20150831Avista 2015 IRP Appendices.pdf

2015
Electric
Integrated Resource Plan
August 31, 2015
Appendices
Table of Contents
Appendix A – Technical Advisory Committee Presentations (Page 1)
Technical Advisory Committee Meeting 1 (Page 2)
Technical Advisory Committee Meeting 2 (Page 68)
Technical Advisory Committee Meeting 3 (Page 178)
Technical Advisory Committee Meeting 4 (Page 263)
Technical Advisory Committee Meeting 5 (Page 381)
Technical Advisory Committee Meeting 6 (Page 520)

Appendix B – 2015 Work Plan (Page 558)

Appendix C – AEG Studies (Page 568)
Demand Response Study (Page 569)
Conservation Potential Assessment (Page 647)

Appendix D – Avista Generation Energy Efficiency Studies (Page 779)
Boulder Park Generation Facility (Page 780)
Cabinet Gorge Hydroelectric Dam (Page 794)
Coyote Springs 2 Thermal Generating Facility (Page 798)
Kettle Falls Generating Facility (Page 814)
Little Falls Generating Facility (Page 826)
Long Lake Hydroelectric Dam (Page 833)
Nine Mile Hydroelectric Dam (Page 856)
Northeast Combustion Turbine (Page 860)
Noxon Rapids Hydroelectric Dam (Page 865)
Post Falls Hydroelectric Dam (Page 868)
Post Street/Upper Falls Hydroelectric Facilities (Page 874)
Rathdrum Combustion Turbine (Page 883)

Appendix E – Transmission (Page 889)
New Resource Table for Transmission (Page 890)
Avista System Planning 2014 IRP Interconnection Study (Page 891)

2015 Electric Integrated
Resource Plan

Appendix A – 2015 Technical
Advisory Committee
Presentations

2015 Electric IRP Appendix A
1

2015 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 1 Agenda
Thursday, May 29, 2014
Conference Room 428

Topic Time Staff
Introductions 8:30 Kalich

TAC Meeting Expectations 8:35 Lyons

2013 IRP Commission Acknowledgements 9:00 Kalich

Break 10:00

2013 Action Plan Update 10:15 Gall
Energy Independence Act Compliance 11:30 Gall/Lyons

Lunch 12:00

Pullman Energy Storage Project 1:00 Gibson

Demand Response Study Discussion 1:30 Kalich

Break 2:00

Draft 2015 Electric IRP Work Plan 2:15 Lyons

Adjourn 3:00

2015 Electric IRP Appendix A
2
2015 Electric IRP
TAC Meeting Expectations
John Lyons, Ph.D.
First Technical Advisory Committee Meeting
May 29, 2014
2015 Electric IRP Appendix A
3
Integrated Resource Planning
• The Integrated Resource Plan (IRP):

• Required by Idaho and Washington every other year

• Guides resource strategy over the next two years

• Resource procurements over the next 20 years –
Preferred Resource Strategy (PRS)

• Snapshot of the current and projected load & resource
position
2 2015 Electric IRP Appendix A
4
Integrated Resource Planning (Cont)
• Based on significant modeling and many assumptions
– Fuel prices
– Economic activity
– Policy considerations
– Resource costs
– Energy efficiency
• Action Items – areas for more research in the next IRP
• This is not an advocacy forum
• Not a forum on a particular resource or resource type
• Supports rate recovery, but not a preapproval process

3 2015 Electric IRP Appendix A
5
Technical Advisory Committee
• The public process piece of the IRP – input on what to study, how to
study, and review of assumptions and results

• Wide range of participants in all or some of the process

• Open forum, but we need to stay on topic to get through the agenda

• Welcome requests for studies or different assumptions.
– Time or resources may limit the amount of studies we can do
– The earlier study requests are made, the more accommodating we can be

• Planning team is also available by email or phone for questions or
comments between the TAC meetings

4 2015 Electric IRP Appendix A
6
Expectations
• Avista:
– Input about assumptions and areas to study
– Six TAC meetings with set agendas that can change based on
input. Topics will be covered later today in the Draft Work Plan.

• TAC Members: What are your expectations?

5 2015 Electric IRP Appendix A
7
2013 IRP Commission Acknowledgements
Clint Kalich
First Technical Advisory Committee Meeting
May 29, 2014
2015 Electric IRP Appendix A
8
Idaho Acceptance Order (32980)
• No Public Comments
• Comments by ICL, SRA, and SC/MEIC
– Concerns with Colstrip costs and risk analysis
• Regional haze, GHG regulation, prevention of significant deterioration,
ambient air quality standards, mercury and air toxics, coal combustion
waste, coal costs
– Request more analysis of Colstrip replacement options
– Too much natural gas in the plan
– Changes to net metering rules are not necessary

