMart-Retro-GasHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-MIniMart-Retro-HtPmpHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Small Off-Retro-ElecHt-PRE1987
Non-Res F96T12VHO to T8HP-4-Small Off-Retro-ElecHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Small Off-Retro-GasHt-PRE1987
Non-Res F96T12VHO to T8HP-4-Small Off-Retro-GasHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Small Off-Retro-HtPmpHt-PRE1987
Non-Res F96T12VHO to T8HP-4-Small Off-Retro-HtPmpHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Supermarket-Retro-ElecHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Supermarket-Retro-GasHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Supermarket-Retro-HtPmpHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Warehouse-Retro-ElecHt-PRE1987
Non-Res F96T12VHO to T8HP-4-Warehouse-Retro-ElecHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Warehouse-Retro-GasHt-PRE1987
Non-Res F96T12VHO to T8HP-4-Warehouse-Retro-GasHt-V1987_1994
Non-Res F96T12VHO to T8HP-4-Warehouse-Retro-HtPmpHt-PRE1987
Non-Res F96T12VHO to T8HP-4-Warehouse-Retro-HtPmpHt-V1987_1994
Non-Res Floating Head Pressure Controller
Non-Res Glass Doors on Open Display Cases (LT)
Non-Res Glass Doors on Open Display Cases (MT)
Non-Res INC to CFL-Hospital-New-ElecHt
Non-Res INC to CFL-Hospital-New-GasHt
Non-Res INC to CFL-Hospital-New-HtPmpHt
Non-Res INC to CFL-Hospital-Retro-ElecHt-PRE1987
Non-Res INC to CFL-Hospital-Retro-ElecHt-V1987_1994
Non-Res INC to CFL-Hospital-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-Hospital-Retro-GasHt-PRE1987
Non-Res INC to CFL-Hospital-Retro-GasHt-V1987_1994
Non-Res INC to CFL-Hospital-Retro-GasHt-V1995_2001
Non-Res INC to CFL-Hospital-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-Hospital-Retro-HtPmpHt-V1987_1994
Non-Res INC to CFL-Hospital-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-K-12-New-ElecHt
Non-Res INC to CFL-K-12-New-GasHt
Non-Res INC to CFL-K-12-New-HtPmpHt
Non-Res INC to CFL-K-12-Retro-ElecHt-PRE1987
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 657 of 729
Non-Res INC to CFL-K-12-Retro-ElecHt-V1987_1994
Non-Res INC to CFL-K-12-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-K-12-Retro-GasHt-PRE1987
Non-Res INC to CFL-K-12-Retro-GasHt-V1987_1994
Non-Res INC to CFL-K-12-Retro-GasHt-V1995_2001
Non-Res INC to CFL-K-12-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-K-12-Retro-HtPmpHt-V1987_1994
Non-Res INC to CFL-K-12-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-Large Off-New-ElecHt
Non-Res INC to CFL-Large Off-New-GasHt
Non-Res INC to CFL-Large Off-New-HtPmpHt
Non-Res INC to CFL-Large Off-Retro-ElecHt-PRE1987
Non-Res INC to CFL-Large Off-Retro-ElecHt-V1987_1994
Non-Res INC to CFL-Large Off-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-Large Off-Retro-GasHt-PRE1987
Non-Res INC to CFL-Large Off-Retro-GasHt-V1987_1994
Non-Res INC to CFL-Large Off-Retro-GasHt-V1995_2001
Non-Res INC to CFL-Large Off-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-Large Off-Retro-HtPmpHt-V1987_1994
Non-Res INC to CFL-Large Off-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-Lodging-New-ElecHt
Non-Res INC to CFL-Lodging-New-GasHt
Non-Res INC to CFL-Lodging-New-HtPmpHt
Non-Res INC to CFL-Lodging-Retro-ElecHt-PRE1987
Non-Res INC to CFL-Lodging-Retro-ElecHt-V1987_1994
Non-Res INC to CFL-Lodging-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-Lodging-Retro-GasHt-PRE1987
Non-Res INC to CFL-Lodging-Retro-GasHt-V1987_1994
Non-Res INC to CFL-Lodging-Retro-GasHt-V1995_2001
Non-Res INC to CFL-Lodging-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-Lodging-Retro-HtPmpHt-V1987_1994
Non-Res INC to CFL-Lodging-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-Medium Off-New-ElecHt
Non-Res INC to CFL-Medium Off-New-GasHt
Non-Res INC to CFL-Medium Off-New-HtPmpHt
Non-Res INC to CFL-Medium Off-Retro-ElecHt-PRE1987
Non-Res INC to CFL-Medium Off-Retro-ElecHt-V1987_1994
Non-Res INC to CFL-Medium Off-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-Medium Off-Retro-GasHt-PRE1987
Non-Res INC to CFL-Medium Off-Retro-GasHt-V1987_1994
Non-Res INC to CFL-Medium Off-Retro-GasHt-V1995_2001
Non-Res INC to CFL-Medium Off-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-Medium Off-Retro-HtPmpHt-V1987_1994
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 658 of 729
Non-Res INC to CFL-Medium Off-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-OtherHealth-New-ElecHt
Non-Res INC to CFL-OtherHealth-New-GasHt
Non-Res INC to CFL-OtherHealth-New-HtPmpHt
Non-Res INC to CFL-OtherHealth-Retro-ElecHt-PRE1987
Non-Res INC to CFL-OtherHealth-Retro-ElecHt-V1987_1994
Non-Res INC to CFL-OtherHealth-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-OtherHealth-Retro-GasHt-PRE1987
Non-Res INC to CFL-OtherHealth-Retro-GasHt-V1987_1994
Non-Res INC to CFL-OtherHealth-Retro-GasHt-V1995_2001
Non-Res INC to CFL-OtherHealth-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-OtherHealth-Retro-HtPmpHt-V1987_1994
Non-Res INC to CFL-OtherHealth-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-Other-New-ElecHt
Non-Res INC to CFL-Other-New-GasHt
Non-Res INC to CFL-Other-New-HtPmpHt
Non-Res INC to CFL-Other-Retro-ElecHt-PRE1987
Non-Res INC to CFL-Other-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-Other-Retro-GasHt-PRE1987
Non-Res INC to CFL-Other-Retro-GasHt-V1995_2001
Non-Res INC to CFL-Other-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-Other-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-Restaurant-New-ElecHt
Non-Res INC to CFL-Restaurant-New-GasHt
Non-Res INC to CFL-Restaurant-New-HtPmpHt
Non-Res INC to CFL-Restaurant-Retro-ElecHt-PRE1987
Non-Res INC to CFL-Restaurant-Retro-ElecHt-V1987_1994
Non-Res INC to CFL-Restaurant-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-Restaurant-Retro-GasHt-PRE1987
Non-Res INC to CFL-Restaurant-Retro-GasHt-V1987_1994
Non-Res INC to CFL-Restaurant-Retro-GasHt-V1995_2001
Non-Res INC to CFL-Restaurant-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-Restaurant-Retro-HtPmpHt-V1987_1994
Non-Res INC to CFL-Restaurant-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-Small Off-New-ElecHt
Non-Res INC to CFL-Small Off-New-GasHt
Non-Res INC to CFL-Small Off-New-HtPmpHt
Non-Res INC to CFL-Small Off-Retro-ElecHt-PRE1987
Non-Res INC to CFL-Small Off-Retro-ElecHt-V1987_1994
Non-Res INC to CFL-Small Off-Retro-ElecHt-V1995_2001
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 659 of 729
Non-Res INC to CFL-Small Off-Retro-GasHt-PRE1987
Non-Res INC to CFL-Small Off-Retro-GasHt-V1987_1994
Non-Res INC to CFL-Small Off-Retro-GasHt-V1995_2001
Non-Res INC to CFL-Small Off-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-Small Off-Retro-HtPmpHt-V1987_1994
Non-Res INC to CFL-Small Off-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-University-Retro-ElecHt-PRE1987
Non-Res INC to CFL-University-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-University-Retro-GasHt-PRE1987
Non-Res INC to CFL-University-Retro-GasHt-V1995_2001
Non-Res INC to CFL-University-Retro-HtPmpHt-PRE1987
Non-Res INC to CFL-University-Retro-HtPmpHt-V1995_2001
Non-Res INC to CFL-Warehouse-New-ElecHt
Non-Res INC to CFL-Warehouse-New-GasHt
Non-Res INC to CFL-Warehouse-New-HtPmpHt
Non-Res INC to CFL-Warehouse-Retro-ElecHt-V1995_2001
Non-Res INC to CFL-Warehouse-Retro-GasHt-V1995_2001
Non-Res INC to CFL-Warehouse-Retro-HtPmpHt-V1995_2001
Non-Res INC to CMH-Anchor-Retro-ElecHt-V1987_1994
Non-Res INC to CMH-Anchor-Retro-GasHt-V1987_1994
Non-Res INC to CMH-Anchor-Retro-HtPmpHt-V1987_1994
Non-Res INC to CMH-Big Box-New-ElecHt
Non-Res INC to CMH-Big Box-New-GasHt
Non-Res INC to CMH-Big Box-New-HtPmpHt
Non-Res INC to CMH-Big Box-Retro-ElecHt-V1995_2001
Non-Res INC to CMH-Big Box-Retro-GasHt-V1995_2001
Non-Res INC to CMH-Big Box-Retro-HtPmpHt-V1995_2001
Non-Res INC to CMH-High End-New-ElecHt
Non-Res INC to CMH-High End-New-GasHt
Non-Res INC to CMH-High End-New-HtPmpHt
Non-Res INC to CMH-High End-Retro-ElecHt-PRE1987
Non-Res INC to CMH-High End-Retro-ElecHt-V1987_1994
Non-Res INC to CMH-High End-Retro-ElecHt-V1995_2001
Non-Res INC to CMH-High End-Retro-GasHt-PRE1987
Non-Res INC to CMH-High End-Retro-GasHt-V1987_1994
Non-Res INC to CMH-High End-Retro-GasHt-V1995_2001
Non-Res INC to CMH-High End-Retro-HtPmpHt-PRE1987
Non-Res INC to CMH-High End-Retro-HtPmpHt-V1987_1994
Non-Res INC to CMH-High End-Retro-HtPmpHt-V1995_2001
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 660 of 729
Non-Res INC to CMH-MIniMart-New-ElecHt
Non-Res INC to CMH-MIniMart-New-GasHt
Non-Res INC to CMH-MIniMart-New-HtPmpHt
Non-Res INC to CMH-MIniMart-Retro-ElecHt-PRE1987
Non-Res INC to CMH-MIniMart-Retro-ElecHt-V1987_1994
Non-Res INC to CMH-MIniMart-Retro-ElecHt-V1995_2001
Non-Res INC to CMH-MIniMart-Retro-GasHt-PRE1987
Non-Res INC to CMH-MIniMart-Retro-GasHt-V1987_1994
Non-Res INC to CMH-MIniMart-Retro-GasHt-V1995_2001
Non-Res INC to CMH-MIniMart-Retro-HtPmpHt-PRE1987
Non-Res INC to CMH-MIniMart-Retro-HtPmpHt-V1987_1994
Non-Res INC to CMH-MIniMart-Retro-HtPmpHt-V1995_2001
Non-Res INC to CMH-Small Box-New-ElecHt
Non-Res INC to CMH-Small Box-New-GasHt
Non-Res INC to CMH-Small Box-New-HtPmpHt
Non-Res INC to CMH-Small Box-Retro-ElecHt-V1987_1994
Non-Res INC to CMH-Small Box-Retro-ElecHt-V1995_2001
Non-Res INC to CMH-Small Box-Retro-GasHt-V1987_1994
Non-Res INC to CMH-Small Box-Retro-GasHt-V1995_2001
Non-Res INC to CMH-Small Box-Retro-HtPmpHt-V1987_1994
Non-Res INC to CMH-Small Box-Retro-HtPmpHt-V1995_2001
Non-Res INC to CMH-Supermarket-Retro-ElecHt-PRE1987
Non-Res INC to CMH-Supermarket-Retro-ElecHt-V1987_1994
Non-Res INC to CMH-Supermarket-Retro-GasHt-PRE1987
Non-Res INC to CMH-Supermarket-Retro-GasHt-V1987_1994
Non-Res INC to CMH-Supermarket-Retro-HtPmpHt-PRE1987
Non-Res INC to CMH-Supermarket-Retro-HtPmpHt-V1987_1994
Non-Res INC to CMH-University-New-ElecHt
Non-Res INC to CMH-University-New-GasHt
Non-Res INC to CMH-University-New-HtPmpHt
Non-Res Large MH to T5HO-Big Box-New-ElecHt
Non-Res Large MH to T5HO-Big Box-New-GasHt
Non-Res Large MH to T5HO-Big Box-New-HtPmpHt
Non-Res Large MH to T5HO-Big Box-Retro-ElecHt-PRE1987
Non-Res Large MH to T5HO-Big Box-Retro-ElecHt-V1987_1994
Non-Res Large MH to T5HO-Big Box-Retro-ElecHt-V1995_2001
Non-Res Large MH to T5HO-Big Box-Retro-GasHt-PRE1987
Non-Res Large MH to T5HO-Big Box-Retro-GasHt-V1987_1994
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 661 of 729
Non-Res Large MH to T5HO-Big Box-Retro-GasHt-V1995_2001
Non-Res Large MH to T5HO-Big Box-Retro-HtPmpHt-PRE1987
Non-Res Large MH to T5HO-Big Box-Retro-HtPmpHt-V1987_1994
Non-Res Large MH to T5HO-Big Box-Retro-HtPmpHt-V1995_2001
Non-Res Large MH to T5HO-Other-New-ElecHt
Non-Res Large MH to T5HO-Other-New-GasHt
Non-Res Large MH to T5HO-Other-New-HtPmpHt
Non-Res Large MH to T5HO-Other-Retro-ElecHt-PRE1987
Non-Res Large MH to T5HO-Other-Retro-ElecHt-V1987_1994
Non-Res Large MH to T5HO-Other-Retro-GasHt-PRE1987
Non-Res Large MH to T5HO-Other-Retro-GasHt-V1987_1994
Non-Res Large MH to T5HO-Other-Retro-HtPmpHt-PRE1987
Non-Res Large MH to T5HO-Other-Retro-HtPmpHt-V1987_1994
Non-Res Large MH to T5HO-Warehouse-New-ElecHt
Non-Res Large MH to T5HO-Warehouse-New-GasHt
Non-Res Large MH to T5HO-Warehouse-New-HtPmpHt
Non-Res Large MH to T5HO-Warehouse-Retro-ElecHt-PRE1987
Non-Res Large MH to T5HO-Warehouse-Retro-ElecHt-V1987_1994
Non-Res Large MH to T5HO-Warehouse-Retro-ElecHt-V1995_2001
Non-Res Large MH to T5HO-Warehouse-Retro-GasHt-PRE1987
Non-Res Large MH to T5HO-Warehouse-Retro-GasHt-V1987_1994
Non-Res Large MH to T5HO-Warehouse-Retro-GasHt-V1995_2001
Non-Res Large MH to T5HO-Warehouse-Retro-HtPmpHt-PRE1987
Non-Res Large MH to T5HO-Warehouse-Retro-HtPmpHt-V1987_1994
Non-Res Large MH to T5HO-Warehouse-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T5HO-Other-New-ElecHt
Non-Res Med MH to T5HO-Other-New-GasHt
Non-Res Med MH to T5HO-Other-New-HtPmpHt
Non-Res Med MH to T5HO-Supermarket-New-ElecHt
Non-Res Med MH to T5HO-Supermarket-New-GasHt
Non-Res Med MH to T5HO-Supermarket-New-HtPmpHt
Non-Res Med MH to T8HP-Anchor-New-GasHt
Non-Res Med MH to T8HP-Anchor-Retro-ElecHt-V1987_1994
Non-Res Med MH to T8HP-Anchor-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-Anchor-Retro-GasHt-V1987_1994
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 662 of 729
Non-Res Med MH to T8HP-Anchor-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-Anchor-Retro-HtPmpHt-V1987_1994
Non-Res Med MH to T8HP-Anchor-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-High End-Retro-ElecHt-V1987_1994
Non-Res Med MH to T8HP-High End-Retro-GasHt-V1987_1994
Non-Res Med MH to T8HP-High End-Retro-HtPmpHt-V1987_1994
Non-Res Med MH to T8HP-Hospital-New-GasHt
Non-Res Med MH to T8HP-Hospital-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-Hospital-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-Hospital-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-K-12-Retro-ElecHt-PRE1987
Non-Res Med MH to T8HP-K-12-Retro-ElecHt-V1987_1994
Non-Res Med MH to T8HP-K-12-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-K-12-Retro-GasHt-PRE1987
Non-Res Med MH to T8HP-K-12-Retro-GasHt-V1987_1994
Non-Res Med MH to T8HP-K-12-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-K-12-Retro-HtPmpHt-PRE1987
Non-Res Med MH to T8HP-K-12-Retro-HtPmpHt-V1987_1994
Non-Res Med MH to T8HP-K-12-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-Large Off-Retro-ElecHt-V1987_1994
Non-Res Med MH to T8HP-Large Off-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-Large Off-Retro-GasHt-V1987_1994
Non-Res Med MH to T8HP-Large Off-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-Large Off-Retro-HtPmpHt-V1987_1994
Non-Res Med MH to T8HP-Large Off-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-Medium Off-Retro-ElecHt-V1987_1994
Non-Res Med MH to T8HP-Medium Off-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-Medium Off-Retro-GasHt-V1987_1994
Non-Res Med MH to T8HP-Medium Off-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-Medium Off-Retro-HtPmpHt-V1987_1994
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 663 of 729
Non-Res Med MH to T8HP-Medium Off-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-MIniMart-Retro-ElecHt-V1987_1994
Non-Res Med MH to T8HP-MIniMart-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-MIniMart-Retro-GasHt-V1987_1994
Non-Res Med MH to T8HP-MIniMart-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-MIniMart-Retro-HtPmpHt-V1987_1994
Non-Res Med MH to T8HP-MIniMart-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-OtherHealth-New-GasHt
Non-Res Med MH to T8HP-OtherHealth-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-OtherHealth-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-OtherHealth-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-Other-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-Other-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-Other-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-Small Box-New-GasHt
Non-Res Med MH to T8HP-Small Box-Retro-ElecHt-PRE1987
Non-Res Med MH to T8HP-Small Box-Retro-ElecHt-V1987_1994
Non-Res Med MH to T8HP-Small Box-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-Small Box-Retro-GasHt-PRE1987
Non-Res Med MH to T8HP-Small Box-Retro-GasHt-V1987_1994
Non-Res Med MH to T8HP-Small Box-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-Small Box-Retro-HtPmpHt-PRE1987
Non-Res Med MH to T8HP-Small Box-Retro-HtPmpHt-V1987_1994
Non-Res Med MH to T8HP-Small Box-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-Supermarket-Retro-ElecHt-V1995_2001
Non-Res Med MH to T8HP-Supermarket-Retro-GasHt-V1995_2001
Non-Res Med MH to T8HP-Supermarket-Retro-HtPmpHt-V1995_2001
Non-Res Med MH to T8HP-University-Retro-ElecHt-V1987_1994
Non-Res Med MH to T8HP-University-Retro-GasHt-V1987_1994
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 664 of 729
Non-Res Med MH to T8HP-University-Retro-HtPmpHt-V1987_1994
Non-Res Night Covers for Display Cases - Horizontal
Non-Res Night Covers for Display Cases - Vertical
Non-Res Outdoor Sign Ballast - 24
Non-Res Outdoor Sign Ballast - 24 - Retro
Non-Res Outdoor Sign Ballast - Night
Non-Res Outdoor Sign Ballast - Night - Retro
Non-Res Perimeter Day lighting Controls (Advanced)-New-K-12-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-K-12-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-K-12-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-Large Off-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-Large Off-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-Large Off-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-Medium Off-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-Medium Off-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-Medium Off-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-OtherHealth-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-OtherHealth-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-OtherHealth-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-Small Off-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-Small Off-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-Small Off-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-University-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-University-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-New-University-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-K-12-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-K-12-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-K-12-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-Large Off-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-Large Off-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-Large Off-HtPmpHt
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 665 of 729
Non-Res Perimeter Day lighting Controls (Advanced)-NR-Medium Off-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-Medium Off-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-Medium Off-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-OtherHealth-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-OtherHealth-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-OtherHealth-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-Small Off-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-Small Off-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-Small Off-HtPmpHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-University-ElecHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-University-GasHt
Non-Res Perimeter Day lighting Controls (Advanced)-NR-University-HtPmpHt
Non-Res Replace 12 inch Green Incandescent Left Turn Bay with 12 inchGreen LED module
Non-Res Replace 12 inch Green Incandescent Thru Lane with 12 inch Green LED module
Non-Res Replace 12 inch Red Incandescent Left Turn Bay with 12 inch Red LED module
Non-Res Replace 12 inch Red Incandescent Thru Lane with 12 inch Red LED module
Non-Res Replace 8 inch Red Incandescent Left Turn Bay with 8 inch Red LED module
Non-Res Replace 8 inch Red Incandescent Thru Lane with 8 inch Red LED module
Non-Res Special Doors with Low/No Anti-Sweat Heat
Non-Res Strip Curtains for Walk-in Boxes
Non-Res T12-2 to T8HP-1-Other-Retro-ElecHt-PRE1987
Non-Res T12-2 to T8HP-1-Other-Retro-GasHt-PRE1987
Non-Res T12-2 to T8HP-1-Other-Retro-HtPmpHt-PRE1987
Non-Res T12-3 to T8HP-2-High End-New-GasHt
Non-Res T12-3 to T8HP-2-High End-Retro-ElecHt-V1995_2001
Non-Res T12-3 to T8HP-2-High End-Retro-GasHt-V1995_2001
Non-Res T12-3 to T8HP-2-High End-Retro-HtPmpHt-V1995_2001
Non-Res T12-3 to T8HP-2-K-12-Retro-ElecHt-V1987_1994
Non-Res T12-3 to T8HP-2-K-12-Retro-GasHt-V1987_1994
Non-Res T12-3 to T8HP-2-K-12-Retro-HtPmpHt-V1987_1994
Non-Res T12-3 to T8HP-2-Small Off-Retro-ElecHt-V1995_2001
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 666 of 729
Non-Res T12-3 to T8HP-2-Small Off-Retro-GasHt-V1995_2001
Non-Res T12-3 to T8HP-2-Small Off-Retro-HtPmpHt-V1995_2001
Non-Res T12-3 to T8HP-3-Anchor-Retro-ElecHt-V1987_1994
Non-Res T12-3 to T8HP-3-Anchor-Retro-GasHt-V1987_1994
Non-Res T12-3 to T8HP-3-Anchor-Retro-HtPmpHt-V1987_1994
Non-Res T12-3 to T8HP-3-Big Box-Retro-ElecHt-PRE1987
Non-Res T12-3 to T8HP-3-Big Box-Retro-GasHt-PRE1987
Non-Res T12-3 to T8HP-3-Big Box-Retro-HtPmpHt-PRE1987
Non-Res T12-3 to T8HP-3-High End-Retro-ElecHt-PRE1987
Non-Res T12-3 to T8HP-3-High End-Retro-ElecHt-V1987_1994
Non-Res T12-3 to T8HP-3-High End-Retro-GasHt-PRE1987
Non-Res T12-3 to T8HP-3-High End-Retro-GasHt-V1987_1994
Non-Res T12-3 to T8HP-3-High End-Retro-HtPmpHt-PRE1987
Non-Res T12-3 to T8HP-3-High End-Retro-HtPmpHt-V1987_1994
Non-Res T12-3 to T8HP-3-MIniMart-Retro-ElecHt-PRE1987
Non-Res T12-3 to T8HP-3-MIniMart-Retro-GasHt-PRE1987
Non-Res T12-3 to T8HP-3-MIniMart-Retro-HtPmpHt-PRE1987
Non-Res T12-3 to T8HP-3-OtherHealth-Retro-ElecHt-PRE1987
Non-Res T12-3 to T8HP-3-OtherHealth-Retro-ElecHt-V1987_1994
Non-Res T12-3 to T8HP-3-OtherHealth-Retro-GasHt-PRE1987
Non-Res T12-3 to T8HP-3-OtherHealth-Retro-GasHt-V1987_1994
Non-Res T12-3 to T8HP-3-OtherHealth-Retro-HtPmpHt-PRE1987
Non-Res T12-3 to T8HP-3-OtherHealth-Retro-HtPmpHt-V1987_1994
Non-Res T12-3 to T8HP-3-Restaurant-Retro-ElecHt-PRE1987
Non-Res T12-3 to T8HP-3-Restaurant-Retro-ElecHt-V1987_1994
Non-Res T12-3 to T8HP-3-Restaurant-Retro-GasHt-PRE1987
Non-Res T12-3 to T8HP-3-Restaurant-Retro-GasHt-V1987_1994
Non-Res T12-3 to T8HP-3-Restaurant-Retro-HtPmpHt-PRE1987
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 667 of 729
Non-Res T12-3 to T8HP-3-Restaurant-Retro-HtPmpHt-V1987_1994
Non-Res T12-3 to T8HP-3-Supermarket-Retro-ElecHt-PRE1987
Non-Res T12-3 to T8HP-3-Supermarket-Retro-GasHt-PRE1987
Non-Res T12-3 to T8HP-3-Supermarket-Retro-HtPmpHt-PRE1987
Non-Res T12-3 to T8HP-3-University-Retro-ElecHt-V1987_1994
Non-Res T12-3 to T8HP-3-University-Retro-GasHt-V1987_1994
Non-Res T12-3 to T8HP-3-University-Retro-HtPmpHt-V1987_1994
Non-Res T12-4 to T8HP-2-Large Off-Retro-ElecHt-PRE1987
Non-Res T12-4 to T8HP-2-Large Off-Retro-ElecHt-V1987_1994
Non-Res T12-4 to T8HP-2-Large Off-Retro-GasHt-PRE1987
Non-Res T12-4 to T8HP-2-Large Off-Retro-GasHt-V1987_1994
Non-Res T12-4 to T8HP-2-Large Off-Retro-HtPmpHt-PRE1987
Non-Res T12-4 to T8HP-2-Large Off-Retro-HtPmpHt-V1987_1994
Non-Res T12-4 to T8HP-2-Medium Off-Retro-ElecHt-PRE1987
Non-Res T12-4 to T8HP-2-Medium Off-Retro-ElecHt-V1987_1994
Non-Res T12-4 to T8HP-2-Medium Off-Retro-GasHt-PRE1987
Non-Res T12-4 to T8HP-2-Medium Off-Retro-GasHt-V1987_1994
Non-Res T12-4 to T8HP-2-Medium Off-Retro-HtPmpHt-PRE1987
Non-Res T12-4 to T8HP-2-Medium Off-Retro-HtPmpHt-V1987_1994
Non-Res T12-4 to T8HP-2-MIniMart-Retro-ElecHt-V1987_1994
Non-Res T12-4 to T8HP-2-MIniMart-Retro-GasHt-V1987_1994
Non-Res T12-4 to T8HP-2-MIniMart-Retro-HtPmpHt-V1987_1994
Non-Res T12-4 to T8HP-2-Small Off-Retro-ElecHt-PRE1987
Non-Res T12-4 to T8HP-2-Small Off-Retro-ElecHt-V1987_1994
Non-Res T12-4 to T8HP-2-Small Off-Retro-GasHt-PRE1987
Non-Res T12-4 to T8HP-2-Small Off-Retro-GasHt-V1987_1994
Non-Res T12-4 to T8HP-2-Small Off-Retro-HtPmpHt-PRE1987
Non-Res T12-4 to T8HP-2-Small Off-Retro-HtPmpHt-V1987_1994
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 668 of 729
Non-Res T12-4 to T8HP-2-Supermarket-Retro-ElecHt-V1987_1994
Non-Res T12-4 to T8HP-2-Supermarket-Retro-GasHt-V1987_1994
Non-Res T12-4 to T8HP-2-Supermarket-Retro-HtPmpHt-V1987_1994
Non-Res T12-4 to T8HP-3-Anchor-Retro-ElecHt-PRE1987
Non-Res T12-4 to T8HP-3-Anchor-Retro-GasHt-PRE1987
Non-Res T12-4 to T8HP-3-Anchor-Retro-HtPmpHt-PRE1987
Non-Res T12-4 to T8HP-3-Big Box-Retro-ElecHt-V1987_1994
Non-Res T12-4 to T8HP-3-Big Box-Retro-GasHt-V1987_1994
Non-Res T12-4 to T8HP-3-Big Box-Retro-HtPmpHt-V1987_1994
Non-Res T12-4 to T8HP-3-Small Box-Retro-ElecHt-PRE1987
Non-Res T12-4 to T8HP-3-Small Box-Retro-GasHt-PRE1987
Non-Res T12-4 to T8HP-3-Small Box-Retro-HtPmpHt-PRE1987
Non-Res Vending Machine Controller-Large Machine w/Illuminated Front
Non-Res Vending Machine Controller-Small Machine or Machine without Illuminated Front
Non-Res VSD Large Fan
Non-Res VSD Medium fan
Non-Res VSD Pump
Non-Res VSD Small Fan
Res Biradiant Oven
Res Bottom Freezer - No Ice
Res Energy Conservation School Program
Res Energy Star Dishwasher (EF 68) - PNW DHW Fuel Average + NEB Waste Water Treatment Savings
Res Energy Star Dishwasher (EF58) - PNW DHW Fuel Average + NEB of Waste Water Treatment Savings
Res Energy Star Dishwasher (EF76) - PNW DHW Fuel Average + NEB Waste Water Treatment Savings
Res Energy Star Dishwasher (EF85) - PNW DHW Fuel Average + NEB Waste Water Treatment Savings
Res
Heat Traps + Increased Insulation (3 1/2" foam) + Insulated Tank Bottom & Plastic Tank w/minimum 10 yr
warranty
Res Heat Traps + Increased Insulation (3" foam) + Insulated Tank Bottom w/minimum 10 year Warranty
Res Heating System Maintenance (tune-up/filter)
Res Improved Oven Insulation
Res Improved Oven Seals
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 669 of 729
Res
Manufactured Home NonSGC Forced Air Furnace w/CAC - PTCS Duct Sealing and System Commissioning
Heat Zone 1
Res
Manufactured Home NonSGC Forced Air Furnace w/CAC - PTCS Duct Sealing and System Commissioning
Heat Zone 2
Res Manufactured Home NonSGC Forced Air Furnace w/CAC - PTCS Duct Sealing Heat Zone 1
Res Manufactured Home NonSGC Forced Air Furnace w/CAC - PTCS Duct Sealing Heat Zone 2
Res Manufactured Home NonSGC Forced Air Furnace w/o CAC - PTCS Duct Sealing Heat Zone 1
Res Manufactured Home NonSGC Forced Air Furnace w/o CAC - PTCS Duct Sealing Heat Zone 2
Res Manufactured Home NonSGC Heat Pump - PTCS Duct Sealing and System Commissioning Heat Zone 1
Res Manufactured Home NonSGC Heat Pump - PTCS Duct Sealing and System Commissioning Heat Zone 2
Res Manufactured Home NonSGC Heat Pump - PTCS Duct Sealing Heat Zone 1
Res Manufactured Home NonSGC Heat Pump - PTCS Duct Sealing Heat Zone 2
Res Manufactured Home NonSGC Heat Pump - PTCS Duct Sealing, Commissioning and Controls Heat Zone 1
Res Manufactured Home NonSGC Heat Pump - PTCS Duct Sealing, Commissioning and Controls Heat Zone 2
Res Manufactured Home NonSGC Heat Pump - PTCS System Commissioning Heat Zone 1
Res Manufactured Home NonSGC Heat Pump - PTCS System Commissioning Heat Zone 2
Res
Manufactured Home SGC Forced Air Furnace w/CAC - PTCS Duct Sealing and System Commissioning
Heat Zone 1
Res
Manufactured Home SGC Forced Air Furnace w/CAC - PTCS Duct Sealing and System Commissioning
Heat Zone 2
Res Manufactured Home SGC Forced Air Furnace w/CAC - PTCS Duct Sealing Heat Zone 1
Res Manufactured Home SGC Forced Air Furnace w/CAC - PTCS Duct Sealing Heat Zone 2
Res Manufactured Home SGC Forced Air Furnace w/o CAC - PTCS Duct Sealing Heat Zone 1
Res Manufactured Home SGC Forced Air Furnace w/o CAC - PTCS Duct Sealing Heat Zone 2
Res Manufactured Home SGC Heat Pump - PTCS Duct Sealing and System Commissioning Heat Zone 1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 670 of 729
Res Manufactured Home SGC Heat Pump - PTCS Duct Sealing and System Commissioning Heat Zone 2
Res Manufactured Home SGC Heat Pump - PTCS Duct Sealing Heat Zone 1
Res Manufactured Home SGC Heat Pump - PTCS Duct Sealing Heat Zone 2
Res Manufactured Home SGC Heat Pump - PTCS Duct Sealing, Commissioning and Controls Heat Zone 1
Res Manufactured Home SGC Heat Pump - PTCS Duct Sealing, Commissioning and Controls Heat Zone 2
Res Manufactured Home SGC Heat Pump - PTCS System Commissioning Heat Zone 1
Res Manufactured Home SGC Heat Pump - PTCS System Commissioning Heat Zone 2
Res Manufactured Home Weatherization - Heating Zone 1
Res Manufactured Home Weatherization - Heating Zone 2
Res Multifamily Weatherization - Heating Zone 1
Res Multifamily Weatherization - Heating Zone 2
Res New MultiFamily Construction, DHW & Shower Preheat, Electric Resistance
Res New MultiFamily Construction, DHW Preheat, Electric Resistance
Res New MultiFamily Construction, Shower Preheat, Electric Resistance
Res New Single Family Construction, DHW & Shower Preheat, Electric Resistance
Res New Single Family Construction, DHW Preheat, Electric Resistance
Res New Single Family Construction, Shower Preheat, Electric Resistance
Res Post79/Pre93 Single Family Construction CAC Upgrade SEER - Cooling Zone 3
Res Post79/Pre93 Single Family Construction CAC Upgrade SEER - Cooling Zone 3
Res Post79/Pre93 Single Family Construction CAC Upgrade SEER - Cooling Zone 3
Res Post79/Pre93 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 671 of 729
Res Post79/Pre93 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post79/Pre93 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post79/Pre93 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post79/Pre93 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post79/Pre93 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post79/Pre93 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post79/Pre93 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post79/Pre93 Single Family Construction Convert Zonal Heating w/o CAC to HP HSPF 8/SEER 13 - Heat
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone
1
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone
1
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone
1
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone
2
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone
2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 672 of 729
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone
2
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 1
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 1
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 1
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 2
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 2
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 2
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 1
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 1
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 1
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 2
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 2
Res Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 2
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone
1
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone
1
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone
1
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone
2
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone
2
Res
Post79/Pre93 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone
2
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 673 of 729
Res Post79/Pre93 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 1
Res Post79/Pre93 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 1
Res Post79/Pre93 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 1
Res Post79/Pre93 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 2
Res Post79/Pre93 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 2
Res Post79/Pre93 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 2
Res Post92 Single Family Construction CAC Upgrade SEER - Cooling Zone 3
Res Post92 Single Family Construction CAC Upgrade SEER - Cooling Zone 3
Res Post92 Single Family Construction CAC Upgrade SEER - Cooling Zone 3
Res Post92 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Post92 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post92 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post92 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post92 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Post92 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 674 of 729
Res Post92 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 1
Res Post92 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 1
Res Post92 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 1
Res Post92 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 2
Res Post92 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 2
Res Post92 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs Air Source Heat Pump - Zone 1
Res Post92 Single Family Contruction Geothermal Heat Pump vs Air Source Heat Pump - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs Air Source Heat Pump - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/CAC - Zone 1
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/CAC - Zone 1
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/CAC - Zone 1
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/CAC - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/CAC - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/CAC - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/oCAC - Zone 1
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/oCAC - Zone 1
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/oCAC - Zone 1
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/oCAC - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/oCAC - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs FAF w/oCAC - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs Zonal Heating - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs Zonal Heating - Zone 2
Res Post92 Single Family Contruction Geothermal Heat Pump vs Zonal Heating - Zone 2
Res Post93 Manufactured Home NonSGC CAC Upgrade SEER w/PTCS - Cooling Zone 3
Res Post93 Manufactured Home NonSGC Convert FAF w/CAC to HP HSPF 8/SEER 12 - Heating
Res Post93 Manufactured Home NonSGC Convert FAF w/CAC to HP HSPF 8/SEER 12 - Heating
Res Post93 Manufactured Home NonSGC Convert FAF w/o CAC to HP HSPF 8/SEER 12 - Heating
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 675 of 729
Res Post93 Manufactured Home NonSGC Convert FAF w/o CAC to HP HSPF 8/SEER 12 - Heating
Res Post93 Manufactured Home NonSGC HP Upgrade HSPF 8 w/PTCS - Cooling Zone 1
Res Post93 Manufactured Home NonSGC HP Upgrade HSPF 8 w/PTCS - Cooling Zone 2
Res
Post93 NonSGC Manufactured Home Convert FAF w/CAC to Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 1
Res
Post93 NonSGC Manufactured Home Convert FAF w/CAC to Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 2
Res
Post93 NonSGC Manufactured Home Convert FAF w/o CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 1
Res
Post93 NonSGC Manufactured Home Convert FAF w/o CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 2
Res Pre80 Single Family Construction CAC Upgrade SEER - Cooling Zone 3
Res Pre80 Single Family Construction CAC Upgrade SEER - Cooling Zone 3
Res Pre80 Single Family Construction CAC Upgrade SEER - Cooling Zone 3
Res Pre80 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert FAF w/o CAC to HP HSPF 8/SEER 13 - Heating
Res Pre80 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Pre80 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Pre80 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 676 of 729
Res Pre80 Single Family Construction Convert Zonal Heating w/CAC to HP HSPF 8/SEER 13 - Heat
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Air Source HP - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/CAC - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on FAF w/oCAC - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone 1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 677 of 729
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone 1
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone 2
Res Pre80 Single Family Construction Geothermal Heat Pump Retrofit w/PTCS on Zonal Heating - Zone 2
Res Pre80 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 1
Res Pre80 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 1
Res Pre80 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 1
Res Pre80 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 2
Res Pre80 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 2
Res Pre80 Single Family Construction HP Upgrade HSPF 8 - Heating Zone 2
Res Pre94 Manufactured Home CAC Upgrade SEER w/PTCS - Cooling Zone 3
Res Pre94 Manufactured Home Convert FAF w/CAC to HP HSPF 8/SEER 12 - Heating
Res Pre94 Manufactured Home Convert FAF w/CAC to HP HSPF 8/SEER 12 - Heating
Res Pre94 Manufactured Home Convert FAF w/o CAC to HP HSPF 8/SEER 12 - Heating
Res Pre94 Manufactured Home Convert FAF w/o CAC to HP HSPF 8/SEER 12 - Heating
Res
Pre94 NonSGC Manufactured Home Convert FAF w/CAC to Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 1
Res
Pre94 NonSGC Manufactured Home Convert FAF w/CAC to Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 2
Res
Pre94 NonSGC Manufactured Home Convert FAF w/o CAC to Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 1
Res
Pre94 NonSGC Manufactured Home Convert FAF w/o CAC to Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 2
Res Reduced Oven Ventilation Rate
Res SGC - Heating Zone 1
Res SGC - Heating Zone 2
Res SGC - Zone 1
Res SGC - Zone 2
Res SGC Manufactured Home CAC Upgrade SEER w/PTCS - Cooling Zone 3
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 678 of 729
Res
SGC Manufactured Home Convert FAF w/CAC to Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 2
Res SGC Manufactured Home Convert FAF w/CAC to HP HSPF 8/SEER 12 - Heating
Res SGC Manufactured Home Convert FAF w/CAC to HP HSPF 8/SEER 12 - Heating
Res
SGC Manufactured Home Convert FAF w/o CAC to Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 2
Res SGC Manufactured Home Convert FAF w/o CAC to HP HSPF 8/SEER 12 - Heating
Res SGC Manufactured Home Convert FAF w/o CAC to HP HSPF 8/SEER 12 - Heating
Res SGCSF - Heating Zone 1
Res SGCSF - Heating Zone 2
Res Side-by-Side Model - Ice
Res Side-by-Side Model - No Ice
Res Single Family Heat Pump - PTCS Duct Sealing and System Commissioning Heat Zone 1
Res Single Family Heat Pump - PTCS Duct Sealing and System Commissioning Heat Zone 2
Res Single Family Heat Pump - PTCS System Commissioning Heat Zone 1
Res Single Family Heat Pump - PTCS System Commissioning Heat Zone 2
Res Single Family Weatherization - Zone 1
Res Single Family Weatherization - Zone 2
Res Top Freezer - Ice
Res Top Freezer - No Ice
Res Weighted Average - Interior & Exterior Wattage - 92 Watt

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 679 of 729
2009

Electric
Integrated Resource Plan

Appendix E – Integration of DSM within the
2009 Electric IRP

August 31, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 680 of 729
Integration of DSM within the 2009 Electric IRP
REPRESENTED WITHIN THE INTEGRATED RESOURCE PLANNING PROCESS
OUTSIDE OF THE SCOPE OF THE INTEGRATED RESOURCE PLANNING PROCESS
Assess market
characteristics
& past program
results
Preliminary cost-
effectiveness
evaluation
"Red""Yellow""Green"Terminate
Yellow -fail Yellow -Pass
Review existing
DSM business planAdditional analysis of
programs as necessary
Development of a revised
DSM business plan
Initiate new programs.
Continue, modify or
terminate existing programs
per business plan
Develop energy savings,
system coincident peak,
loadshape, NEB's,
measure lives
Develop cost
characteristics
Identify
potential
measures
Develop technical
and economic
potential
DSM
acquisition
goal
Business Plan
acquisition goal
Evaluated against the
updated avoided
costs
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 681 of 729
2009

Electric
Integrated Resource Plan

Appendix F – Achievable 20-Year Potential for
Residential and Non-Residential DSM
Programs

August 31, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 682 of 729
(in 2009 $s)
Meas #Segment Category Measure
achievable
potential (20 yr)
levelized trc
cost 2009 Life
46.5 Res Dishwash
Energy Star Dishwasher (EF58) - PNW DHW Fuel
Average + NEB of Waste Water Treatment Savings 835,250 0.00 9
52.5 Res Dishwash
Energy Star Dishwasher (EF 68) - PNW DHW Fuel
Average + NEB Waste Water Treatment Savings 835,250 0.01 9
58.5 Res Dishwash
Energy Star Dishwasher (EF76) - PNW DHW Fuel
Average + NEB Waste Water Treatment Savings 835,250 0.61 9
64.5 Res Dishwash
Energy Star Dishwasher (EF85) - PNW DHW Fuel
Average + NEB Waste Water Treatment Savings 835,250 1.98 9
104 Res Lighting
Weighted Average - Interior & Exterior Wattage - 92
Watt 250,452,883 0.03 9
106 Res Appliance Bottom Freezer - No Ice 659,410 0.04 19
107 Res Appliance Side-by-Side Model - No Ice 659,410 0.03 19
108 Res Appliance Side-by-Side Model - Ice 659,410 0.52 19
109 Res Appliance Top Freezer - No Ice 659,410 0.24 19
110 Res Appliance Top Freezer - Ice 659,410 0.13 19
111 Res DHW
New Single Family Construction, Shower Preheat,
Electric Resistance 44,117 0.11 40
113 Res DHW
New Single Family Construction, DHW & Shower
Preheat, Electric Resistance 126,027 0.08 40
115 Res DHW
New Single Family Construction, DHW Preheat,
Electric Resistance 50,419 0.10 40
117 Res DHW
New MultiFamily Construction, Shower Preheat,
Electric Resistance 17,638 0.09 40
119 Res DHW
New MultiFamily Construction, DHW & Shower
Preheat, Electric Resistance 50,419 0.07 40
121 Res DHW
New MultiFamily Construction, DHW Preheat,
Electric Resistance 20,155 0.08 40
129 Res Cooking Reduced Oven Ventilation Rate 24,336 0.03 20
130 Res Cooking Improved Oven Insulation 23,712 0.11 20
131 Res Cooking Improved Oven Seals 7,904 0.86 20
132 Res Cooking Biradiant Oven 163,072 0.26 20
133 Res DHW
Heat Traps + Increased Insulation (3" foam) +
Insulated Tank Bottom w/minimum 10 year
Warranty 92,976 0.03 12
134 Res DHW
Heat Traps + Increased Insulation (3 1/2" foam) +
Insulated Tank Bottom & Plastic Tank w/minimum
10 yr warranty 29,370 0.04 12
172 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Zonal Heating - Zone 1 892,459 0.18 30
175 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Zonal Heating - Zone 2 892,459 0.13 30
178 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Air Source HP - Zone 1 892,459 0.09 30
Acheiveable Potential (20-yr) for Res and Non-Res (excludes low-income/non-res site specific)
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 683 of 729
181 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Air Source HP - Zone 2 892,459 0.07 30
184 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/oCAC - Zone 1 892,459 0.09 30
187 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/oCAC - Zone 2 892,459 0.06 30
190 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/CAC - Zone 1 892,459 0.09 30
193 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/CAC - Zone 2 892,459 0.06 30
196 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Zonal
Heating - Zone 1 892,459 0.15 30
199 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Zonal
Heating - Zone 2 892,459 0.11 30
202 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Air
Source HP - Zone 1 892,459 0.08 30
205 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Air
Source HP - Zone 2 892,459 0.06 30
208 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/oCAC - Zone 1 892,459 0.06 30
211 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/oCAC - Zone 2 892,459 0.04 30
214 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/CAC - Zone 1 892,459 0.06 30
217 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/CAC - Zone 2 892,459 0.04 30
223 Res HP Upgrade
Post92 Single Family Contruction Geothermal Heat
Pump vs Zonal Heating - Zone 2 892,459 0.18 30
226 Res HP Upgrade
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/oCAC - Zone 1 892,459 0.11 30
229 Res HP Upgrade
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/oCAC - Zone 2 892,459 0.07 30
232 Res HP Upgrade
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/CAC - Zone 1 892,459 0.11 30
235 Res HP Upgrade
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/CAC - Zone 2 892,459 0.07 30
238 Res HP Upgrade
Post92 Single Family Contruction Geothermal Heat
Pump vs Air Source Heat Pump - Zone 1 892,459 0.14 30
241 Res HP Upgrade
Post92 Single Family Contruction Geothermal Heat
Pump vs Air Source Heat Pump - Zone 2 892,459 0.10 30
244 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Zonal Heating - Zone 1 892,459 0.17 30
247 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Zonal Heating - Zone 2 892,459 0.12 30
250 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Air Source HP - Zone 1 892,459 0.17 30
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 684 of 729
256 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/oCAC - Zone 1 892,459 0.11 30
259 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/oCAC - Zone 2 892,459 0.08 30
262 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/CAC - Zone 1 892,459 0.11 30
265 Res HP Upgrade
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/CAC - Zone 2 892,459 0.08 30
268 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Zonal
Heating - Zone 1 892,459 0.15 30
271 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Zonal
Heating - Zone 2 892,459 0.11 30
274 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Air
Source HP - Zone 1 892,459 0.14 30
277 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Air
Source HP - Zone 2 892,459 0.11 30
280 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/oCAC - Zone 1 892,459 0.08 30
283 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/oCAC - Zone 2 892,459 0.06 30
286 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/CAC - Zone 1 892,459 0.08 30
289 Res HP Upgrade
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/CAC - Zone 2 892,459 0.06 30
295 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs Zonal Heating - Zone 2 484,272 0.17 30
298 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/oCAC - Zone 1 484,272 0.14 30
301 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/oCAC - Zone 2 484,272 0.10 30
304 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/CAC - Zone 1 484,272 0.14 30
307 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/CAC - Zone 2 484,272 0.10 30
313 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs Air Source Heat Pump - Zone 2 484,272 0.18 30
316 Res HP Conv
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Zonal Heating - Zone 1 484,272 0.17 30
319 Res HP Conv
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Zonal Heating - Zone 2 484,272 0.12 30
322 Res HP Conv
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Air Source HP - Zone 1 484,272 0.22 30
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 685 of 729
325 Res HP Conv
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on Air Source HP - Zone 2 484,272 0.17 30
328 Res HP Conv
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/oCAC - Zone 1 484,272 0.13 30
331 Res HP Conv
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/oCAC - Zone 2 484,272 0.09 30
334 Res HP Conv
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/CAC - Zone 1 484,272 0.13 30
337 Res HP Conv
Pre80 Single Family Construction Geothermal Heat
Pump Retrofit w/PTCS on FAF w/CAC - Zone 2 484,272 0.09 30
340 Res HP Conv
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Zonal
Heating - Zone 1 484,272 0.14 30
343 Res HP Conv
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Zonal
Heating - Zone 2 484,272 0.10 30
346 Res HP Conv
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Air
Source HP - Zone 1 484,272 0.18 30
349 Res HP Conv
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on Air
Source HP - Zone 2 484,272 0.14 30
352 Res HP Conv
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/oCAC - Zone 1 484,272 0.09 30
355 Res HP Conv
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/oCAC - Zone 2 484,272 0.07 30
358 Res HP Conv
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/CAC - Zone 1 484,272 0.09 30
361 Res HP Conv
Post79/Pre93 Single Family Construction
Geothermal Heat Pump Retrofit w/PTCS on FAF
w/CAC - Zone 2 484,272 0.07 30
367 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs Zonal Heating - Zone 2 484,272 0.17 30
370 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/oCAC - Zone 1 484,272 0.16 30
373 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/oCAC - Zone 2 484,272 0.11 30
376 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/CAC - Zone 1 484,272 0.16 30
379 Res HP Conv
Post92 Single Family Contruction Geothermal Heat
Pump vs FAF w/CAC - Zone 2 484,272 0.11 30
388 Res MH HP Conv
Pre94 Manufactured Home Convert FAF w/o CAC
to HP HSPF 8/SEER 12 - Heating 410,091 0.09 18
390 Res MH HP Conv
Pre94 Manufactured Home Convert FAF w/o CAC
to HP HSPF 8/SEER 12 - Heating 527,124 0.07 18
392 Res MH HP Conv
Post93 Manufactured Home NonSGC Convert FAF
w/o CAC to HP HSPF 8/SEER 12 - Heating 341,756 0.10 18
394 Res MH HP Conv
Post93 Manufactured Home NonSGC Convert FAF
w/o CAC to HP HSPF 8/SEER 12 - Heating 450,441 0.08 18
396 Res MH HP Conv
SGC Manufactured Home Convert FAF w/o CAC to
HP HSPF 8/SEER 12 - Heating 217,385 0.14 18
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 686 of 729
398 Res MH HP Conv
SGC Manufactured Home Convert FAF w/o CAC to
HP HSPF 8/SEER 12 - Heating 300,697 0.10 18
400 Res MH HP Conv
Pre94 Manufactured Home Convert FAF w/CAC to
HP HSPF 8/SEER 12 - Heating 410,091 0.08 18
402 Res MH HP Conv
Pre94 Manufactured Home Convert FAF w/CAC to
HP HSPF 8/SEER 12 - Heating 527,124 0.07 18
404 Res MH HP Conv
Post93 Manufactured Home NonSGC Convert FAF
w/CAC to HP HSPF 8/SEER 12 - Heating 341,756 0.10 18
406 Res MH HP Conv
Post93 Manufactured Home NonSGC Convert FAF
w/CAC to HP HSPF 8/SEER 12 - Heating 450,441 0.08 18
408 Res MH HP Conv
SGC Manufactured Home Convert FAF w/CAC to
HP HSPF 8/SEER 12 - Heating 217,385 0.13 18
410 Res MH HP Conv
SGC Manufactured Home Convert FAF w/CAC to
HP HSPF 8/SEER 12 - Heating 300,697 0.10 18
412 Res Shell SGC - Heating Zone 1 31,387 0.05 70
413 Res Shell SGC - Heating Zone 2 92,577 0.05 70
414 Res Shell Single Family Weatherization - Zone 1 2,263,516 0.04 45
415 Res Shell Single Family Weatherization - Zone 2 4,334,121 0.03 45
416 Res Shell Multifamily Weatherization - Heating Zone 1 1,060,596 0.05 45
417 Res Shell Multifamily Weatherization - Heating Zone 2 1,394,411 0.04 45
418 Res Shell SGCSF - Heating Zone 1 2,416,877 0.06 70
419 Res Shell SGCSF - Heating Zone 2 3,931,820 0.05 70
420 Res HP Conv
Pre80 Single Family Construction Convert FAF w/o
CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.12 18
422 Res HP Conv
Pre80 Single Family Construction Convert FAF w/o
CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.10 18
424 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.07 18
426 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.06 18
428 Res HP Conv
Post92 Single Family Construction Convert FAF
w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.11 18
430 Res HP Conv
Post92 Single Family Construction Convert FAF
w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.09 18
432 Res HP Conv
Pre80 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.12 18
434 Res HP Conv
Pre80 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.10 18
436 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.07 18
438 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.06 18
440 Res HP Conv
Post92 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.11 18
442 Res HP Conv
Post92 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.09 18
444 Res HP Conv
Pre80 Single Family Construction Convert Zonal
Heating w/CAC to HP HSPF 8/SEER 13 - Heat 484,272 0.15 18
446 Res HP Conv
Pre80 Single Family Construction Convert Zonal
Heating w/CAC to HP HSPF 8/SEER 13 - Heat 484,272 0.13 18
448 Res HP Conv
Post79/Pre93 Single Family Construction Convert
Zonal Heating w/CAC to HP HSPF 8/SEER 13 -
Heat 484,272 0.09 18
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 687 of 729
450 Res HP Conv
Post79/Pre93 Single Family Construction Convert
Zonal Heating w/CAC to HP HSPF 8/SEER 13 -
Heat 484,272 0.08 18
452 Res HP Conv
Post92 Single Family Construction Convert Zonal
Heating w/CAC to HP HSPF 8/SEER 13 - Heat 484,272 0.13 18
454 Res HP Conv
Post92 Single Family Construction Convert Zonal
Heating w/CAC to HP HSPF 8/SEER 13 - Heat 484,272 0.11 18
468 Res HP Conv
Pre80 Single Family Construction Convert FAF w/o
CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.14 18
470 Res HP Conv
Pre80 Single Family Construction Convert FAF w/o
CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.12 18
472 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.08 18
474 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.07 18
476 Res HP Conv
Post92 Single Family Construction Convert FAF
w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.13 18
478 Res HP Conv
Post92 Single Family Construction Convert FAF
w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.10 18
480 Res HP Conv
Pre80 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.14 18
482 Res HP Conv
Pre80 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.12 18
484 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.08 18
486 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.07 18
488 Res HP Conv
Post92 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.13 18
490 Res HP Conv
Post92 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.10 18
492 Res HP Conv
Pre80 Single Family Construction Convert Zonal
Heating w/CAC to HP HSPF 8/SEER 13 - Heat 484,272 0.14 18
494 Res HP Conv
Pre80 Single Family Construction Convert Zonal
Heating w/CAC to HP HSPF 8/SEER 13 - Heat 484,272 0.12 18
496 Res HP Conv
Post79/Pre93 Single Family Construction Convert
Zonal Heating w/CAC to HP HSPF 8/SEER 13 -
Heat 484,272 0.08 18
498 Res HP Conv
Post79/Pre93 Single Family Construction Convert
Zonal Heating w/CAC to HP HSPF 8/SEER 13 -
Heat 484,272 0.07 18
500 Res HP Conv
Post92 Single Family Construction Convert Zonal
Heating w/CAC to HP HSPF 8/SEER 13 - Heat 484,272 0.13 18
502 Res HP Conv
Post92 Single Family Construction Convert Zonal
Heating w/CAC to HP HSPF 8/SEER 13 - Heat 484,272 0.10 18
510 Res HP Conv
Post79/Pre93 Single Family Construction Convert
Zonal Heating w/o CAC to HP HSPF 8/SEER 13 -
Heat 484,272 0.13 18
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 688 of 729
516 Res Shell
Manufactured Home Weatherization - Heating Zone
1 6,151,873 0.07 25
517 Res Shell
Manufactured Home Weatherization - Heating Zone
2 7,870,990 0.06 25
529 Res MF Duc Seal
Manufactured Home NonSGC Forced Air Furnace
w/o CAC - PTCS Duct Sealing Heat Zone 1 60,322 0.05 20
530 Res MF Duc Seal
Manufactured Home NonSGC Forced Air Furnace
w/o CAC - PTCS Duct Sealing Heat Zone 2 89,539 0.04 20
531 Res MF Duc Seal
Manufactured Home SGC Forced Air Furnace w/o
CAC - PTCS Duct Sealing Heat Zone 1 32,672 0.10 20
532 Res MF Duc Seal
Manufactured Home SGC Forced Air Furnace w/o
CAC - PTCS Duct Sealing Heat Zone 2 52,508 0.06 20
537 Res SF Com
Single Family Heat Pump - PTCS System
Commissioning Heat Zone 1 222,025 0.26 5
539 Res SF Com
Single Family Heat Pump - PTCS System
Commissioning Heat Zone 2 383,505 0.15 5
541 Res SF Com
Single Family Heat Pump - PTCS Duct Sealing and
System Commissioning Heat Zone 1 1,183,530 0.05 20
543 Res SF Com
Single Family Heat Pump - PTCS Duct Sealing and
System Commissioning Heat Zone 2 2,038,711 0.03 20
549 Res MH Duct Seal
Manufactured Home NonSGC Heat Pump - PTCS
Duct Sealing Heat Zone 1 37,507 0.09 20
551 Res MH Duct Seal
Manufactured Home NonSGC Heat Pump - PTCS
Duct Sealing Heat Zone 2 65,568 0.05 20
553 Res MH Com
Manufactured Home NonSGC Heat Pump - PTCS
System Commissioning Heat Zone 1 17,514 0.28 5
555 Res MH Com
Manufactured Home NonSGC Heat Pump - PTCS
System Commissioning Heat Zone 2 30,317 0.16 5
557 Res MH Duct Seal + Com
Manufactured Home NonSGC Heat Pump - PTCS
Duct Sealing and System Commissioning Heat
Zone 1 55,020 0.09 20
559 Res MH Duct Seal + Com
Manufactured Home NonSGC Heat Pump - PTCS
Duct Sealing and System Commissioning Heat
Zone 2 95,885 0.05 20
561 Res MH Duct Seal + Com
Manufactured Home NonSGC Heat Pump - PTCS
Duct Sealing, Commissioning and Controls Heat
Zone 1 62,104 0.10 20
563 Res MH Duct Seal + Com
Manufactured Home NonSGC Heat Pump - PTCS
Duct Sealing, Commissioning and Controls Heat
Zone 2 92,314 0.06 20
565 Res MH Duct Seal
Manufactured Home SGC Heat Pump - PTCS Duct
Sealing Heat Zone 1 20,752 0.15 20
567 Res MH Duct Seal
Manufactured Home SGC Heat Pump - PTCS Duct
Sealing Heat Zone 2 39,129 0.08 20
569 Res MH Com
Manufactured Home SGC Heat Pump - PTCS
System Commissioning Heat Zone 1 9,692 0.51 5
571 Res MH Com
Manufactured Home SGC Heat Pump - PTCS
System Commissioning Heat Zone 2 18,094 0.27 5
573 Res MH Duct Seal + Com
Manufactured Home SGC Heat Pump - PTCS Duct
Sealing and System Commissioning Heat Zone 1 30,444 0.17 20
575 Res MH Duct Seal + Com
Manufactured Home SGC Heat Pump - PTCS Duct
Sealing and System Commissioning Heat Zone 2 57,223 0.09 20
577 Res MH Duct Seal + Com
Manufactured Home SGC Heat Pump - PTCS Duct
Sealing, Commissioning and Controls Heat Zone 1 34,399 0.17 20
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 689 of 729
579 Res MH Duct Seal + Com
Manufactured Home SGC Heat Pump - PTCS Duct
Sealing, Commissioning and Controls Heat Zone 2 55,088 0.11 20
593 Res MH Duct Seal
Manufactured Home NonSGC Forced Air Furnace
w/CAC - PTCS Duct Sealing Heat Zone 1 60,322 0.05 20
595 Res MH Duct Seal
Manufactured Home NonSGC Forced Air Furnace
w/CAC - PTCS Duct Sealing Heat Zone 2 89,539 0.04 20
601 Res MH Duct Seal + Com
Manufactured Home NonSGC Forced Air Furnace
w/CAC - PTCS Duct Sealing and System
Commissioning Heat Zone 1 60,322 0.05 20
603 Res MH Duct Seal + Com
Manufactured Home NonSGC Forced Air Furnace
w/CAC - PTCS Duct Sealing and System
Commissioning Heat Zone 2 89,539 0.04 20
605 Res MH Duct Seal
Manufactured Home SGC Forced Air Furnace
w/CAC - PTCS Duct Sealing Heat Zone 1 32,672 0.10 20
607 Res MH Duct Seal
Manufactured Home SGC Forced Air Furnace
w/CAC - PTCS Duct Sealing Heat Zone 2 52,508 0.06 20
613 Res MH Duct Seal + Com
Manufactured Home SGC Forced Air Furnace
w/CAC - PTCS Duct Sealing and System
Commissioning Heat Zone 1 32,672 0.10 20
615 Res MH Duct Seal + Com
Manufactured Home SGC Forced Air Furnace
w/CAC - PTCS Duct Sealing and System
Commissioning Heat Zone 2 52,508 0.06 20
617 Res Shell SGC - Zone 1 538,582 0.05 45
618 Res Shell SGC - Zone 2 1,089,896 0.04 45
625 Res HP Conv
Pre94 NonSGC Manufactured Home Convert FAF
w/o CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 1 484,272 0.09 30
628 Res HP Conv
Pre94 NonSGC Manufactured Home Convert FAF
w/o CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 2 484,272 0.07 30
631 Res HP Conv
Pre94 NonSGC Manufactured Home Convert FAF
w/CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 1 484,272 0.09 30
634 Res HP Conv
Pre94 NonSGC Manufactured Home Convert FAF
w/CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 2 484,272 0.07 30
643 Res HP Conv
Post93 NonSGC Manufactured Home Convert FAF
w/o CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 1 484,272 0.13 30
646 Res HP Conv
Post93 NonSGC Manufactured Home Convert FAF
w/o CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 2 484,272 0.09 30
649 Res HP Conv
Post93 NonSGC Manufactured Home Convert FAF
w/CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 1 484,272 0.13 30
652 Res HP Conv
Post93 NonSGC Manufactured Home Convert FAF
w/CAC to Energy Star Geothermal Heat Pump
w/PTCS Specifications - Heating Zone 2 484,272 0.09 30
658 Res HP Conv
SGC Manufactured Home Convert FAF w/o CAC to
Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 2 484,272 0.13 30
664 Res HP Conv
SGC Manufactured Home Convert FAF w/CAC to
Energy Star Geothermal Heat Pump w/PTCS
Specifications - Heating Zone 2 484,272 0.13 30
673 Res AC Upgrade
Pre80 Single Family Construction CAC Upgrade
SEER - Cooling Zone 3 224,848 0.56 18
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 690 of 729
674 Res AC Upgrade
Post79/Pre93 Single Family Construction CAC
Upgrade SEER - Cooling Zone 3 224,848 0.36 18
675 Res AC Upgrade
Post92 Single Family Construction CAC Upgrade
SEER - Cooling Zone 3 224,848 0.47 18
676 Res HP Upgrade
Pre80 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 1 892,459 0.17 18
678 Res HP Upgrade
Pre80 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 2 892,459 0.10 18
680 Res HP Upgrade
Post79/Pre93 Single Family Construction HP
Upgrade HSPF 8 - Heating Zone 1 892,459 0.10 18
682 Res HP Upgrade
Post79/Pre93 Single Family Construction HP
Upgrade HSPF 8 - Heating Zone 2 892,459 0.06 18
684 Res HP Upgrade
Post92 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 1 892,459 0.16 18
686 Res HP Upgrade
Post92 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 2 892,459 0.09 18
688 Res AC Upgrade
Pre80 Single Family Construction CAC Upgrade
SEER - Cooling Zone 3 224,848 0.33 18
689 Res AC Upgrade
Post79/Pre93 Single Family Construction CAC
Upgrade SEER - Cooling Zone 3 224,848 0.21 18
690 Res AC Upgrade
Post92 Single Family Construction CAC Upgrade
SEER - Cooling Zone 3 224,848 0.28 18
691 Res HP Upgrade
Pre80 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 1 892,459 0.06 18
693 Res HP Upgrade
Pre80 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 2 892,459 0.04 18
695 Res HP Upgrade
Post79/Pre93 Single Family Construction HP
Upgrade HSPF 8 - Heating Zone 1 892,459 0.04 18
697 Res HP Upgrade
Post79/Pre93 Single Family Construction HP
Upgrade HSPF 8 - Heating Zone 2 892,459 0.02 18
699 Res HP Upgrade
Post92 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 1 892,459 0.06 18
701 Res HP Upgrade
Post92 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 2 892,459 0.03 18
703 Res AC Upgrade
Pre94 Manufactured Home CAC Upgrade SEER
w/PTCS - Cooling Zone 3 224,848 0.28 18
704 Res AC Upgrade
Post93 Manufactured Home NonSGC CAC
Upgrade SEER w/PTCS - Cooling Zone 3 224,848 0.29 18
705 Res AC Upgrade
SGC Manufactured Home CAC Upgrade SEER
w/PTCS - Cooling Zone 3 224,848 0.39 18
710 Res HP Upgrade
Post93 Manufactured Home NonSGC HP Upgrade
HSPF 8 w/PTCS - Cooling Zone 1 892,459 0.09 18
712 Res HP Upgrade
Post93 Manufactured Home NonSGC HP Upgrade
HSPF 8 w/PTCS - Cooling Zone 2 892,459 0.04 18
718 Res HP Conv
Pre80 Single Family Construction Convert FAF w/o
CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.10 18
720 Res HP Conv
Pre80 Single Family Construction Convert FAF w/o
CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.08 18
722 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.06 18
724 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.05 18
726 Res HP Conv
Post92 Single Family Construction Convert FAF
w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.09 18
728 Res HP Conv
Post92 Single Family Construction Convert FAF
w/o CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.07 18
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 691 of 729
730 Res HP Conv
Pre80 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.10 18
732 Res HP Conv
Pre80 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.08 18
734 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.06 18
736 Res HP Conv
Post79/Pre93 Single Family Construction Convert
FAF w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.05 18
738 Res HP Conv
Post92 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.09 18
740 Res HP Conv
Post92 Single Family Construction Convert FAF
w/CAC to HP HSPF 8/SEER 13 - Heating 484,272 0.07 18
746 Res HP Conv
Post79/Pre93 Single Family Construction Convert
Zonal Heating w/CAC to HP HSPF 8/SEER 13 -
Heat 484,272 0.11 18
748 Res HP Conv
Post79/Pre93 Single Family Construction Convert
Zonal Heating w/CAC to HP HSPF 8/SEER 13 -
Heat 484,272 0.10 18
752 Res HP Conv
Post92 Single Family Construction Convert Zonal
Heating w/CAC to HP HSPF 8/SEER 13 - Heat 484,272 0.15 18
766 Res AC Upgrade
Pre80 Single Family Construction CAC Upgrade
SEER - Cooling Zone 3 224,848 0.41 18
767 Res AC Upgrade
Post79/Pre93 Single Family Construction CAC
Upgrade SEER - Cooling Zone 3 224,848 0.26 18
768 Res AC Upgrade
Post92 Single Family Construction CAC Upgrade
SEER - Cooling Zone 3 224,848 0.34 18
769 Res HP Upgrade
Pre80 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 1 892,459 0.12 18
771 Res HP Upgrade
Pre80 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 2 892,459 0.07 18
773 Res HP Upgrade
Post79/Pre93 Single Family Construction HP
Upgrade HSPF 8 - Heating Zone 1 892,459 0.07 18
775 Res HP Upgrade
Post79/Pre93 Single Family Construction HP
Upgrade HSPF 8 - Heating Zone 2 892,459 0.04 18
777 Res HP Upgrade
Post92 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 1 892,459 0.11 18
779 Res HP Upgrade
Post92 Single Family Construction HP Upgrade
HSPF 8 - Heating Zone 2 892,459 0.06 18
783 Res Lighting Energy Conservation School Program 13,728,000 0.02 7
785 Res HVAC Heating System Maintenance (tune-up/filter)416,000 0.00 12
21 Non-Res HVAC VSD Small Fan 13,000,000 0.16 15
22 Non-Res HVAC VSD Medium fan 13,000,000 0.10 15
23 Non-Res HVAC VSD Large Fan 13,000,000 0.07 15
24 Non-Res HVAC VSD Pump 13,000,000 0.11 15
27 Non-Res Energy Smart Night Covers for Display Cases - Vertical 9,464,000 0.02 5
28 Non-Res Energy Smart Night Covers for Display Cases - Horizontal 9,464,000 0.04 5
29 Non-Res Energy Smart Strip Curtains for Walk-in Boxes 9,464,000 0.00 4
30 Non-Res Energy Smart Glass Doors on Open Display Cases (LT)9,464,000 0.03 12
31 Non-Res Energy Smart Glass Doors on Open Display Cases (MT)9,464,000 0.08 12
34 Non-Res Energy Smart Special Doors with Low/No Anti-Sweat Heat 9,464,000 0.05 12
35 Non-Res Energy Smart Anti-Sweat Heat Controls 9,464,000 0.03 11
36 Non-Res Energy Smart Auto-Closers for Coolers and Freezers 9,464,000 0.01 8
37 Non-Res Energy Smart Evaporative fan controller on walk-in 9,464,000 0.07 5
40 Non-Res Energy Smart Floating Head Pressure Controller 9,464,000 0.04 12
44 Non-Res HVAC
Built-Up HVAC Controls Optimization-Large Off-
GasHt-Retro 260,000 0.07 8
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 692 of 729
45 Non-Res HVAC
Built-Up HVAC Controls Optimization-Medium Off-
GasHt-Retro 260,000 0.08 8
46 Non-Res HVAC
Built-Up HVAC Controls Optimization-Small Off-
GasHt-Retro 260,000 0.25 8
47 Non-Res HVAC
Built-Up HVAC Controls Optimization-Big Box-
GasHt-Retro 260,000 0.10 8
48 Non-Res HVAC
Built-Up HVAC Controls Optimization-Small Box-
GasHt-Retro 260,000 0.23 8
49 Non-Res HVAC
Built-Up HVAC Controls Optimization-High End-
GasHt-Retro 260,000 0.17 8
50 Non-Res HVAC
Built-Up HVAC Controls Optimization-Anchor-
GasHt-Retro 260,000 0.06 8
51 Non-Res HVAC
Built-Up HVAC Controls Optimization-K-12-GasHt-
Retro 260,000 0.29 8
52 Non-Res HVAC
Built-Up HVAC Controls Optimization-University-
GasHt-Retro 260,000 0.10 8
53 Non-Res HVAC
Built-Up HVAC Controls Optimization-Warehouse-
GasHt-Retro 260,000 0.28 8
54 Non-Res HVAC
Built-Up HVAC Controls Optimization-Supermarket-
GasHt-Retro 260,000 0.08 8
55 Non-Res HVAC
Built-Up HVAC Controls Optimization-MIniMart-
GasHt-Retro 260,000 0.11 8
56 Non-Res HVAC
Built-Up HVAC Controls Optimization-Restaurant-
GasHt-Retro 260,000 0.10 8
57 Non-Res HVAC
Built-Up HVAC Controls Optimization-Lodging-
GasHt-Retro 260,000 0.08 8
58 Non-Res HVAC
Built-Up HVAC Controls Optimization-Hospital-
GasHt-Retro 260,000 0.06 8
59 Non-Res HVAC
Built-Up HVAC Controls Optimization-OtherHealth-
GasHt-Retro 260,000 0.07 8
60 Non-Res HVAC
Built-Up HVAC Controls Optimization-Other-GasHt-
Retro 260,000 0.23 8
61 Non-Res HVAC
Built-Up HVAC Controls Optimization-Large Off-
ElecHt-Retro 260,000 0.05 8
62 Non-Res HVAC
Built-Up HVAC Controls Optimization-Medium Off-
ElecHt-Retro 260,000 0.05 8
63 Non-Res HVAC
Built-Up HVAC Controls Optimization-Small Off-
ElecHt-Retro 260,000 0.15 8
64 Non-Res HVAC
Built-Up HVAC Controls Optimization-Big Box-
ElecHt-Retro 260,000 0.09 8
65 Non-Res HVAC
Built-Up HVAC Controls Optimization-Small Box-
ElecHt-Retro 260,000 0.17 8
66 Non-Res HVAC
Built-Up HVAC Controls Optimization-High End-
ElecHt-Retro 260,000 0.14 8
67 Non-Res HVAC
Built-Up HVAC Controls Optimization-Anchor-
ElecHt-Retro 260,000 0.05 8
68 Non-Res HVAC
Built-Up HVAC Controls Optimization-K-12-ElecHt-
Retro 260,000 0.05 8
69 Non-Res HVAC
Built-Up HVAC Controls Optimization-University-
ElecHt-Retro 260,000 0.06 8
70 Non-Res HVAC
Built-Up HVAC Controls Optimization-Warehouse-
ElecHt-Retro 260,000 0.11 8
71 Non-Res HVAC
Built-Up HVAC Controls Optimization-Supermarket-
ElecHt-Retro 260,000 0.05 8
72 Non-Res HVAC
Built-Up HVAC Controls Optimization-MIniMart-
ElecHt-Retro 260,000 0.09 8
73 Non-Res HVAC
Built-Up HVAC Controls Optimization-Restaurant-
ElecHt-Retro 260,000 0.08 8
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 693 of 729
74 Non-Res HVAC
Built-Up HVAC Controls Optimization-Lodging-
ElecHt-Retro 260,000 0.05 8
75 Non-Res HVAC
Built-Up HVAC Controls Optimization-Hospital-
ElecHt-Retro 260,000 0.04 8
76 Non-Res HVAC
Built-Up HVAC Controls Optimization-OtherHealth-
ElecHt-Retro 260,000 0.04 8
77 Non-Res HVAC
Built-Up HVAC Controls Optimization-Other-ElecHt-
Retro 260,000 0.13 8
78 Non-Res HVAC
Built-Up HVAC Controls Optimization-Large Off-
HtPmpHt-Retro 260,000 0.06 8
79 Non-Res HVAC
Built-Up HVAC Controls Optimization-Medium Off-
HtPmpHt-Retro 260,000 0.07 8
80 Non-Res HVAC
Built-Up HVAC Controls Optimization-Small Off-
HtPmpHt-Retro 260,000 0.19 8
81 Non-Res HVAC
Built-Up HVAC Controls Optimization-Big Box-
HtPmpHt-Retro 260,000 0.09 8
82 Non-Res HVAC
Built-Up HVAC Controls Optimization-Small Box-
HtPmpHt-Retro 260,000 0.20 8
83 Non-Res HVAC
Built-Up HVAC Controls Optimization-High End-
HtPmpHt-Retro 260,000 0.17 8
84 Non-Res HVAC
Built-Up HVAC Controls Optimization-Anchor-
HtPmpHt-Retro 260,000 0.06 8
85 Non-Res HVAC
Built-Up HVAC Controls Optimization-K-12-
HtPmpHt-Retro 260,000 0.08 8
86 Non-Res HVAC
Built-Up HVAC Controls Optimization-University-
HtPmpHt-Retro 260,000 0.08 8
87 Non-Res HVAC
Built-Up HVAC Controls Optimization-Warehouse-
HtPmpHt-Retro 260,000 0.17 8
88 Non-Res HVAC
Built-Up HVAC Controls Optimization-Supermarket-
HtPmpHt-Retro 260,000 0.07 8
90 Non-Res HVAC
Built-Up HVAC Controls Optimization-Restaurant-
HtPmpHt-Retro 260,000 0.10 8
91 Non-Res HVAC
Built-Up HVAC Controls Optimization-Lodging-
HtPmpHt-Retro 260,000 0.06 8
92 Non-Res HVAC
Built-Up HVAC Controls Optimization-Hospital-
HtPmpHt-Retro 260,000 0.05 8
93 Non-Res HVAC
Built-Up HVAC Controls Optimization-OtherHealth-
HtPmpHt-Retro 260,000 0.05 8
94 Non-Res HVAC
Built-Up HVAC Controls Optimization-Other-
HtPmpHt-Retro 260,000 0.17 8
115 Non-Res Controls Commission-New 21,960 0.07 12
117 Non-Res Traffic Lights
Replace 12 inch Red Incandescent Left Turn Bay
with 12 inch Red LED module 208,000 0.02 5
118 Non-Res Traffic Lights
Replace 12 inch Green Incandescent Left Turn Bay
with 12 inchGreen LED module 208,000 0.06 16
119 Non-Res Traffic Lights
Replace 12 inch Red Incandescent Thru Lane with
12 inch Red LED module 208,000 0.02 6
120 Non-Res Traffic Lights
Replace 12 inch Green Incandescent Thru Lane
with 12 inch Green LED module 208,000 0.05 7
121 Non-Res Traffic Lights
Replace 8 inch Red Incandescent Left Turn Bay
with 8 inch Red LED module 208,000 0.04 5
123 Non-Res Traffic Lights
Replace 8 inch Red Incandescent Thru Lane with 8
inch Red LED module 208,000 0.04 6
129 Non-Res Lighting-CFL INC to CFL-Large Off-New-ElecHt 163,800 0.01 15
132 Non-Res Lighting-CFL INC to CFL-Large Off-New-HtPmpHt 163,800 0.01 15
135 Non-Res Lighting-CFL INC to CFL-Large Off-New-GasHt 163,800 0.01 15
138 Non-Res Lighting-CFL INC to CFL-Medium Off-New-ElecHt 163,800 0.01 15
141 Non-Res Lighting-CFL INC to CFL-Medium Off-New-HtPmpHt 163,800 0.01 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 694 of 729
144 Non-Res Lighting-CFL INC to CFL-Medium Off-New-GasHt 163,800 0.01 15
148 Non-Res Lighting-CFL INC to CFL-Small Off-New-ElecHt 163,800 0.01 15
152 Non-Res Lighting-CFL INC to CFL-Small Off-New-HtPmpHt 163,800 0.01 15
154 Non-Res Lighting-T12T8F96T12 to T8HP-Small Off-New-GasHt 602,173 0.01 15
156 Non-Res Lighting-CFL INC to CFL-Small Off-New-GasHt 163,800 0.02 15
159 Non-Res Lighting-CFL INC to CMH-Big Box-New-ElecHt 81,900 0.04 15
161 Non-Res Lighting-HID Large MH to T5HO-Big Box-New-ElecHt 441,447 0.00 15
163 Non-Res Lighting-CFL INC to CMH-Big Box-New-HtPmpHt 81,900 0.03 15
165 Non-Res Lighting-HID Large MH to T5HO-Big Box-New-HtPmpHt 441,447 0.00 15
167 Non-Res Lighting-CFL INC to CMH-Big Box-New-GasHt 81,900 0.04 15
169 Non-Res Lighting-HID Large MH to T5HO-Big Box-New-GasHt 441,447 0.01 15
173 Non-Res Lighting-CFL INC to CMH-Small Box-New-ElecHt 81,900 0.06 15
178 Non-Res Lighting-CFL INC to CMH-Small Box-New-HtPmpHt 81,900 0.04 15
180 Non-Res Lighting-T12T8F96T12 to T8HP-Small Box-New-GasHt 602,173 0.01 15
183 Non-Res Lighting-CFL INC to CMH-Small Box-New-GasHt 81,900 0.05 15
184 Non-Res Lighting-HID Med MH to T8HP-Small Box-New-GasHt 441,447 0.01 15
187 Non-Res Lighting-CFL INC to CMH-High End-New-ElecHt 81,900 0.06 15
192 Non-Res Lighting-CFL INC to CMH-High End-New-HtPmpHt 81,900 0.05 15
195 Non-Res Lighting-T12T8T12-3 to T8HP-2-High End-New-GasHt 602,173 0.00 15
197 Non-Res Lighting-CFL INC to CMH-High End-New-GasHt 81,900 0.05 15
208 Non-Res Lighting-T12T8F96T12 to T8HP-Anchor-New-GasHt 602,173 0.01 15
211 Non-Res Lighting-HID Med MH to T8HP-Anchor-New-GasHt 441,447 0.01 15
214 Non-Res Lighting-CFL INC to CFL-K-12-New-ElecHt 145,600 0.02 15
218 Non-Res Lighting-CFL INC to CFL-K-12-New-HtPmpHt 145,600 0.01 15
222 Non-Res Lighting-CFL INC to CFL-K-12-New-GasHt 145,600 0.03 15
225 Non-Res Lighting-CFL INC to CMH-University-New-ElecHt 145,600 0.08 15
228 Non-Res Lighting-CFL INC to CMH-University-New-HtPmpHt 145,600 0.06 15
231 Non-Res Lighting-CFL INC to CMH-University-New-GasHt 145,600 0.06 15
235 Non-Res Lighting-CFL INC to CFL-Warehouse-New-ElecHt 655,200 0.01 15
237 Non-Res Lighting-HID Large MH to T5HO-Warehouse-New-ElecHt 441,447 0.00 15
240 Non-Res Lighting-CFL INC to CFL-Warehouse-New-HtPmpHt 655,200 0.01 15
242 Non-Res Lighting-HID Large MH to T5HO-Warehouse-New-HtPmpHt 441,447 0.00 15
243 Non-Res Lighting-T12T8F96T12 to T8HP-Warehouse-New-GasHt 602,173 0.00 15
245 Non-Res Lighting-CFL INC to CFL-Warehouse-New-GasHt 655,200 0.02 15
247 Non-Res Lighting-HID Large MH to T5HO-Warehouse-New-GasHt 441,447 0.01 15
252 Non-Res Lighting-HID Med MH to T5HO-Supermarket-New-ElecHt 441,447 0.01 15
257 Non-Res Lighting-HID Med MH to T5HO-Supermarket-New-HtPmpHt 441,447 0.01 15
258 Non-Res Lighting-T12T8F96T12 to T8HP-Supermarket-New-GasHt 602,173 0.00 15
262 Non-Res Lighting-HID Med MH to T5HO-Supermarket-New-GasHt 441,447 0.01 15
265 Non-Res Lighting-CFL INC to CMH-MIniMart-New-ElecHt 81,900 0.03 15
269 Non-Res Lighting-CFL INC to CMH-MIniMart-New-HtPmpHt 81,900 0.03 15
271 Non-Res Lighting-T12T8F96T12 to T8HP-MIniMart-New-GasHt 602,173 0.01 15
273 Non-Res Lighting-CFL INC to CMH-MIniMart-New-GasHt 81,900 0.04 15
278 Non-Res Lighting-CFL INC to CFL-Restaurant-New-ElecHt 72,800 0.01 15
283 Non-Res Lighting-CFL INC to CFL-Restaurant-New-HtPmpHt 72,800 0.01 15
285 Non-Res Lighting-T12T8F96T12 to T8HP-Restaurant-New-GasHt 602,173 0.01 15
288 Non-Res Lighting-CFL INC to CFL-Restaurant-New-GasHt 72,800 0.03 15
292 Non-Res Lighting-CFL INC to CFL-Lodging-New-ElecHt 218,400 0.01 15
297 Non-Res Lighting-CFL INC to CFL-Lodging-New-HtPmpHt 218,400 0.01 15
300 Non-Res Lighting-T12T8F96T12 to T8HP-Lodging-New-GasHt 602,173 0.01 15
302 Non-Res Lighting-CFL INC to CFL-Lodging-New-GasHt 218,400 0.02 15
307 Non-Res Lighting-CFL INC to CFL-Hospital-New-ElecHt 9,100 0.02 15
311 Non-Res Lighting-CFL INC to CFL-Hospital-New-HtPmpHt 9,100 0.01 15
313 Non-Res Lighting-T12T8F96T12 to T8HP-Hospital-New-GasHt 602,173 0.02 15
315 Non-Res Lighting-CFL INC to CFL-Hospital-New-GasHt 9,100 0.03 15
316 Non-Res Lighting-HID Med MH to T8HP-Hospital-New-GasHt 441,447 0.02 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 695 of 729
319 Non-Res Lighting-CFL INC to CFL-OtherHealth-New-ElecHt 9,100 0.01 15
324 Non-Res Lighting-CFL INC to CFL-OtherHealth-New-HtPmpHt 9,100 0.01 15
329 Non-Res Lighting-CFL INC to CFL-OtherHealth-New-GasHt 9,100 0.01 15
331 Non-Res Lighting-HID Med MH to T8HP-OtherHealth-New-GasHt 441,447 0.00 15
334 Non-Res Lighting-CFL INC to CFL-Other-New-ElecHt 145,600 0.01 15
335 Non-Res Lighting-HID Med MH to T5HO-Other-New-ElecHt 441,447 0.01 15
336 Non-Res Lighting-HID Large MH to T5HO-Other-New-ElecHt 441,447 0.00 15
339 Non-Res Lighting-CFL INC to CFL-Other-New-HtPmpHt 145,600 0.01 15
340 Non-Res Lighting-HID Med MH to T5HO-Other-New-HtPmpHt 441,447 0.01 15
341 Non-Res Lighting-HID Large MH to T5HO-Other-New-HtPmpHt 441,447 0.00 15
344 Non-Res Lighting-CFL INC to CFL-Other-New-GasHt 145,600 0.01 15
345 Non-Res Lighting-HID Med MH to T5HO-Other-New-GasHt 441,447 0.02 15
346 Non-Res Lighting-HID Large MH to T5HO-Other-New-GasHt 441,447 0.01 15
347 Non-Res Lighting-T12T8T12-4 to T8HP-2-Large Off-Retro-ElecHt-PRE1987 602,173 0.02 15
350 Non-Res Lighting-CFL INC to CFL-Large Off-Retro-ElecHt-PRE1987 163,800 0.03 15
351 Non-Res Lighting-T12T8F96T12 to T8HP-Large Off-Retro-ElecHt-PRE1987 602,173 0.08 15
352 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Large Off-Retro-HtPmpHt-
PRE1987 602,173 0.01 15
355 Non-Res Lighting-CFL INC to CFL-Large Off-Retro-HtPmpHt-PRE1987 163,800 0.03 15
356 Non-Res Lighting-T12T8
F96T12 to T8HP-Large Off-Retro-HtPmpHt-
PRE1987 602,173 0.07 15
357 Non-Res Lighting-T12T8T12-4 to T8HP-2-Large Off-Retro-GasHt-PRE1987 602,173 0.02 15
360 Non-Res Lighting-CFL INC to CFL-Large Off-Retro-GasHt-PRE1987 163,800 0.03 15
361 Non-Res Lighting-T12T8F96T12 to T8HP-Large Off-Retro-GasHt-PRE1987 602,173 0.07 15
362 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Medium Off-Retro-ElecHt-
PRE1987 602,173 0.02 15
365 Non-Res Lighting-CFL INC to CFL-Medium Off-Retro-ElecHt-PRE1987 163,800 0.04 15
366 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Medium Off-Retro-ElecHt-
PRE1987 602,173 0.01 15
368 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Medium Off-Retro-HtPmpHt-
PRE1987 602,173 0.02 15
371 Non-Res Lighting-CFL INC to CFL-Medium Off-Retro-HtPmpHt-PRE1987 163,800 0.03 15
372 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Medium Off-Retro-
HtPmpHt-PRE1987 602,173 0.01 15
374 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Medium Off-Retro-GasHt-
PRE1987 602,173 0.02 15
377 Non-Res Lighting-CFL INC to CFL-Medium Off-Retro-GasHt-PRE1987 163,800 0.04 15
378 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Medium Off-Retro-GasHt-
PRE1987 602,173 0.02 15
380 Non-Res Lighting-T12T8T12-4 to T8HP-2-Small Off-Retro-ElecHt-PRE1987 602,173 0.03 15
383 Non-Res Lighting-CFL INC to CFL-Small Off-Retro-ElecHt-PRE1987 163,800 0.06 15
384 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Small Off-Retro-ElecHt-
PRE1987 602,173 0.02 15
386 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Small Off-Retro-HtPmpHt-
PRE1987 602,173 0.02 15
389 Non-Res Lighting-CFL INC to CFL-Small Off-Retro-HtPmpHt-PRE1987 163,800 0.04 15
390 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Small Off-Retro-HtPmpHt-
PRE1987 602,173 0.02 15
392 Non-Res Lighting-T12T8T12-4 to T8HP-2-Small Off-Retro-GasHt-PRE1987 602,173 0.03 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 696 of 729
395 Non-Res Lighting-CFL INC to CFL-Small Off-Retro-GasHt-PRE1987 163,800 0.05 15
396 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Small Off-Retro-GasHt-
PRE1987 602,173 0.03 15
398 Non-Res Lighting-T12T8T12-3 to T8HP-3-Big Box-Retro-ElecHt-PRE1987 602,173 0.04 15
401 Non-Res Lighting-HID Large MH to T5HO-Big Box-Retro-ElecHt-PRE1987 441,447 0.05 15
402 Non-Res Lighting-T12T8T12-3 to T8HP-3-Big Box-Retro-HtPmpHt-PRE1987 602,173 0.03 15
405 Non-Res Lighting-HID
Large MH to T5HO-Big Box-Retro-HtPmpHt-
PRE1987 441,447 0.04 15
406 Non-Res Lighting-T12T8T12-3 to T8HP-3-Big Box-Retro-GasHt-PRE1987 602,173 0.04 15
409 Non-Res Lighting-HID Large MH to T5HO-Big Box-Retro-GasHt-PRE1987 441,447 0.05 15
410 Non-Res Lighting-T12T8T12-4 to T8HP-3-Small Box-Retro-ElecHt-PRE1987 602,173 0.03 15
412 Non-Res Lighting-T12T8F96T12 to T8HP-Small Box-Retro-ElecHt-PRE1987 602,173 0.12 15
414 Non-Res Lighting-HID
Med MH to T8HP-Small Box-Retro-ElecHt-
PRE1987 441,447 0.13 15
415 Non-Res Lighting-T12T8
T12-4 to T8HP-3-Small Box-Retro-HtPmpHt-
PRE1987 602,173 0.02 15
417 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Box-Retro-HtPmpHt-
PRE1987 602,173 0.09 15
419 Non-Res Lighting-HID
Med MH to T8HP-Small Box-Retro-HtPmpHt-
PRE1987 441,447 0.09 15
420 Non-Res Lighting-T12T8T12-4 to T8HP-3-Small Box-Retro-GasHt-PRE1987 602,173 0.03 15
422 Non-Res Lighting-T12T8F96T12 to T8HP-Small Box-Retro-GasHt-PRE1987 602,173 0.09 15
424 Non-Res Lighting-HID Med MH to T8HP-Small Box-Retro-GasHt-PRE1987 441,447 0.10 15
425 Non-Res Lighting-T12T8T12-3 to T8HP-3-High End-Retro-ElecHt-PRE1987 602,173 0.05 15
427 Non-Res Lighting-CFL INC to CMH-High End-Retro-ElecHt-PRE1987 81,900 0.09 15
430 Non-Res Lighting-T12T8
T12-3 to T8HP-3-High End-Retro-HtPmpHt-
PRE1987 602,173 0.04 15
432 Non-Res Lighting-CFL INC to CMH-High End-Retro-HtPmpHt-PRE1987 81,900 0.07 15
435 Non-Res Lighting-T12T8T12-3 to T8HP-3-High End-Retro-GasHt-PRE1987 602,173 0.05 15
437 Non-Res Lighting-CFL INC to CMH-High End-Retro-GasHt-PRE1987 81,900 0.08 15
440 Non-Res Lighting-T12T8T12-4 to T8HP-3-Anchor-Retro-ElecHt-PRE1987 602,173 0.03 15
442 Non-Res Lighting-T12T8F96T12 to T8HP-Anchor-Retro-ElecHt-PRE1987 602,173 0.11 15
445 Non-Res Lighting-T12T8T12-4 to T8HP-3-Anchor-Retro-HtPmpHt-PRE1987 602,173 0.02 15
447 Non-Res Lighting-T12T8F96T12 to T8HP-Anchor-Retro-HtPmpHt-PRE1987 602,173 0.08 15
450 Non-Res Lighting-T12T8T12-4 to T8HP-3-Anchor-Retro-GasHt-PRE1987 602,173 0.03 15
452 Non-Res Lighting-T12T8F96T12 to T8HP-Anchor-Retro-GasHt-PRE1987 602,173 0.08 15
455 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-K-12-Retro-ElecHt-
PRE1987 602,173 0.03 15
458 Non-Res Lighting-CFL INC to CFL-K-12-Retro-ElecHt-PRE1987 145,600 0.09 15
459 Non-Res Lighting-HID Med MH to T8HP-K-12-Retro-ElecHt-PRE1987 441,447 0.25 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 697 of 729
460 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-K-12-Retro-HtPmpHt-
PRE1987 602,173 0.02 15
463 Non-Res Lighting-CFL INC to CFL-K-12-Retro-HtPmpHt-PRE1987 145,600 0.06 15
464 Non-Res Lighting-HID Med MH to T8HP-K-12-Retro-HtPmpHt-PRE1987 441,447 0.16 15
465 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-K-12-Retro-GasHt-
PRE1987 602,173 0.03 15
468 Non-Res Lighting-CFL INC to CFL-K-12-Retro-GasHt-PRE1987 145,600 0.07 15
469 Non-Res Lighting-HID Med MH to T8HP-K-12-Retro-GasHt-PRE1987 441,447 0.16 15
470 Non-Res Lighting-T12T8F96T12 to T8HP-University-Retro-ElecHt-PRE1987 602,173 0.15 15
473 Non-Res Lighting-CFL INC to CFL-University-Retro-ElecHt-PRE1987 145,600 0.06 15
475 Non-Res Lighting-T12T8
F96T12 to T8HP-University-Retro-HtPmpHt-
PRE1987 602,173 0.11 15
478 Non-Res Lighting-CFL INC to CFL-University-Retro-HtPmpHt-PRE1987 145,600 0.04 15
480 Non-Res Lighting-T12T8F96T12 to T8HP-University-Retro-GasHt-PRE1987 602,173 0.11 15
483 Non-Res Lighting-CFL INC to CFL-University-Retro-GasHt-PRE1987 145,600 0.05 15
485 Non-Res Lighting-T12T8
F96T12 to T8HP-Warehouse-Retro-ElecHt-
PRE1987 602,173 0.14 15
487 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Warehouse-Retro-ElecHt-
PRE1987 602,173 0.02 15
489 Non-Res Lighting-HID
Large MH to T5HO-Warehouse-Retro-ElecHt-
PRE1987 441,447 0.09 15
490 Non-Res Lighting-T12T8
F96T12 to T8HP-Warehouse-Retro-HtPmpHt-
PRE1987 602,173 0.11 15
492 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Warehouse-Retro-HtPmpHt-
PRE1987 602,173 0.02 15
494 Non-Res Lighting-HID
Large MH to T5HO-Warehouse-Retro-HtPmpHt-
PRE1987 441,447 0.07 15
495 Non-Res Lighting-T12T8
F96T12 to T8HP-Warehouse-Retro-GasHt-
PRE1987 602,173 0.10 15
497 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Warehouse-Retro-GasHt-
PRE1987 602,173 0.03 15
499 Non-Res Lighting-HID
Large MH to T5HO-Warehouse-Retro-GasHt-
PRE1987 441,447 0.07 15
500 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Supermarket-Retro-ElecHt-
PRE1987 602,173 0.03 15
502 Non-Res Lighting-CFL INC to CMH-Supermarket-Retro-ElecHt-PRE1987 81,900 0.04 15
504 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Supermarket-Retro-HtPmpHt-
PRE1987 602,173 0.02 15
506 Non-Res Lighting-CFL
INC to CMH-Supermarket-Retro-HtPmpHt-
PRE1987 81,900 0.04 15
508 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Supermarket-Retro-GasHt-
PRE1987 602,173 0.03 15
510 Non-Res Lighting-CFL INC to CMH-Supermarket-Retro-GasHt-PRE1987 81,900 0.04 15
512 Non-Res Lighting-T12T8T12-3 to T8HP-3-MIniMart-Retro-ElecHt-PRE1987 602,173 0.03 15
514 Non-Res Lighting-CFL INC to CMH-MIniMart-Retro-ElecHt-PRE1987 81,900 0.05 15
515 Non-Res Lighting-T12T8
T12-3 to T8HP-3-MIniMart-Retro-HtPmpHt-
PRE1987 602,173 0.02 15
517 Non-Res Lighting-CFL INC to CMH-MIniMart-Retro-HtPmpHt-PRE1987 81,900 0.04 15
518 Non-Res Lighting-T12T8T12-3 to T8HP-3-MIniMart-Retro-GasHt-PRE1987 602,173 0.04 15
520 Non-Res Lighting-CFL INC to CMH-MIniMart-Retro-GasHt-PRE1987 81,900 0.05 15
521 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Restaurant-Retro-ElecHt-
PRE1987 602,173 0.07 15
522 Non-Res Lighting-CFL INC to CFL-Restaurant-Retro-ElecHt-PRE1987 72,800 0.06 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 698 of 729
523 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Restaurant-Retro-HtPmpHt-
PRE1987 602,173 0.04 15
524 Non-Res Lighting-CFL INC to CFL-Restaurant-Retro-HtPmpHt-PRE1987 72,800 0.03 15
525 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Restaurant-Retro-GasHt-
PRE1987 602,173 0.05 15
526 Non-Res Lighting-CFL INC to CFL-Restaurant-Retro-GasHt-PRE1987 72,800 0.05 15
527 Non-Res Lighting-T12T8F96T12 to T8HP-Lodging-Retro-ElecHt-PRE1987 602,173 0.12 15
529 Non-Res Lighting-CFL INC to CFL-Lodging-Retro-ElecHt-PRE1987 218,400 0.05 15
530 Non-Res Lighting-T12T8F96T12 to T8HP-Lodging-Retro-HtPmpHt-PRE1987 602,173 0.10 15
532 Non-Res Lighting-CFL INC to CFL-Lodging-Retro-HtPmpHt-PRE1987 218,400 0.04 15
533 Non-Res Lighting-T12T8F96T12 to T8HP-Lodging-Retro-GasHt-PRE1987 602,173 0.09 15
535 Non-Res Lighting-CFL INC to CFL-Lodging-Retro-GasHt-PRE1987 218,400 0.05 15
536 Non-Res Lighting-T12T8F96T12 to T8HP-Hospital-Retro-ElecHt-PRE1987 602,173 0.18 15
538 Non-Res Lighting-CFL INC to CFL-Hospital-Retro-ElecHt-PRE1987 9,100 0.07 15
539 Non-Res Lighting-T12T8
F96T12 to T8HP-Hospital-Retro-HtPmpHt-
PRE1987 602,173 0.08 15
541 Non-Res Lighting-CFL INC to CFL-Hospital-Retro-HtPmpHt-PRE1987 9,100 0.03 15
542 Non-Res Lighting-T12T8F96T12 to T8HP-Hospital-Retro-GasHt-PRE1987 602,173 0.08 15
544 Non-Res Lighting-CFL INC to CFL-Hospital-Retro-GasHt-PRE1987 9,100 0.05 15
545 Non-Res Lighting-T12T8
T12-3 to T8HP-3-OtherHealth-Retro-ElecHt-
PRE1987 602,173 0.04 15
547 Non-Res Lighting-CFL INC to CFL-OtherHealth-Retro-ElecHt-PRE1987 9,100 0.04 15
548 Non-Res Lighting-T12T8
T12-3 to T8HP-3-OtherHealth-Retro-HtPmpHt-
PRE1987 602,173 0.04 15
550 Non-Res Lighting-CFL INC to CFL-OtherHealth-Retro-HtPmpHt-PRE1987 9,100 0.03 15
551 Non-Res Lighting-T12T8
T12-3 to T8HP-3-OtherHealth-Retro-GasHt-
PRE1987 602,173 0.04 15
553 Non-Res Lighting-CFL INC to CFL-OtherHealth-Retro-GasHt-PRE1987 9,100 0.04 15
554 Non-Res Lighting-T12T8F96T12 to T8HP-Other-Retro-ElecHt-PRE1987 602,173 0.09 15
556 Non-Res Lighting-T12T8T12-2 to T8HP-1-Other-Retro-ElecHt-PRE1987 602,173 0.03 15
557 Non-Res Lighting-CFL INC to CFL-Other-Retro-ElecHt-PRE1987 145,600 0.04 15
558 Non-Res Lighting-HID Large MH to T5HO-Other-Retro-ElecHt-PRE1987 441,447 0.06 15
559 Non-Res Lighting-T12T8F96T12 to T8HP-Other-Retro-HtPmpHt-PRE1987 602,173 0.08 15
561 Non-Res Lighting-T12T8T12-2 to T8HP-1-Other-Retro-HtPmpHt-PRE1987 602,173 0.02 15
562 Non-Res Lighting-CFL INC to CFL-Other-Retro-HtPmpHt-PRE1987 145,600 0.03 15
563 Non-Res Lighting-HID Large MH to T5HO-Other-Retro-HtPmpHt-PRE1987 441,447 0.05 15
564 Non-Res Lighting-T12T8F96T12 to T8HP-Other-Retro-GasHt-PRE1987 602,173 0.08 15
566 Non-Res Lighting-T12T8T12-2 to T8HP-1-Other-Retro-GasHt-PRE1987 602,173 0.03 15
567 Non-Res Lighting-CFL INC to CFL-Other-Retro-GasHt-PRE1987 145,600 0.04 15
568 Non-Res Lighting-HID Large MH to T5HO-Other-Retro-GasHt-PRE1987 441,447 0.05 15
569 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Large Off-Retro-ElecHt-
V1987_1994 602,173 0.02 15
572 Non-Res Lighting-CFL INC to CFL-Large Off-Retro-ElecHt-V1987_1994 163,800 0.03 15
573 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Large Off-Retro-ElecHt-
V1987_1994 602,173 0.01 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 699 of 729
574 Non-Res Lighting-HID
Med MH to T8HP-Large Off-Retro-ElecHt-
V1987_1994 441,447 0.08 15
575 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Large Off-Retro-HtPmpHt-
V1987_1994 602,173 0.01 15
578 Non-Res Lighting-CFL INC to CFL-Large Off-Retro-HtPmpHt-V1987_1994 163,800 0.03 15
579 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Large Off-Retro-HtPmpHt-
V1987_1994 602,173 0.01 15
580 Non-Res Lighting-HID
Med MH to T8HP-Large Off-Retro-HtPmpHt-
V1987_1994 441,447 0.08 15
581 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Large Off-Retro-GasHt-
V1987_1994 602,173 0.02 15
584 Non-Res Lighting-CFL INC to CFL-Large Off-Retro-GasHt-V1987_1994 163,800 0.03 15
585 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Large Off-Retro-GasHt-
V1987_1994 602,173 0.02 15
586 Non-Res Lighting-HID
Med MH to T8HP-Large Off-Retro-GasHt-
V1987_1994 441,447 0.08 15
587 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Medium Off-Retro-ElecHt-
V1987_1994 602,173 0.02 15
589 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Medium Off-Retro-ElecHt-
V1987_1994 602,173 0.01 15
590 Non-Res Lighting-CFL INC to CFL-Medium Off-Retro-ElecHt-V1987_1994 163,800 0.04 15
591 Non-Res Lighting-HID
Med MH to T8HP-Medium Off-Retro-ElecHt-
V1987_1994 441,447 0.10 15
592 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Medium Off-Retro-HtPmpHt-
V1987_1994 602,173 0.02 15
594 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Medium Off-Retro-
HtPmpHt-V1987_1994 602,173 0.01 15
595 Non-Res Lighting-CFL
INC to CFL-Medium Off-Retro-HtPmpHt-
V1987_1994 163,800 0.03 15
596 Non-Res Lighting-HID
Med MH to T8HP-Medium Off-Retro-HtPmpHt-
V1987_1994 441,447 0.09 15
597 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Medium Off-Retro-GasHt-
V1987_1994 602,173 0.02 15
599 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Medium Off-Retro-GasHt-
V1987_1994 602,173 0.02 15
600 Non-Res Lighting-CFL INC to CFL-Medium Off-Retro-GasHt-V1987_1994 163,800 0.04 15
601 Non-Res Lighting-HID
Med MH to T8HP-Medium Off-Retro-GasHt-
V1987_1994 441,447 0.09 15
602 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Small Off-Retro-ElecHt-
V1987_1994 602,173 0.03 15
604 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Small Off-Retro-ElecHt-
V1987_1994 602,173 0.02 15
605 Non-Res Lighting-CFL INC to CFL-Small Off-Retro-ElecHt-V1987_1994 163,800 0.06 15
606 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Off-Retro-ElecHt-
V1987_1994 602,173 0.14 15
608 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Small Off-Retro-HtPmpHt-
V1987_1994 602,173 0.02 15
610 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Small Off-Retro-HtPmpHt-
V1987_1994 602,173 0.02 15
611 Non-Res Lighting-CFL INC to CFL-Small Off-Retro-HtPmpHt-V1987_1994 163,800 0.04 15
612 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Off-Retro-HtPmpHt-
V1987_1994 602,173 0.10 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 700 of 729
614 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Small Off-Retro-GasHt-
V1987_1994 602,173 0.03 15
616 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Small Off-Retro-GasHt-
V1987_1994 602,173 0.03 15
617 Non-Res Lighting-CFL INC to CFL-Small Off-Retro-GasHt-V1987_1994 163,800 0.05 15
618 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Off-Retro-GasHt-
V1987_1994 602,173 0.10 15
620 Non-Res Lighting-T12T8
T12-4 to T8HP-3-Big Box-Retro-ElecHt-
V1987_1994 602,173 0.02 15
622 Non-Res Lighting-T12T8
F96T12 to T8HP-Big Box-Retro-ElecHt-
V1987_1994 602,173 0.07 15
624 Non-Res Lighting-HID
Large MH to T5HO-Big Box-Retro-ElecHt-
V1987_1994 441,447 0.05 15
625 Non-Res Lighting-T12T8
T12-4 to T8HP-3-Big Box-Retro-HtPmpHt-
V1987_1994 602,173 0.01 15
627 Non-Res Lighting-T12T8
F96T12 to T8HP-Big Box-Retro-HtPmpHt-
V1987_1994 602,173 0.06 15
629 Non-Res Lighting-HID
Large MH to T5HO-Big Box-Retro-HtPmpHt-
V1987_1994 441,447 0.04 15
630 Non-Res Lighting-T12T8
T12-4 to T8HP-3-Big Box-Retro-GasHt-
V1987_1994 602,173 0.02 15
632 Non-Res Lighting-T12T8F96T12 to T8HP-Big Box-Retro-GasHt-V1987_1994 602,173 0.06 15
634 Non-Res Lighting-HID
Large MH to T5HO-Big Box-Retro-GasHt-
V1987_1994 441,447 0.04 15
635 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Box-Retro-ElecHt-
V1987_1994 602,173 0.11 15
637 Non-Res Lighting-CFL INC to CMH-Small Box-Retro-ElecHt-V1987_1994 81,900 0.09 15
638 Non-Res Lighting-HID
Med MH to T8HP-Small Box-Retro-ElecHt-
V1987_1994 441,447 0.12 15
639 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Box-Retro-HtPmpHt-
V1987_1994 602,173 0.08 15
641 Non-Res Lighting-CFL
INC to CMH-Small Box-Retro-HtPmpHt-
V1987_1994 81,900 0.06 15
642 Non-Res Lighting-HID
Med MH to T8HP-Small Box-Retro-HtPmpHt-
V1987_1994 441,447 0.09 15
643 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Box-Retro-GasHt-
V1987_1994 602,173 0.09 15
645 Non-Res Lighting-CFL INC to CMH-Small Box-Retro-GasHt-V1987_1994 81,900 0.07 15
646 Non-Res Lighting-HID
Med MH to T8HP-Small Box-Retro-GasHt-
V1987_1994 441,447 0.09 15
647 Non-Res Lighting-T12T8
T12-3 to T8HP-3-High End-Retro-ElecHt-
V1987_1994 602,173 0.05 15
649 Non-Res Lighting-T12T8
F96T12 to T8HP-High End-Retro-ElecHt-
V1987_1994 602,173 0.11 15
650 Non-Res Lighting-CFL INC to CMH-High End-Retro-ElecHt-V1987_1994 81,900 0.09 15
652 Non-Res Lighting-HID
Med MH to T8HP-High End-Retro-ElecHt-
V1987_1994 441,447 0.12 15
653 Non-Res Lighting-T12T8
T12-3 to T8HP-3-High End-Retro-HtPmpHt-
V1987_1994 602,173 0.04 15
655 Non-Res Lighting-T12T8
F96T12 to T8HP-High End-Retro-HtPmpHt-
V1987_1994 602,173 0.09 15
656 Non-Res Lighting-CFL INC to CMH-High End-Retro-HtPmpHt-V1987_1994 81,900 0.07 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 701 of 729
658 Non-Res Lighting-HID
Med MH to T8HP-High End-Retro-HtPmpHt-
V1987_1994 441,447 0.10 15
659 Non-Res Lighting-T12T8
T12-3 to T8HP-3-High End-Retro-GasHt-
V1987_1994 602,173 0.06 15
661 Non-Res Lighting-T12T8
F96T12 to T8HP-High End-Retro-GasHt-
V1987_1994 602,173 0.10 15
662 Non-Res Lighting-CFL INC to CMH-High End-Retro-GasHt-V1987_1994 81,900 0.08 15
664 Non-Res Lighting-HID
Med MH to T8HP-High End-Retro-GasHt-
V1987_1994 441,447 0.11 15
665 Non-Res Lighting-T12T8T12-3 to T8HP-3-Anchor-Retro-ElecHt-V1987_1994 602,173 0.05 15
667 Non-Res Lighting-T12T8F96T12 to T8HP-Anchor-Retro-ElecHt-V1987_1994 602,173 0.10 15
668 Non-Res Lighting-CFL INC to CMH-Anchor-Retro-ElecHt-V1987_1994 81,900 0.08 15
670 Non-Res Lighting-HID
Med MH to T8HP-Anchor-Retro-ElecHt-
V1987_1994 441,447 0.11 15
671 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Anchor-Retro-HtPmpHt-
V1987_1994 602,173 0.03 15
673 Non-Res Lighting-T12T8
F96T12 to T8HP-Anchor-Retro-HtPmpHt-
V1987_1994 602,173 0.08 15
674 Non-Res Lighting-CFL INC to CMH-Anchor-Retro-HtPmpHt-V1987_1994 81,900 0.06 15
676 Non-Res Lighting-HID
Med MH to T8HP-Anchor-Retro-HtPmpHt-
V1987_1994 441,447 0.08 15
677 Non-Res Lighting-T12T8T12-3 to T8HP-3-Anchor-Retro-GasHt-V1987_1994 602,173 0.06 15
679 Non-Res Lighting-T12T8F96T12 to T8HP-Anchor-Retro-GasHt-V1987_1994 602,173 0.09 15
680 Non-Res Lighting-CFL INC to CMH-Anchor-Retro-GasHt-V1987_1994 81,900 0.07 15
682 Non-Res Lighting-HID
Med MH to T8HP-Anchor-Retro-GasHt-
V1987_1994 441,447 0.10 15
683 Non-Res Lighting-T12T8T12-3 to T8HP-2-K-12-Retro-ElecHt-V1987_1994 602,173 0.05 15
686 Non-Res Lighting-CFL INC to CFL-K-12-Retro-ElecHt-V1987_1994 145,600 0.09 15
687 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-K-12-Retro-ElecHt-
V1987_1994 602,173 0.03 15
688 Non-Res Lighting-HID Med MH to T8HP-K-12-Retro-ElecHt-V1987_1994 441,447 0.24 15
689 Non-Res Lighting-T12T8T12-3 to T8HP-2-K-12-Retro-HtPmpHt-V1987_1994 602,173 0.04 15
692 Non-Res Lighting-CFL INC to CFL-K-12-Retro-HtPmpHt-V1987_1994 145,600 0.06 15
693 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-K-12-Retro-HtPmpHt-
V1987_1994 602,173 0.02 15
694 Non-Res Lighting-HID
Med MH to T8HP-K-12-Retro-HtPmpHt-
V1987_1994 441,447 0.16 15
695 Non-Res Lighting-T12T8T12-3 to T8HP-2-K-12-Retro-GasHt-V1987_1994 602,173 0.05 15
698 Non-Res Lighting-CFL INC to CFL-K-12-Retro-GasHt-V1987_1994 145,600 0.07 15
699 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-K-12-Retro-GasHt-
V1987_1994 602,173 0.04 15
700 Non-Res Lighting-HID Med MH to T8HP-K-12-Retro-GasHt-V1987_1994 441,447 0.15 15
701 Non-Res Lighting-T12T8
T12-3 to T8HP-3-University-Retro-ElecHt-
V1987_1994 602,173 0.07 15
705 Non-Res Lighting-HID
Med MH to T8HP-University-Retro-ElecHt-
V1987_1994 441,447 0.16 15
706 Non-Res Lighting-T12T8
T12-3 to T8HP-3-University-Retro-HtPmpHt-
V1987_1994 602,173 0.05 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 702 of 729
710 Non-Res Lighting-HID
Med MH to T8HP-University-Retro-HtPmpHt-
V1987_1994 441,447 0.11 15
711 Non-Res Lighting-T12T8
T12-3 to T8HP-3-University-Retro-GasHt-
V1987_1994 602,173 0.06 15
715 Non-Res Lighting-HID
Med MH to T8HP-University-Retro-GasHt-
V1987_1994 441,447 0.11 15
716 Non-Res Lighting-T12T8
F96T12 to T8HP-Warehouse-Retro-ElecHt-
V1987_1994 602,173 0.14 15
718 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Warehouse-Retro-ElecHt-
V1987_1994 602,173 0.02 15
720 Non-Res Lighting-HID
Large MH to T5HO-Warehouse-Retro-ElecHt-
V1987_1994 441,447 0.09 15
721 Non-Res Lighting-T12T8
F96T12 to T8HP-Warehouse-Retro-HtPmpHt-
V1987_1994 602,173 0.10 15
723 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Warehouse-Retro-HtPmpHt-
V1987_1994 602,173 0.02 15
725 Non-Res Lighting-HID
Large MH to T5HO-Warehouse-Retro-HtPmpHt-
V1987_1994 441,447 0.07 15
726 Non-Res Lighting-T12T8
F96T12 to T8HP-Warehouse-Retro-GasHt-
V1987_1994 602,173 0.10 15
728 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Warehouse-Retro-GasHt-
V1987_1994 602,173 0.03 15
730 Non-Res Lighting-HID
Large MH to T5HO-Warehouse-Retro-GasHt-
V1987_1994 441,447 0.07 15
731 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Supermarket-Retro-ElecHt-
V1987_1994 602,173 0.01 15
733 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Supermarket-Retro-ElecHt-
V1987_1994 602,173 0.01 15
734 Non-Res Lighting-CFL
INC to CMH-Supermarket-Retro-ElecHt-
V1987_1994 81,900 0.04 15
737 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Supermarket-Retro-HtPmpHt-
V1987_1994 602,173 0.01 15
739 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Supermarket-Retro-
HtPmpHt-V1987_1994 602,173 0.01 15
740 Non-Res Lighting-CFL
INC to CMH-Supermarket-Retro-HtPmpHt-
V1987_1994 81,900 0.04 15
743 Non-Res Lighting-T12T8
T12-4 to T8HP-2-Supermarket-Retro-GasHt-
V1987_1994 602,173 0.03 15
745 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-Supermarket-Retro-GasHt-
V1987_1994 602,173 0.02 15
746 Non-Res Lighting-CFL
INC to CMH-Supermarket-Retro-GasHt-
V1987_1994 81,900 0.05 15
749 Non-Res Lighting-T12T8
T12-4 to T8HP-2-MIniMart-Retro-ElecHt-
V1987_1994 602,173 0.01 15
751 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-MIniMart-Retro-ElecHt-
V1987_1994 602,173 0.01 15
752 Non-Res Lighting-CFL INC to CMH-MIniMart-Retro-ElecHt-V1987_1994 81,900 0.05 15
754 Non-Res Lighting-HID
Med MH to T8HP-MIniMart-Retro-ElecHt-
V1987_1994 441,447 0.07 15
755 Non-Res Lighting-T12T8
T12-4 to T8HP-2-MIniMart-Retro-HtPmpHt-
V1987_1994 602,173 0.01 15
757 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-MIniMart-Retro-HtPmpHt-
V1987_1994 602,173 0.01 15
758 Non-Res Lighting-CFL INC to CMH-MIniMart-Retro-HtPmpHt-V1987_1994 81,900 0.04 15
760 Non-Res Lighting-HID
Med MH to T8HP-MIniMart-Retro-HtPmpHt-
V1987_1994 441,447 0.05 15
761 Non-Res Lighting-T12T8
T12-4 to T8HP-2-MIniMart-Retro-GasHt-
V1987_1994 602,173 0.03 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 703 of 729
763 Non-Res Lighting-T12T8
F96T12VHO to T8HP-4-MIniMart-Retro-GasHt-
V1987_1994 602,173 0.03 15
764 Non-Res Lighting-CFL INC to CMH-MIniMart-Retro-GasHt-V1987_1994 81,900 0.05 15
766 Non-Res Lighting-HID
Med MH to T8HP-MIniMart-Retro-GasHt-
V1987_1994 441,447 0.07 15
767 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Restaurant-Retro-ElecHt-
V1987_1994 602,173 0.06 15
768 Non-Res Lighting-CFL INC to CFL-Restaurant-Retro-ElecHt-V1987_1994 72,800 0.06 15
770 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Restaurant-Retro-HtPmpHt-
V1987_1994 602,173 0.04 15
771 Non-Res Lighting-CFL
INC to CFL-Restaurant-Retro-HtPmpHt-
V1987_1994 72,800 0.03 15
773 Non-Res Lighting-T12T8
T12-3 to T8HP-3-Restaurant-Retro-GasHt-
V1987_1994 602,173 0.06 15
774 Non-Res Lighting-CFL INC to CFL-Restaurant-Retro-GasHt-V1987_1994 72,800 0.05 15
776 Non-Res Lighting-T12T8
F96T12 to T8HP-Lodging-Retro-ElecHt-
V1987_1994 602,173 0.12 15
778 Non-Res Lighting-CFL INC to CFL-Lodging-Retro-ElecHt-V1987_1994 218,400 0.05 15
779 Non-Res Lighting-T12T8
F96T12 to T8HP-Lodging-Retro-HtPmpHt-
V1987_1994 602,173 0.09 15
781 Non-Res Lighting-CFL INC to CFL-Lodging-Retro-HtPmpHt-V1987_1994 218,400 0.04 15
782 Non-Res Lighting-T12T8
F96T12 to T8HP-Lodging-Retro-GasHt-
V1987_1994 602,173 0.09 15
784 Non-Res Lighting-CFL INC to CFL-Lodging-Retro-GasHt-V1987_1994 218,400 0.05 15
785 Non-Res Lighting-T12T8
F96T12 to T8HP-Hospital-Retro-ElecHt-
V1987_1994 602,173 0.17 15
787 Non-Res Lighting-CFL INC to CFL-Hospital-Retro-ElecHt-V1987_1994 9,100 0.07 15
788 Non-Res Lighting-T12T8
F96T12 to T8HP-Hospital-Retro-HtPmpHt-
V1987_1994 602,173 0.08 15
790 Non-Res Lighting-CFL INC to CFL-Hospital-Retro-HtPmpHt-V1987_1994 9,100 0.03 15
791 Non-Res Lighting-T12T8
F96T12 to T8HP-Hospital-Retro-GasHt-
V1987_1994 602,173 0.08 15
793 Non-Res Lighting-CFL INC to CFL-Hospital-Retro-GasHt-V1987_1994 9,100 0.05 15
794 Non-Res Lighting-T12T8
T12-3 to T8HP-3-OtherHealth-Retro-ElecHt-
V1987_1994 602,173 0.04 15
796 Non-Res Lighting-CFL INC to CFL-OtherHealth-Retro-ElecHt-V1987_1994 9,100 0.04 15
797 Non-Res Lighting-T12T8
T12-3 to T8HP-3-OtherHealth-Retro-HtPmpHt-
V1987_1994 602,173 0.04 15
799 Non-Res Lighting-CFL
INC to CFL-OtherHealth-Retro-HtPmpHt-
V1987_1994 9,100 0.03 15
800 Non-Res Lighting-T12T8
T12-3 to T8HP-3-OtherHealth-Retro-GasHt-
V1987_1994 602,173 0.04 15
802 Non-Res Lighting-CFL INC to CFL-OtherHealth-Retro-GasHt-V1987_1994 9,100 0.04 15
803 Non-Res Lighting-T12T8F96T12 to T8HP-Other-Retro-ElecHt-V1987_1994 602,173 0.08 15
807 Non-Res Lighting-HID
Large MH to T5HO-Other-Retro-ElecHt-
V1987_1994 441,447 0.05 15
808 Non-Res Lighting-T12T8
F96T12 to T8HP-Other-Retro-HtPmpHt-
V1987_1994 602,173 0.07 15
812 Non-Res Lighting-HID
Large MH to T5HO-Other-Retro-HtPmpHt-
V1987_1994 441,447 0.05 15
813 Non-Res Lighting-T12T8F96T12 to T8HP-Other-Retro-GasHt-V1987_1994 602,173 0.08 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 704 of 729
817 Non-Res Lighting-HID
Large MH to T5HO-Other-Retro-GasHt-
V1987_1994 441,447 0.05 15
818 Non-Res Lighting-T12T8
F96T12 to T8HP-Large Off-Retro-ElecHt-
V1995_2001 602,173 0.07 15
821 Non-Res Lighting-CFL INC to CFL-Large Off-Retro-ElecHt-V1995_2001 163,800 0.03 15
822 Non-Res Lighting-HID
Med MH to T8HP-Large Off-Retro-ElecHt-
V1995_2001 441,447 0.08 15
823 Non-Res Lighting-T12T8
F96T12 to T8HP-Large Off-Retro-HtPmpHt-
V1995_2001 602,173 0.07 15
826 Non-Res Lighting-CFL INC to CFL-Large Off-Retro-HtPmpHt-V1995_2001 163,800 0.03 15
827 Non-Res Lighting-HID
Med MH to T8HP-Large Off-Retro-HtPmpHt-
V1995_2001 441,447 0.08 15
828 Non-Res Lighting-T12T8
F96T12 to T8HP-Large Off-Retro-GasHt-
V1995_2001 602,173 0.07 15
831 Non-Res Lighting-CFL INC to CFL-Large Off-Retro-GasHt-V1995_2001 163,800 0.03 15
832 Non-Res Lighting-HID
Med MH to T8HP-Large Off-Retro-GasHt-
V1995_2001 441,447 0.08 15
833 Non-Res Lighting-T12T8
F96T12 to T8HP-Medium Off-Retro-ElecHt-
V1995_2001 602,173 0.09 15
836 Non-Res Lighting-CFL INC to CFL-Medium Off-Retro-ElecHt-V1995_2001 163,800 0.04 15
837 Non-Res Lighting-HID
Med MH to T8HP-Medium Off-Retro-ElecHt-
V1995_2001 441,447 0.10 15
838 Non-Res Lighting-T12T8
F96T12 to T8HP-Medium Off-Retro-HtPmpHt-
V1995_2001 602,173 0.08 15
841 Non-Res Lighting-CFL
INC to CFL-Medium Off-Retro-HtPmpHt-
V1995_2001 163,800 0.03 15
842 Non-Res Lighting-HID
Med MH to T8HP-Medium Off-Retro-HtPmpHt-
V1995_2001 441,447 0.09 15
843 Non-Res Lighting-T12T8
F96T12 to T8HP-Medium Off-Retro-GasHt-
V1995_2001 602,173 0.08 15
846 Non-Res Lighting-CFL INC to CFL-Medium Off-Retro-GasHt-V1995_2001 163,800 0.04 15
847 Non-Res Lighting-HID
Med MH to T8HP-Medium Off-Retro-GasHt-
V1995_2001 441,447 0.09 15
848 Non-Res Lighting-T12T8
T12-3 to T8HP-2-Small Off-Retro-ElecHt-
V1995_2001 602,173 0.03 15
851 Non-Res Lighting-CFL INC to CFL-Small Off-Retro-ElecHt-V1995_2001 163,800 0.06 15
853 Non-Res Lighting-T12T8
T12-3 to T8HP-2-Small Off-Retro-HtPmpHt-
V1995_2001 602,173 0.03 15
856 Non-Res Lighting-CFL INC to CFL-Small Off-Retro-HtPmpHt-V1995_2001 163,800 0.04 15
858 Non-Res Lighting-T12T8
T12-3 to T8HP-2-Small Off-Retro-GasHt-
V1995_2001 602,173 0.04 15
861 Non-Res Lighting-CFL INC to CFL-Small Off-Retro-GasHt-V1995_2001 163,800 0.05 15
863 Non-Res Lighting-T12T8
F96T12 to T8HP-Big Box-Retro-ElecHt-
V1995_2001 602,173 0.07 15
865 Non-Res Lighting-CFL INC to CMH-Big Box-Retro-ElecHt-V1995_2001 81,900 0.06 15
867 Non-Res Lighting-HID
Large MH to T5HO-Big Box-Retro-ElecHt-
V1995_2001 441,447 0.05 15
868 Non-Res Lighting-T12T8
F96T12 to T8HP-Big Box-Retro-HtPmpHt-
V1995_2001 602,173 0.06 15
870 Non-Res Lighting-CFL INC to CMH-Big Box-Retro-HtPmpHt-V1995_2001 81,900 0.05 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 705 of 729
872 Non-Res Lighting-HID
Large MH to T5HO-Big Box-Retro-HtPmpHt-
V1995_2001 441,447 0.04 15
873 Non-Res Lighting-T12T8F96T12 to T8HP-Big Box-Retro-GasHt-V1995_2001 602,173 0.06 15
875 Non-Res Lighting-CFL INC to CMH-Big Box-Retro-GasHt-V1995_2001 81,900 0.05 15
877 Non-Res Lighting-HID
Large MH to T5HO-Big Box-Retro-GasHt-
V1995_2001 441,447 0.04 15
878 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Box-Retro-ElecHt-
V1995_2001 602,173 0.10 15
881 Non-Res Lighting-CFL INC to CMH-Small Box-Retro-ElecHt-V1995_2001 81,900 0.08 15
882 Non-Res Lighting-HID
Med MH to T8HP-Small Box-Retro-ElecHt-
V1995_2001 441,447 0.12 15
883 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Box-Retro-HtPmpHt-
V1995_2001 602,173 0.08 15
886 Non-Res Lighting-CFL
INC to CMH-Small Box-Retro-HtPmpHt-
V1995_2001 81,900 0.06 15
887 Non-Res Lighting-HID
Med MH to T8HP-Small Box-Retro-HtPmpHt-
V1995_2001 441,447 0.09 15
888 Non-Res Lighting-T12T8
F96T12 to T8HP-Small Box-Retro-GasHt-
V1995_2001 602,173 0.08 15
891 Non-Res Lighting-CFL INC to CMH-Small Box-Retro-GasHt-V1995_2001 81,900 0.07 15
892 Non-Res Lighting-HID
Med MH to T8HP-Small Box-Retro-GasHt-
V1995_2001 441,447 0.09 15
893 Non-Res Lighting-T12T8
T12-3 to T8HP-2-High End-Retro-ElecHt-
V1995_2001 602,173 0.03 15
895 Non-Res Lighting-CFL INC to CMH-High End-Retro-ElecHt-V1995_2001 81,900 0.08 15
898 Non-Res Lighting-T12T8
T12-3 to T8HP-2-High End-Retro-HtPmpHt-
V1995_2001 602,173 0.02 15
900 Non-Res Lighting-CFL INC to CMH-High End-Retro-HtPmpHt-V1995_2001 81,900 0.07 15
903 Non-Res Lighting-T12T8
T12-3 to T8HP-2-High End-Retro-GasHt-
V1995_2001 602,173 0.04 15
905 Non-Res Lighting-CFL INC to CMH-High End-Retro-GasHt-V1995_2001 81,900 0.08 15
908 Non-Res Lighting-T12T8F96T12 to T8HP-Anchor-Retro-ElecHt-V1995_2001 602,173 0.10 15
911 Non-Res Lighting-HID
Med MH to T8HP-Anchor-Retro-ElecHt-
V1995_2001 441,447 0.11 15
912 Non-Res Lighting-T12T8
F96T12 to T8HP-Anchor-Retro-HtPmpHt-
V1995_2001 602,173 0.08 15
915 Non-Res Lighting-HID
Med MH to T8HP-Anchor-Retro-HtPmpHt-
V1995_2001 441,447 0.08 15
916 Non-Res Lighting-T12T8F96T12 to T8HP-Anchor-Retro-GasHt-V1995_2001 602,173 0.09 15
919 Non-Res Lighting-HID
Med MH to T8HP-Anchor-Retro-GasHt-
V1995_2001 441,447 0.10 15
920 Non-Res Lighting-T12T8F96T12 to T8HP-K-12-Retro-ElecHt-V1995_2001 602,173 0.21 15
923 Non-Res Lighting-CFL INC to CFL-K-12-Retro-ElecHt-V1995_2001 145,600 0.08 15
924 Non-Res Lighting-HID Med MH to T8HP-K-12-Retro-ElecHt-V1995_2001 441,447 0.23 15
925 Non-Res Lighting-T12T8F96T12 to T8HP-K-12-Retro-HtPmpHt-V1995_2001 602,173 0.14 15
928 Non-Res Lighting-CFL INC to CFL-K-12-Retro-HtPmpHt-V1995_2001 145,600 0.06 15
929 Non-Res Lighting-HID
Med MH to T8HP-K-12-Retro-HtPmpHt-
V1995_2001 441,447 0.16 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 706 of 729
930 Non-Res Lighting-T12T8F96T12 to T8HP-K-12-Retro-GasHt-V1995_2001 602,173 0.14 15
933 Non-Res Lighting-CFL INC to CFL-K-12-Retro-GasHt-V1995_2001 145,600 0.06 15
934 Non-Res Lighting-HID Med MH to T8HP-K-12-Retro-GasHt-V1995_2001 441,447 0.15 15
935 Non-Res Lighting-T12T8
F96T12 to T8HP-University-Retro-ElecHt-
V1995_2001 602,173 0.14 15
937 Non-Res Lighting-CFL INC to CFL-University-Retro-ElecHt-V1995_2001 145,600 0.06 15
939 Non-Res Lighting-T12T8
F96T12 to T8HP-University-Retro-HtPmpHt-
V1995_2001 602,173 0.10 15
941 Non-Res Lighting-CFL INC to CFL-University-Retro-HtPmpHt-V1995_2001 145,600 0.04 15
943 Non-Res Lighting-T12T8
F96T12 to T8HP-University-Retro-GasHt-
V1995_2001 602,173 0.10 15
945 Non-Res Lighting-CFL INC to CFL-University-Retro-GasHt-V1995_2001 145,600 0.05 15
947 Non-Res Lighting-T12T8
F96T12 to T8HP-Warehouse-Retro-ElecHt-
V1995_2001 602,173 0.14 15
949 Non-Res Lighting-CFL INC to CFL-Warehouse-Retro-ElecHt-V1995_2001 655,200 0.06 15
951 Non-Res Lighting-HID
Large MH to T5HO-Warehouse-Retro-ElecHt-
V1995_2001 441,447 0.09 15
952 Non-Res Lighting-T12T8
F96T12 to T8HP-Warehouse-Retro-HtPmpHt-
V1995_2001 602,173 0.10 15
954 Non-Res Lighting-CFL
INC to CFL-Warehouse-Retro-HtPmpHt-
V1995_2001 655,200 0.04 15
956 Non-Res Lighting-HID
Large MH to T5HO-Warehouse-Retro-HtPmpHt-
V1995_2001 441,447 0.07 15
957 Non-Res Lighting-T12T8
F96T12 to T8HP-Warehouse-Retro-GasHt-
V1995_2001 602,173 0.10 15
959 Non-Res Lighting-CFL INC to CFL-Warehouse-Retro-GasHt-V1995_2001 655,200 0.05 15
961 Non-Res Lighting-HID
Large MH to T5HO-Warehouse-Retro-GasHt-
V1995_2001 441,447 0.07 15
962 Non-Res Lighting-T12T8
F96T12 to T8HP-Supermarket-Retro-ElecHt-
V1995_2001 602,173 0.05 15
966 Non-Res Lighting-HID
Med MH to T8HP-Supermarket-Retro-ElecHt-
V1995_2001 441,447 0.06 15
967 Non-Res Lighting-T12T8
F96T12 to T8HP-Supermarket-Retro-HtPmpHt-
V1995_2001 602,173 0.05 15
971 Non-Res Lighting-HID
Med MH to T8HP-Supermarket-Retro-HtPmpHt-
V1995_2001 441,447 0.05 15
972 Non-Res Lighting-T12T8
F96T12 to T8HP-Supermarket-Retro-GasHt-
V1995_2001 602,173 0.06 15
976 Non-Res Lighting-HID
Med MH to T8HP-Supermarket-Retro-GasHt-
V1995_2001 441,447 0.06 15
977 Non-Res Lighting-T12T8
F96T12 to T8HP-MIniMart-Retro-ElecHt-
V1995_2001 602,173 0.06 15
979 Non-Res Lighting-CFL INC to CMH-MIniMart-Retro-ElecHt-V1995_2001 81,900 0.05 15
980 Non-Res Lighting-HID
Med MH to T8HP-MIniMart-Retro-ElecHt-
V1995_2001 441,447 0.07 15
981 Non-Res Lighting-T12T8
F96T12 to T8HP-MIniMart-Retro-HtPmpHt-
V1995_2001 602,173 0.05 15
983 Non-Res Lighting-CFL INC to CMH-MIniMart-Retro-HtPmpHt-V1995_2001 81,900 0.04 15
984 Non-Res Lighting-HID
Med MH to T8HP-MIniMart-Retro-HtPmpHt-
V1995_2001 441,447 0.05 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 707 of 729
985 Non-Res Lighting-T12T8
F96T12 to T8HP-MIniMart-Retro-GasHt-
V1995_2001 602,173 0.07 15
987 Non-Res Lighting-CFL INC to CMH-MIniMart-Retro-GasHt-V1995_2001 81,900 0.05 15
988 Non-Res Lighting-HID
Med MH to T8HP-MIniMart-Retro-GasHt-
V1995_2001 441,447 0.07 15
989 Non-Res Lighting-T12T8
F96T12 to T8HP-Restaurant-Retro-ElecHt-
V1995_2001 602,173 0.14 15
992 Non-Res Lighting-CFL INC to CFL-Restaurant-Retro-ElecHt-V1995_2001 72,800 0.06 15
994 Non-Res Lighting-T12T8
F96T12 to T8HP-Restaurant-Retro-HtPmpHt-
V1995_2001 602,173 0.08 15
997 Non-Res Lighting-CFL
INC to CFL-Restaurant-Retro-HtPmpHt-
V1995_2001 72,800 0.03 15
999 Non-Res Lighting-T12T8
F96T12 to T8HP-Restaurant-Retro-GasHt-
V1995_2001 602,173 0.09 15
1002 Non-Res Lighting-CFL INC to CFL-Restaurant-Retro-GasHt-V1995_2001 72,800 0.05 15
1004 Non-Res Lighting-T12T8
F96T12 to T8HP-Lodging-Retro-ElecHt-
V1995_2001 602,173 0.12 15
1006 Non-Res Lighting-CFL INC to CFL-Lodging-Retro-ElecHt-V1995_2001 218,400 0.05 15
1008 Non-Res Lighting-T12T8
F96T12 to T8HP-Lodging-Retro-HtPmpHt-
V1995_2001 602,173 0.09 15
1010 Non-Res Lighting-CFL INC to CFL-Lodging-Retro-HtPmpHt-V1995_2001 218,400 0.04 15
1012 Non-Res Lighting-T12T8
F96T12 to T8HP-Lodging-Retro-GasHt-
V1995_2001 602,173 0.09 15
1014 Non-Res Lighting-CFL INC to CFL-Lodging-Retro-GasHt-V1995_2001 218,400 0.05 15
1016 Non-Res Lighting-T12T8
F96T12 to T8HP-Hospital-Retro-ElecHt-
V1995_2001 602,173 0.17 15
1018 Non-Res Lighting-CFL INC to CFL-Hospital-Retro-ElecHt-V1995_2001 9,100 0.07 15
1019 Non-Res Lighting-HID
Med MH to T8HP-Hospital-Retro-ElecHt-
V1995_2001 441,447 0.19 15
1020 Non-Res Lighting-T12T8
F96T12 to T8HP-Hospital-Retro-HtPmpHt-
V1995_2001 602,173 0.08 15
1022 Non-Res Lighting-CFL INC to CFL-Hospital-Retro-HtPmpHt-V1995_2001 9,100 0.03 15
1023 Non-Res Lighting-HID
Med MH to T8HP-Hospital-Retro-HtPmpHt-
V1995_2001 441,447 0.08 15
1024 Non-Res Lighting-T12T8
F96T12 to T8HP-Hospital-Retro-GasHt-
V1995_2001 602,173 0.08 15
1026 Non-Res Lighting-CFL INC to CFL-Hospital-Retro-GasHt-V1995_2001 9,100 0.05 15
1027 Non-Res Lighting-HID
Med MH to T8HP-Hospital-Retro-GasHt-
V1995_2001 441,447 0.09 15
1028 Non-Res Lighting-T12T8
F96T12 to T8HP-OtherHealth-Retro-ElecHt-
V1995_2001 602,173 0.09 15
1030 Non-Res Lighting-CFL INC to CFL-OtherHealth-Retro-ElecHt-V1995_2001 9,100 0.04 15
1031 Non-Res Lighting-HID
Med MH to T8HP-OtherHealth-Retro-ElecHt-
V1995_2001 441,447 0.10 15
1032 Non-Res Lighting-T12T8
F96T12 to T8HP-OtherHealth-Retro-HtPmpHt-
V1995_2001 602,173 0.08 15
1034 Non-Res Lighting-CFL
INC to CFL-OtherHealth-Retro-HtPmpHt-
V1995_2001 9,100 0.03 15
1035 Non-Res Lighting-HID
Med MH to T8HP-OtherHealth-Retro-HtPmpHt-
V1995_2001 441,447 0.09 15
1036 Non-Res Lighting-T12T8
F96T12 to T8HP-OtherHealth-Retro-GasHt-
V1995_2001 602,173 0.08 15
1038 Non-Res Lighting-CFL INC to CFL-OtherHealth-Retro-GasHt-V1995_2001 9,100 0.04 15
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 708 of 729
1039 Non-Res Lighting-HID
Med MH to T8HP-OtherHealth-Retro-GasHt-
V1995_2001 441,447 0.09 15
1040 Non-Res Lighting-T12T8F96T12 to T8HP-Other-Retro-ElecHt-V1995_2001 602,173 0.08 15
1042 Non-Res Lighting-CFL INC to CFL-Other-Retro-ElecHt-V1995_2001 145,600 0.03 15
1043 Non-Res Lighting-HID Med MH to T8HP-Other-Retro-ElecHt-V1995_2001 441,447 0.09 15
1044 Non-Res Lighting-T12T8
F96T12 to T8HP-Other-Retro-HtPmpHt-
V1995_2001 602,173 0.07 15
1046 Non-Res Lighting-CFL INC to CFL-Other-Retro-HtPmpHt-V1995_2001 145,600 0.03 15
1047 Non-Res Lighting-HID
Med MH to T8HP-Other-Retro-HtPmpHt-
V1995_2001 441,447 0.08 15
1048 Non-Res Lighting-T12T8F96T12 to T8HP-Other-Retro-GasHt-V1995_2001 602,173 0.07 15
1050 Non-Res Lighting-CFL INC to CFL-Other-Retro-GasHt-V1995_2001 145,600 0.03 15
1051 Non-Res Lighting-HID Med MH to T8HP-Other-Retro-GasHt-V1995_2001 441,447 0.08 15
1058 Non-Res Lighting-Signs Outdoor Sign Ballast - Night 546,000 0.01 13
1059 Non-Res Lighting-Signs Outdoor Sign Ballast - 24 546,000 0.01 7
1060 Non-Res Lighting-Signs Outdoor Sign Ballast - Night - Retro 546,000 0.11 13
1061 Non-Res Lighting-Signs Outdoor Sign Ballast - 24 - Retro 546,000 0.09 7
1065 Non-Res EE Reach-In Refrigerator from E-Star Baseline 189,800 0.03 9
1067 Non-Res EE Reach-In Freezer from E-Star Baseline 351,800 0.01 9
1070 Non-Res EE Ice Maker from FEMP Baseline 82,043 0.07 9
1071 Non-Res EE Vending Machine from Average Baseline 147,056 0.04 9
1072 Non-Res EE Vending Machine from E-Star Baseline 115,544 0.02 9
1146 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
Large Off-ElecHt 60,667 0.09 21
1147 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
Large Off-HtPmpHt 60,667 0.08 21
1148 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
Large Off-GasHt 60,667 0.08 21
1149 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
Medium Off-ElecHt 60,667 0.13 21
1150 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
Medium Off-HtPmpHt 60,667 0.12 21
1151 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
Medium Off-GasHt 60,667 0.11 21
1152 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
Small Off-ElecHt 60,667 0.18 21
1153 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
Small Off-HtPmpHt 60,667 0.13 21
1154 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
Small Off-GasHt 60,667 0.11 21
1155 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-K-
12-ElecHt 60,667 0.22 21
1156 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-K-
12-HtPmpHt 60,667 0.15 21
1157 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-K-
12-GasHt 60,667 0.13 21
1158 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
University-ElecHt 60,667 0.17 21
1159 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
University-HtPmpHt 60,667 0.13 21
1160 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
University-GasHt 60,667 0.11 21
1161 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
OtherHealth-ElecHt 60,667 0.11 21
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 709 of 729
1162 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
OtherHealth-HtPmpHt 60,667 0.10 21
1163 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-New-
OtherHealth-GasHt 60,667 0.10 21
1164 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
Large Off-ElecHt 60,667 0.09 21
1165 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
Large Off-HtPmpHt 60,667 0.08 21
1166 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
Large Off-GasHt 60,667 0.08 21
1167 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
Medium Off-ElecHt 60,667 0.13 21
1168 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
Medium Off-HtPmpHt 60,667 0.12 21
1169 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
Medium Off-GasHt 60,667 0.11 21
1170 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
Small Off-ElecHt 60,667 0.18 21
1171 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
Small Off-HtPmpHt 60,667 0.13 21
1172 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
Small Off-GasHt 60,667 0.11 21
1173 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-K-
12-ElecHt 60,667 0.23 21
1174 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-K-
12-HtPmpHt 60,667 0.15 21
1175 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-K-
12-GasHt 60,667 0.13 21
1176 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
University-ElecHt 60,667 0.18 21
1177 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
University-HtPmpHt 60,667 0.13 21
1178 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
University-GasHt 60,667 0.11 21
1179 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
OtherHealth-ElecHt 60,667 0.11 21
1180 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
OtherHealth-HtPmpHt 60,667 0.10 21
1181 Non-Res Lighting-Daylighting
Perimeter Day lighting Controls (Advanced)-NR-
OtherHealth-GasHt 60,667 0.10 21
1290 Non-Res Appliances
Vending Machine Controller-Large Machine
w/Illuminated Front 49,920 0.02 10
1291 Non-Res Appliances
Vending Machine Controller-Small Machine or
Machine without Illuminated Front 33,280 0.03 10
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 710 of 729
2009

Electric
Integrated Resource Plan

Appendix G – Avista Distribution System
Efficiencies Program

August 31, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 711 of 729

Avista Distribution System Efficiencies Program

Programs to Reduce Energy Loss across Avista’s Distribution System

System Efficiencies Team Date 4/21/2009
Heather Cummins
Mark Weiss
Rodney Pickett
Dave Defelice
Curt Kirkeby
Ross Taylor
Greg Smith
Jill Ham
Will Stone
John McClain

Authored by: John Gibson

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 712 of 729
Executive Summary
Avista’s Distribution System consists of approximately three hundred and thirty feeders covering a geographical area of 30,000 square miles. The distribution feeders range in distribution voltage from
4.16 kV to 34.5 kV phase to phase and are typically rated to meet 10 MVA load for the typical 13.2 kV feeder. The distribution feeders reside in urban, suburban and rural areas and can range in length from 3
to 73 miles. The distribution feeders are typically designed to provide service for approximately one to two thousand residential customers.
The engineering analysis summarized in this report determines losses across the distribution system for
the following program areas: 1) Conductor losses, 2) Distribution Transformers, 3) Secondary Districts and 4) VAr compensation. Although additional programs like phase balancing and Conservation
Voltage Reduction (CVR) could have been included in the analysis, they were intentionally left out since daily operational activity may negate the energy savings. The energy loss, capital investment and
reduction in O&M costs resulting from the individual efficiencies programs were combined on a per feeder basis. This approach provided a means to rank and compare energy savings and net resource cost
for each feeder.
The efficiency analysis of the distribution feeders evaluated the existing energy losses and energy savings resulting from implementing the program upgrades. The study identified the existing
distribution system losses to be approximately 3.6%. Assuming, all of the distribution feeders studied were economically viable to upgrade, the resulting system energy losses would be reduced by 2%. The
total energy savings corresponding to the implementation of the upgrades would correspond to an energy savings of approximately 29.2 MW on peak and 13.5 MW on average.
Although it may not be prudent to upgrade all of the distribution feeders, this study ranks the feeders by
diminishing economic return. The economic metric used to rank feeders was net resource cost. The net resource cost for each feeder was determined for O&M offsets forecasted on a five, ten and fifteen year
time horizon. This variable O&M forecast provided a means to filter on or off the number of economically viable feeder upgrades. Other criteria used to reduce the number of viable feeder upgrade
projects included capital investment greater then $0.5 million and net resource cost less then $100 per Mwh.
The feeder upgrade program by itself falls short of being a strategic vision. However, it can be used as a
first step towards a broader strategic view to be included in programs like capital budgeting, energy efficiency, and O&M reduction. A more robust corporate strategic vision for aging infrastructure
rehabilitation would need to incorporate the following elements: 1) Movement of bulk power across our transmission system, 2) Optimum distribution topologies, 3) Substation size, locations and architectures,
and 4) Reliable forecasts of geographical centered load growth. Once these elements are incorporated into the existing feeder upgrade program, a long term plan for Avista’s electric infrastructure can be
developed to move infrastructure upgrades from a tactical or reactive approach to a planned replacement strategy.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 713 of 729
Introduction
Objective The objective of the system efficiency analysis was to obtain a first order of magnitude assessment of
energy savings across Avista’s electric distribution system. The analysis was constructed to address the following two questions: 1) How much energy savings is available across Avista’s distribution system?
2) Which feeders provide the most cost-effective for the least investment across the system?
Concession The analysis did not include operational or design options to assist in refining cost estimates or selecting
feeders for upgrade. Also, this analysis focused solely on the distribution system and did not consider system changes which may incorporate the installation of substations or new transmission lines.

Background
Avista’s electric distribution system consists of approximately three hundred and thirty feeders covering a geographical area of 30,000 square miles. The distribution feeders range in voltage from 4.16 kV to
34.5 kV phase to phase and are typically rated to meet 10 MVA load for a typical 13.2 kV feeder. The distribution feeders reside in urban, suburban and rural areas and can range in length from 3 to 73 miles.
The distribution feeders are typically designed to provide service from one to two thousand residential customers.
Past efficiency studies on Avista’s distribution system have typically focused on either individual
reinforcement projects or specific equipment upgrades. This current analysis differs from past analysis by combining several efficiency programs across most of Avista’s distribution feeders. The results of the
analysis provided an overall assessment of the energy savings on a per feeder basis. Also, this analysis incorporated capital, operational and maintenance costs into the economic assessment in order to
determine the net resource value.
Analysis Tool Set To determine efficiency gains associated with upgrading the distribution feeders, an analysis framework
was developed by combining complementary technologies existing at Avista. For example, the SynerGEE Electric tool and its corresponding analysis engine Solver was leveraged to perform power
flow analysis. Avista’s Facility Management (AFM) system and Major Equipment Tracking (MET) system were queried to obtain the number, age and sizes of transformers on the distribution feeders. In
addition, Avista’s Substation Control and Data Acquisition (SCADA) system provided annual peak load and VAr consumption at the substation buses. Finally, the economic analysis of the annual Operation
and Maintenance (O&M) forecast was approximated by Asset Managements Isograph Availability Workbench.

Engineering Analysis Methodology
The engineering analysis evaluated losses across the distribution system for the following program areas: 1) Conductor losses, 2) Distribution Transformers, 3) Secondary Districts and 4) VAr
compensation. The energy losses, capital investment and reduction in O&M costs resulting from the individual efficiencies programs were combined on a per feeder basis. This analysis approach provided
a means to rank and compare energy savings, along with return on investment, for each feeder. The individual programs methodology and assumptions are summarized in the descriptions below.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 714 of 729

Reconductoring The Distribution Engineering Group builds and maintains the SynerGEE distribution databases. The
SynerGEE databases require material size, type and network topology for Avista’s distribution feeders
as provided by the Avista Facilities Management (AFM) system. These databases provide a network
model from which a power flow analysis can be performed to evaluate thermal and voltage performance
of each feeder. The power flow analysis accuracy is dependent upon these SynerGEE databases being
both current and accurate. The internal work processes used to maintain the SynerGEE models are
summarized below.

• Avista’s AFM system is maintained by applications which support the design of new facilities,
outages, operations and maintenance activities on the distribution system.
• An internally developed AFM application called Model Builder is used to upload the AFM data
into a SynerGEE Model database
• Distribution Engineering reviews the SynerGEE Models and performs system calibration of the
models.
• At the distribution feeder bus, a peak current meter read is recorded and inputted by Distribution
Planning.
In order to perform a power flow analysis for all three hundred plus feeders, in this system efficiency
analysis, the process was automated by utilizing Advantica’s Solver engine. By using Solver, a scripting tool was developed to run multiple power flow iterations utilizing the SynerGEE models. The first
iteration evaluated the energy loss with existing conductor and flagged conductor which did not adhere to Distribution Engineering’s new economic conductor standard summarized in Table 1. The second
iteration updated the flagged conductor with the new conductor standard and evaluated the energy loss.
Table 1 Economic Conductor Standard Ampacity Range Selected Conductor
0 to 25 Amps 2ACSR
26 to 100 Amps 4/0AAC
101 to 250 Amps 556AAC
251 to 700 Amps 795AAC

The incremental energy savings resulting from reconductoring the feeder was determined by evaluating
the peak loss of KW for the existing conductor versus the new conductor standards. Once the peak
incremental loss was determined between the two runs, an average energy loss was calculated. The
average energy loss was determined by multiplying the peak loss by a loss factor. The loss factor was
determined by squaring the load factor. The assumptions used in the analysis are summarized in the list
below.

• The load factor for the distribution feeders were approximated by evaluating the load factor at
several of the substation buses with hourly SCADA data
• The load factor used for the distribution analysis was 50 percent
• The loss factor used for the distribution analysis was 25 percent

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 715 of 729

Overhead Transformers Between 1986 and 1987, Distribution Engineering conducted a set of no-load tests on approximately
two hundred overhead transformers of various sizes, types and vintages. From the tests, a set of curves
were developed to approximate the no-load losses for a transformer rating and age class (see Appendix).
As a result, the no-load curves showed the loss for a particular transformer could be categorized into the
following three vintages of transformers: 1) Pre-1960, 2) 1960 – 1983, 3) Post 1983.

In 2008, Distribution Engineering implemented a new design standard for overhead transformers which
is based on a life-cycle cost analysis and recently established an avoided cost of energy value of
$66/MW. Consequently, the new transformer design standards specify transformers with no-load losses
less then recently enacted Department of Energy (DOE) transformer efficiency standards. Upgrading the
older overhead transformers accounted for a significant incremental energy savings in no-load losses.

A software script was developed within the AFM system to retrieve the number, size and vintage of
transformers located on distribution feeders. The analysis assumed the overhead transformers would be
replaced in-kind with the new lower no load loss overhead transformers. The difference between the no-
load loss of the old and new transformer accounts for the incremental energy savings. The overhead
transformer no-load loss occurs every hour of the year and is independent of the actual load. Therefore,
the incremental energy savings are an average value. The transformer population for particular vintage
classes is summarized in Table 2, for overhead transformers only.

Table 2 Overhead Transformer Vintages
Vintage Population Number
Pre1963 10,416
1963 - 1983 32,788
Post 1983 43,204

Secondary Districts
Up to the late 1960’s, Avista designed and constructed large secondary districts in residential
neighborhoods. A secondary district is designed with a distribution transformer and a three wire
secondary lines which provided service tie positions for up to thirty customers. At the time of
construction, these districts were economically viable since they increased the customer to transformer
ratio. Due to the increased cost of energy and associated operational O&M costs, the elimination or
redesign of the secondary districts were evaluated for efficiency gains.

To determine the number of secondary districts on a feeder, an AFM script was written to identify the
number of customers connected to a distribution transformer. To support the analysis, a secondary
district was defined as an overhead transformer with twelve or more service premises. Using this
classification, the ten feeders with the most secondary districts returned from the AFM query is
summarized in Table 3.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 716 of 729
Table 3 Feeder Secondary Districts
Feeder Name Number of Secondary Districts
Ross Park 12F1 56
Ross Park 12F6 55
Ross Park 12F5 53
Sunset 12F3 52
Lyons & Standard 12F2 49
Francis & Cedar 12F1 47
Fort Wright 12F1 43
Beacon 12F5 40
Collage & Walnut 12F5 39
Third & Hatch 12F2 37

In order to evaluate the reduction in energy losses, a SynerGEE power flow analysis was performed on
some typical secondary districts. To improve the efficiency of the secondary districts, two options were
considered: 1) Reduce the district length by the addition of a transformer, 2) Reconductoring the district
with insulated triplex conductor. The power flow analysis concluded districts with more then twenty two
service premises should be reduced in length by the addition of an overhead transformer, while districts
with less then twenty two service premises should be replaced using overhead triplex wire.

The secondary district analysis only reviewed the reduction of energy loss and did not consider other
design considerations such as flicker and reliability. Although an operational case could be made to
eliminate districts by the addition of transformers for every four services, the energy loss in the
transformers exceed the energy savings in the elimination of the district. The average KW loss
associated with the district types is summarized in Table 4 below.

Table 4 Secondary District Type
Secondary District Type Average KW Loss
10-12 .234
12-22 .356
22 and up 1.03

VAr Compensation Another efficiency program evaluated the reduction of current on the line by offsetting the reactive load
with the installation of switched capacitors. A VAr controller operates the switched capacitor to respond to adverse reactive loading on a feeder. The amount of energy savings associated with the installation of
switched capacitors depends upon the feeder power factor. To a large extent, motor loading required for air conditioning drives the reactive loading on a feeder. Consequently, the number of hours a switched
capacitor operates is seasonal. The analysis methodology developed for evaluating the energy savings associated for a feeder is described below.
The Ninth and Central feeders were modeled to determine the size and type of switched capacitors as
well as the annual hours of operation. A SCADA point located at Ninth and Central provided the amount of MVAr loading on a substation transformer on a per hour basis. A load duration curve developed from
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 717 of 729
this data determined the capacitor size and hours of operation. Once sized, SynerGEE’s capacitor
placement application optimized both the peak power savings and the ideal placement of the capacitor.
The energy savings obtained by installing the capacitor was determined by multiplying the number of
hours of operation by the KW savings to MVAr ratio.

This analysis methodology was simplified for the rest of the feeders by assuming the KW to MVAr ratio
for all distribution feeders. The capacitor size for the rest of the feeders was assumed to be a single 900
KVAr bank. The hours of operation for the 900 KVAr were based on the load duration curve.

Economic Analysis The economic analysis for the feeder upgrade programs estimated the capital investment, calculated the
energy savings and forecasted operational and maintenance expense and interim capital investments. The capital investment required to implement the efficiencies programs were obtained from engineering
estimates described below. The energy savings for a feeder upgrade was determined by the efficiency programs described previously. Finally, Asset Management modeled the feeders using their tools and
forecasted the reduction in operational and maintenance expense resulting from the feeder upgrade, also described below.

Engineering Estimate
Reconductoring The material and labor estimate were performed by Distribution Engineering in conjunction with
Planning and are based on 2008 material and labor costs. The reconductoring estimate was based on whether the conductor was being replaced or whether new construction was necessary to install the
conductor. The assumptions made in the unit pricing for each case are summarized in the list below.
New Construction
• New Pole
• New Anchors
• New Cross Arms
Replacement
• 40 % replacement of the poles, cross arms and anchors

The conductor replacement unit price is summarized in the Table 5 below.

Table 5 Conductor Unit Price
CONDUCTOR_TYPE
Replacement
$/Per Mile
New Construction
$/Per Mile
795AAC $60,000 $85,000
556AAC $45,000 $71,000
4/0AAC $35,000 $52,000
2ACSR $30,000 $42,000

Distribution Transformers
The engineering estimates for distribution transformers were obtained from Purchasing and are based on 2008 material and labor costs. The overhead transformers met the new design requirements for no-load
losses. The estimated unit prices for various sized overhead transformers are summarized in Table 6.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 718 of 729
Table 6 Overhead Transformers
Overhead Transformers Installed Cost
15 KVA $1,014
25 KVA $1,301
37.5 KVA $1,952
75 KVA $2,519
100 KVA $3,278
150 KVA $3,430
225 KVA $3,936
300 KVA $4,310

Secondary Districts
The engineering estimates to redesign secondary districts were determined for three distinct archetypes.
The secondary district archetypes were based on the number of customers attached to overhead
transformers. The labor and material costs to redesign the secondary districts for the distinct archetypes
are listed in Table 7.

Table 7 Secondary Districts
Secondary District Archetypes Cost
10-12 Customer Service Points $5,728 - $8,687
13-22 Customer Service Points $6,181 - $8,820
>22 Customer Service Points $7,539 - $10,498

VAr Compensation The labor and material estimate for switched capacitors were based on recently purchased and installed
capacitors. The cost for the purchased and installed capacitors for a 900 KVAr bank was $11,000.

Asset Management The Asset Management team developed the Availability Workbench Model for six distribution feeders.
The Availability Workbench Model combines input from the following areas: 1) system performance, 2)
facility data, 3) manager and crafts 4) industry data, and 5) key performance indicators. From these
inputs, the workbench application generates a forecasted annualized O&M and Capital cost model. The
cost model is generated by comparing O&M expense resulting after a feeder upgrade versus the O&M
expense for a base case. Asset Managements base case assumes the equipment will be replaced upon
failure.
The Asset Management analysis results indicated that upgrading the feeders reduces forecasted O&M
expense when compared to the base case. The feeder upgrade program replaces aged equipment with new equipment to improve system efficiencies and reliability. The replacement of equipment reduces
future O&M expenditures which is an economic benefit to the project and is included in the analysis. The reduction and avoidance of future increases in O&M expenditures are illustrated in Figure 1. The
base case curve shows an exponential growth in O&M costs resulting from failure of the aging equipment failing. The feeder upgrade curve shows an initial increase in revenue requirement
corresponding to the cost of the upgrade but shows how the revenue requirement rises slower due to the replacement of the aging facility.
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 719 of 729

Figure 1 O&M Cost Programs

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Base Case Feeder Upgrade

The Asset Management program conducted an O&M analysis for the following six feeders: 1)
9CE12F4, 2) SUN12F3, 3) SUN12F1, 4) SUN12F2, 5) COL12F2, 6) KET12F2. The Asset Management team estimated the time to develop a Workbench model to determine the O&M expenditure was
approximately thirty hours per feeder. To reduce the time to perform the analysis, the O&M expenditure curve determined for the six feeders was used to interpolate the expenditure for the other feeders. The
linear interpolation was based on a strong correlation between the O&M expense and the length of the feeders analyzed.
In order to limit the interpolation, the O&M expense was generated only for feeders with lengths
between 12.5 miles (SUN12F3) and149 miles (KET12F2). Consequently, feeders with lengths outside this range were not included in the net resource cost analysis. Although the feeders were not included in
the analysis the may still be economically viable. One example is the ORI12F3 feeder which ranks first in energy savings as shown Table 12. However, the feeder was not included in the net resource cost
analysis since its length of 170 miles exceeded the maximum mileage criteria used for the analysis.
Energy Results The efficiency analysis of the distribution feeders evaluated the existing energy losses and energy
savings resulting from implementing the program upgrades. The study identified the existing distribution system losses to be approximately 3.6%. Assuming, all of the distribution feeders studied
were economically viable to upgrade, the resulting system energy losses would be reduced by 2%. The total energy savings corresponding to the implementation of the upgrades would correspond to an
energy savings of approximately 29.2 MW on peak and 13.5 MW on average. The energy savings break down across each program is described below.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 720 of 729
Reconductoring
The reconductoring program as mentioned previously used the SynerGEE application to determine the conductor losses across our feeders. The distribution conductor operating at twenty percent or greater of
its rated ampacity was upgraded to the new distribution standard, if warranted. The analysis was run again to determine the incremental reduction in conductor losses corresponding to the conductor
upgrade. The results of the analysis are summarized in Table 8.
Table 8 Reconductoring Power Savings
Number of
Feeders
Peak
Loss KW
Average
Loss KW
Peak Loss Savings
KW
Average Loss
Savings KW
302 35,676 8,919 14,973 3,743

Overhead Transformers The efficiency analysis evaluated the no-load losses across the existing transformer population to
determine the average no-load transformer loss on Avista’s distribution feeders. The incremental energy
savings was determined by taking the difference between the no-load losses of the new transformer
standard versus the older vintage transformers. The results of the analysis are summarized in Table 9.

Table 9 Overhead Transformer Power Savings
Vintage Total number of
Transformers Average Loss
KW
Average Loss
Savings KW
Pre1963 10,416 4700 1,907
1963 To 1983 32,788 9470 5,710

Secondary Districts The energy losses corresponding to the secondary districts were categorized by the number of service
premises connected to the district. The incremental energy savings from the redesign of these districts
was determined by taking the difference between the existing losses and the new designed district losses.
The results of the analysis are summarized in Table 10.

Table 10 Secondary Districts Power Savings
Archetypes
Number
of
Districts
Peak
Loss KW
Avg. Power
Loss KW
Peak Loss
Savings KW
Avg. Power
Savings KW
10 - 12 Customer
Service Points 3,414 5,516 1,379 3,196 799
13 - 22 Customer
Service Points 1,302 3,156 789 1,856 464
> 22 Customer
Service Points 32 196 49 132 33
TOTAL 4,748 8,868 2,217 5,184 1,296

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 721 of 729
VAr Compensation
A VAr duration curve across Avista’s load was developed from the electric transmission SCADA data. This load duration curve helped to book mark the amount of reactive load on Avista’s system. The
analysis assumed approximately 100 MVAr of reactive load could be offset in the distribution system. It was also assumed that standard switched bank installation of 900 KVAr would be deployed for a single
feeder. Therefore, approximately 112 feeders would have switched capacitors installed. Finally, as mentioned previously the ratio between kilowatts savings for megavar compensation was determined by
evaluating several distribution feeders. The results of the savings are shown in Table 11.
Table 11 VAr Compensation Power Savings
Number of
Feeders
Bank Size KW Savings Average Hours
Operation
Peak Power
Savings KW
Avg Power
Savings KW
112 900 KVAr 13 5100 1456 847
In addition to reviewing the individual programs for energy savings, the programs were combined on a
per feeder basis. This allowed the feeders to be ranked on the total amount of energy savings available on a per feeder basis. Table 12 provides the number of feeders which would provided power savings
over one hundred kilowatts. The list of feeders and corresponding power savings is listed in Table 12.
Table 12 Top Feeder Power Savings
Feeder Name Total Cost
Total Average
kW
ORI12F3 $1,170,357 201
CHW12F3 $1,682,503 184
SPI12F1 $1,243,066 172
WIL12F2 $1,705,623 155
KET12F2 $968,669 143
STM631 $1,211,798 139
CLV34F1 $1,765,413 127
F&C12F1 $1,499,055 123
ROX751 $1,069,310 120
BEA12F2 $1,423,808 116
SUN12F3 $1,224,379 113
GIF34F2 $1,253,973 112
BEA12F1 $1,221,446 111
COB12F2 $822,727 109
RAT231 $1,111,882 108
ORO1281 $669,953 107
CLV12F4 $907,259 105
ROS12F1 $1,428,530 104
ROS12F6 $1,316,652 102
L&S12F2 $1,101,072 101
BEA12F5 $1,210,094 101

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 722 of 729
Economic Ranking
Although it may not be prudent to upgrade all of the distribution feeders, this study ranks the feeders by diminishing economic return. The economic metric used to rank feeders was net resource cost. The net
resource cost for each feeder was determined for O&M offsets forecasted on a five, ten and fifteen year time horizon. This variable O&M forecast provided a means to filter on or off the number of
economically viable feeder upgrades. Other criteria used to reduce the number of viable feeder upgrade projects included capital investment greater then $0.5 million and net resource cost less then $100 per
MW.
The ranking of the most viable economic feeder upgrades are illustrated in the following three tables. Table 13, Table 14 and Table 15 is based on a five, ten and fifteen year O&M time horizon respectively.

Table 13 Net Resource Cost - Five Year O&M
Feeder
Net Resource Cost
$/Mwh
Capital
Investment KW
KET12F2 $55.00 $968,669.0 142.99
SPI12F1 $67.73 $1,243,065.8 171.98
ORO1281 $68.58 $669,953.1 106.53
COL12F2 $74.92 $822,726.8 108.96
COB12F2 $74.92 $822,726.8 108.96
LF34F1 $76.29 $595,875.0 72.71
COB12F1 $82.87 $671,737.4 77.55
PVW241 $89.40 $528,985.4 53.68
CLV12F4 $89.83 $907,259.4 105.03
L&R512 $94.53 $546,237.7 55.02
OLD721 $94.87 $608,545.7 67.75
ARD12F2 $95.35 $817,711.5 82.33
STM631 $97.26 $1,211,797.7 139.36
ROX751 $99.44 $1,069,309.6 120.48

Table 14 Net Resource Cost – Ten Year O&M
Feeder Net Resource Cost
$/Mwh
Capital
Investment KW
KET12F2 $31.00 $968,669.0 142.99
SPI12F1 $49.19 $1,243,065.8 171.98
LF34F1 $51.54 $595,875.0 72.71
PVW241 $56.55 $528,985.4 53.68
ORO1281 $56.75 $669,953.1 106.53
COL12F2 $57.56 $822,726.8 108.96
COB12F2 $57.56 $822,726.8 108.96
COB12F1 $59.29 $671,737.4 77.55
CHW12F2 $60.29 $600,325.8 41.95
L&R512 $63.81 $546,237.7 55.02
ARD12F2 $70.17 $817,711.5 82.33
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 723 of 729
Feeder Net Resource Cost
$/Mwh
Capital
Investment KW
CLV12F4 $72.60 $907,259.4 105.03
GIF34F2 $72.61 $1,253,972.5 112.27
OLD721 $73.12 $608,545.7 67.75
MIS431 $79.16 $780,915.9 57.44
F&C12F2 $80.57 $610,746.1 65.07
RDN12F1 $81.47 $519,904.7 34.81
ORI12F1 $81.53 $832,306.2 75.82
FOR12F1 $81.55 $560,782.7 39.13
CKF711 $83.62 $912,659.4 88.03
STM631 $85.11 $1,211,797.7 139.36
PF213 $85.38 $579,843.8 55.23
PRA222 $85.48 $543,659.3 51.64
NE12F2 $85.54 $508,476.3 45.31
ROX751 $86.10 $1,069,309.6 120.48
RAT231 $86.36 $1,111,881.6 108.16
PUL112 $86.42 $528,311.9 44.24
SE12F2 $86.66 $714,903.4 69.83
TEN1256 $87.12 $789,201.9 85.49
GLN12F2 $88.33 $584,770.4 51.32
LIB12F3 $88.64 $529,971.6 46.50
CLV12F2 $88.87 $904,207.9 90.25
PUL116 $89.22 $537,639.7 45.27
CRG1261 $89.84 $561,702.8 44.85
APW112 $91.22 $522,196.7 45.53
WAK12F1 $93.01 $560,901.0 48.81
DEE12F2 $93.14 $743,960.8 69.63
GRV1274 $94.16 $671,626.1 66.96
PDL1202 $94.22 $581,246.6 55.32
SUN12F5 $95.38 $642,722.3 52.58
LIB12F2 $95.47 $726,778.1 58.98
DAL131 $97.14 $870,985.5 84.97
SAG741 $97.29 $634,916.4 44.82
BKR12F1 $98.20 $683,595.8 64.18
DEE12F1 $98.39 $996,523.0 67.68
M15515 $99.16 $540,077.6 44.53
SE12F4 $99.42 $686,532.3 59.34
M15512 $99.50 $531,004.8 43.84

Table 15 Net Resource Cost - Fifteen Year O&M
Feeder
Net Resource Cost
$/Mwh
Capital
Investment KW
CHW12F2 $2.9 $600,325.8 41.95
KET12F2 $4.6 $968,669.0 142.99
PVW241 $23.3 $528,985.4 53.68
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 724 of 729
Feeder
Net Resource Cost
$/Mwh
Capital
Investment KW
LF34F1 $26.4 $595,875.0 72.71
SPI12F1 $28.9 $1,243,065.8 171.98
RDN12F1 $29.4 $519,904.7 34.81
L&R512 $32.8 $546,237.7 55.02
FOR12F1 $34.0 $560,782.7 39.13
MIS431 $35.1 $780,915.9 57.44
COB12F1 $35.3 $671,737.4 77.55
GIF34F2 $39.5 $1,253,972.5 112.27
COL12F2 $39.9 $822,726.8 108.96
COB12F2 $39.9 $822,726.8 108.96
ARD12F2 $44.1 $817,711.5 82.33
ORO1281 $44.8 $669,953.1 106.53
AIR12F1 $48.7 $615,395.6 49.12
OLD721 $51.3 $608,545.7 67.75
PUL112 $51.6 $528,311.9 44.24
CRG1261 $54.0 $561,702.8 44.85
ORI12F1 $54.7 $832,306.2 75.82
CLV12F4 $55.1 $907,259.4 105.03
NE12F2 $55.5 $508,476.3 45.31
PUL116 $56.2 $537,639.7 45.27
DEE12F1 $56.5 $996,523.0 67.68
SAG741 $57.4 $634,916.4 44.82
GLN12F2 $58.3 $584,770.4 51.32
LIB12F3 $59.0 $529,971.6 46.50
PF213 $60.1 $579,843.8 55.23
PRA222 $60.3 $543,659.3 51.64
F&C12F2 $60.5 $610,746.1 65.07
CKF711 $61.5 $912,659.4 88.03
ODN731 $61.9 $627,946.4 44.01
APW112 $62.8 $522,196.7 45.53
SE12F2 $64.1 $714,903.4 69.83
SUN12F5 $64.6 $642,722.3 52.58
WAK12F1 $65.2 $560,901.0 48.81
LIB12F2 $65.8 $726,778.1 58.98
RAT231 $65.9 $1,111,881.6 108.16
CLV12F2 $70.0 $904,207.9 90.25
M15515 $70.7 $540,077.6 44.53
DEE12F2 $70.8 $743,960.8 69.63
M15512 $71.5 $531,004.8 43.84
TEN1256 $71.6 $789,201.9 85.49
ROX751 $72.7 $1,069,309.6 120.48
STM631 $72.8 $1,211,797.7 139.36
SE12F4 $74.2 $686,532.3 59.34
PDL1202 $74.6 $581,246.6 55.32
SPT4S30 $75.7 $541,420.5 44.99
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 725 of 729
Feeder
Net Resource Cost
$/Mwh
Capital
Investment KW
CHE12F4 $76.2 $667,293.8 57.48
OGA611 $76.5 $780,992.8 58.08
GRV1274 $77.5 $671,626.1 66.96
SOT522 $77.7 $632,142.6 51.02
CFD1210 $78.0 $563,163.3 45.20
SOT521 $78.4 $538,938.7 46.10
BKR12F1 $79.3 $683,595.8 64.18
NE12F1 $79.6 $687,832.8 62.33
DAL131 $79.8 $870,985.5 84.97
PDL1203 $81.8 $559,682.9 45.75
CFD1211 $82.4 $734,775.9 65.51
MIL12F3 $82.8 $619,499.7 55.10
CDA123 $83.5 $672,854.8 56.29
9CE12F1 $83.5 $616,123.8 54.88
MEA12F2 $83.7 $750,315.2 63.99
SIP12F4 $84.3 $634,440.7 53.05
CHE12F1 $84.3 $629,576.6 54.28
SOT523 $84.9 $1,023,389.6 89.92
NW12F1 $85.1 $788,923.6 73.66
WIL12F2 $86.5 $1,705,622.8 155.22
TEN1254 $86.6 $582,980.2 48.35
ECL222 $86.7 $686,592.4 60.28
CDA124 $86.8 $641,838.7 55.52
M15513 $87.1 $736,558.1 67.36
F&C12F6 $88.2 $658,978.5 57.70
TEN1255 $89.2 $607,926.6 50.49
SLK12F1 $89.4 $854,712.8 72.56
MIL12F4 $89.6 $831,468.1 75.37
LOL1359 $90.7 $830,015.9 73.31
CHE12F2 $90.8 $642,694.9 54.26
SPU123 $91.2 $724,338.0 60.68
9CE12F2 $92.9 $764,865.0 66.97
CDA121 $92.9 $623,762.0 50.00
TEN1257 $93.0 $740,138.0 65.15
WAK12F2 $93.6 $765,628.4 67.80
9CE12F4 $93.7 $774,787.7 68.61
SLW1358 $93.7 $717,636.7 62.17
CDA125 $94.4 $863,793.5 70.73
EFM12F1 $95.0 $950,734.3 79.18
NW12F3 $96.7 $746,886.7 62.10
M23621 $97.1 $641,972.3 43.52
MIL12F1 $100.3 $798,146.0 68.01
SUN12F6 $101.5 $789,282.4 66.28

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 726 of 729
Conclusion
The intent of this system efficiency analysis was to develop and implement a methodology to identify and quantify remedies to reducing losses across Avista’s distribution system. The results of this analysis
can then be folded into a broader infrastructure strategy. A program to systematically refresh feeders can be combined with existing internal programs like asset management and capital budgeting to identify
synergistic work alignments. For example, a project schedule could be developed to upgrade feeders based on energy, operational, reliability and maintenance priorities. Today, capital work is typically
driven by system capacity constraints. With the results obtained in this analysis, capital projects could be aligned with corporate economic goals of reducing energy loss and offsetting O&M expenditures.
The benefits identified in the feeder upgrade program assumed the upgrades would be deployed in a
comprehensive manner. The temptation to implement individual efficiency program components across the system may compromise the performance of a feeder as an energy delivery system. The efficient and
reliable delivery of electrical energy across the Avista feeders is best met by incorporating all of the electrical components in the upgrade. This systemic approach may help guide how programs should be
implemented across the organization.
Today, Avista implements projects in fairly discrete work silos influenced by departmental task structure and budget constraints. Examples of these type of programs are joint use, pole test and treat, failed
equipment, new revenue and specific capital project budgeting. Consequently, the programs are dispersed across multiple feeders resulting in different crews working on the same feeder at different
times over multiple years. The feeder upgrade program could be used not only to achieve energy savings but also be used as a springboard to consolidate and coordinate work efforts. Rather than referring to
work groups by departmental names like Distribution Engineering, Operations or Asset Management, they may be better served by being aligned with actual work processes like capital and operational
feeder programs.
The feeder upgrade program by itself falls short of being a strategic vision. However, it can be used as a
first step towards a broader strategic view to be included in programs like capital budgeting, energy efficiency, and O&M cost reduction. A more robust corporate strategic vision for aging infrastructure
rehabilitation would need to incorporate the following elements: 1) Movement of bulk power across our transmission system, 2) Optimum distribution topologies, 3) Substation size, locations and architectures,
and 4) Reliable forecasts of geographical centered load growth. Once these elements are incorporated into the existing feeder upgrade program, a long term plan for Avista’s electric infrastructure can be
developed to move infrastructure upgrades from a tactical or reactive approach to a planned replacement strategy.

Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 727 of 729
2009

Electric
Integrated Resource Plan

Appendix H – 2009 Electric IRP Avista New
Resource Table

August 31, 2009
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 728 of 729
Resource POR Capacity Year
Resource Location or Local Area POD Start Stop MW Total
Lancaster CCCT Rathdrum, ID Bell/Westside AVA System 1/1/2010 10/31/2026 125.0
Lancaster CCCT Rathdrum, ID Mid-C AVA System 1/1/2010 10/31/2026 150.0 275.0
Noxon 3 (incremental)Noxon, MT Noxon, MT AVA System 1/1/2010 Indefinite 14.0 14.0
Noxon 2 (incremental)Noxon, MT Noxon, MT AVA System 1/1/2011 Indefinite 14.0 14.0
Noxon 4 (incremental)Noxon, MT Noxon, MT AVA System 1/1/2012 Indefinite 14.0
Nine Mile (incremental)Nine Mile, WA Nine Mile, WA AVA System 1/1/2012 Indefinite 8.8
Wind Reardan, WA Reardan, WA AVA System 1/1/2012 Indefinite 90.0
Wind TBD TBD AVA System 1/1/2012 Indefinite 60.0 172.8
Little Falls (incremental)Ford, WA Little Falls, WA AVA System 1/1/2013 Indefinite 1.0 1.0
Little Falls (incremental)Ford, WA Little Falls, WA AVA System 1/1/2014 Indefinite 1.0 1.0
Little Falls (incremental)Ford, WA Little Falls, WA AVA System 1/1/2016 Indefinite 1.0 1.0
Wind TBD TBD AVA System 1/1/2019 Indefinite 150.0
CCCT TBD Bell/Westside AVA System 1/1/2019 Indefinite 250.0 400.0
Upper Falls (incremental)Spokane, WA Spokane, WA AVA System 1/1/2020 Indefinite 2.0 2.0
Wind TBD TBD AVA System 1/1/2022 Indefinite 50.0 50.0
CCCT TBD TBD AVA System 1/1/2024 Indefinite 250.0 250.0
CCCT TBD TBD AVA System 1/1/2027 Indefinite 250.0 250.0
Total 1431 1431
August 26, 2009
2009 Avista IRP
New Resource Table
Page 1 of 1
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 5, Page 729 of 729

CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality

Palouse Wind Board Involvement Documentation
Pages 1 through 24
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 6, Page 1 of 24

CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality

2011 Renewables Request for Proposal Process and Results
Pages 1 through 93
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 7, Page 1 of 93

CONFIDENTIAL subject to Attorney’s Certificate of Confidentiality
Compact Disc Exhibit
Palouse Wind Power Purchase Agreement
Pages 1 through 261
Exhibit No. 4
Case Nos. AVU-E-12-08
R. Lafferty, Avista
Schedule 8, Page 1 of 261