2
2015 Electric IRP Appendix A
9
Idaho Acceptance Order (32980)
• Comments by IPUC Staff
– Accept IRP as filed
– Additional analysis of net metering and impacts on system
– Closely monitor load growth for 2015 IRP given significant
decrease between 2011 and 2013 IRPs
– More detailed analysis around selected planning margin
– More description of rationale for arriving at Conservation
Achievable Potential Savings
3
2015 Electric IRP Appendix A
10
Idaho Acceptance Order (32980)
• Idaho Commission Order
– Accept 2013 IRP as filed
– Encourage commenters to actively participate in 2015 IRP
– Consider and discuss concerns and suggestions offered by
commenters
– Continue exploring demand response
– Continue to monitor federal environmental regulations, and their
impacts on planning
– Monitor actual load growth for 2015 IRP

4
2015 Electric IRP Appendix A
11
Washington Acceptance Letter
• No Public Comments
• Commission
– Evaluate value of risk mitigation when choosing among
competing resource strategies. Provide justification of the
choice of the PRS, including desired level of portfolio risk
–Re-evaluate planning margin
– Investigate modeling energy efficiency as a selectable and
scalable resource within the IRP (PRiSM)
– Incorporate a non-zero carbon value in the Expected Case
– Continue evaluating Colstrip, including rate impacts of a
hypothetical portfolio absent them
– Evaluate the benefits of storage to Avista’s generation portfolio

5
2015 Electric IRP Appendix A
12
Idaho Acknowledgement Order Specifics
6
2015 Electric IRP Appendix A
13
Washington Acceptance Letter Specifics
7
2015 Electric IRP Appendix A
14
2013 IRP Action Plan Update
James Gall
First Technical Advisory Committee Meeting
May 29, 2014
2015 Electric IRP Appendix A
15
Action Items- A Progress Report
Existing
Resources Identifying Need Demand
Forecasting
Supply Side
Options Policy Implications Demand Side
Options
Evaluation Resource Selection Transmission
2 2015 Electric IRP Appendix A
16
Demand Forecasting
• Review and update the energy forecast methodology to
better integrate economic, regional, and weather drivers
of energy use.
– Move from 30-year average temperatures to 20-year moving
average
– Integration of U.S. industrial production as an economic driver
– Discuss the relationship between energy demand and
population, energy pricing, income, and family size

3 2015 Electric IRP Appendix A
17
Existing Resources
• Continue to evaluate scenarios related to Colstrip and
how each scenario may impact power supply costs.
– Avista will update its 2013 IRP scenarios and consider other
scenarios later in the process
• Evaluate options to integrate intermittent resources.
– As part of the storage RFP, we will get information regarding
demand side options (to be discussed later)
– Avista is part of the Energy Imbalance Market (EIM) process
– Avista is developing a 1 MW storage project to test this benefit
(to be discussed later)

4 2015 Electric IRP Appendix A
18
Identifying Need
• Evaluate the benefits of a short-term (up to 24-months)
capacity position report.
– Avista will implement this report this summer for single hour and
sustained peak events
– Report will integrate short-term planning and long-term capacity
planning
• Revisit with the TAC the benefits and costs of the
Company’s 2013 IRP planning margin target to
determine if a different level is warranted in the 2015
IRP.
– Current method is 14% of peak load plus operating reserves &
regulation
– To be discussed at future TAC meeting
5 2015 Electric IRP Appendix A
19
Policy Implications
• Continue monitoring state and federal climate change
policies and report work from Avista’s Climate Change
Council.
–Gov. Inslee’s executive order and the EPA’s Emission
Performance Standards are current climate change initiatives
• Evaluate and explicitly document various options for
quantifying carbon costs in the IRP
– For discussion at future TAC meeting
• Work with TAC to determine which carbon quantification
method should be employed in the Expected Case of the
2015 IRP
– Washington Order requires a non-zero carbon cost
– For discussion at future TAC meeting
6 2015 Electric IRP Appendix A
20
Supply Side Options
• Consider Spokane and Clark Fork River hydro upgrade options in
the next IRP as potential resource options to meet energy, capacity
and environmental requirements.
– To be included as resource options in 2015 plan
• Continue to evaluate potential locations for the natural gas-fired
resource identified to be online by the end of 2019, including
environmental reviews, transmission studies, and potential land
acquisition.
– Avista is working to identify potential locations
• Use Avista’s new modeling capabilities to further evaluate the
benefits of storage resources to its generation portfolio, including the
impacts on ancillary services needs.
– Avista is in process of modeling storage in its new portfolio optimization
tool
7 2015 Electric IRP Appendix A
21
Demand Side
• Work with NPCC, commissions, and others to resolve
adjusted market baseline issues for setting energy
efficiency target setting and acquisition claims in
Washington
– Completed in December 2013 and is discussed in the 2014-15
WA Biennial Conservation Plan
• Update processes and protocols for conservation
measurement, evaluation and verification
– The third party evaluator “Cadmus” completed the study and will
be filed May 30th as part of the 2012-13 compliance/ cost
recovery/ prudence case in Washington

8 2015 Electric IRP Appendix A
22
Demand Side (Continued)
• Commission a demand response potential and cost
assessment of commercial and industrial customers per
its inclusion in the middle of the PRS action plan
– RFP to be released in June, to be discussed this afternoon
• Assess energy efficiency potential on Avista’s generation
facilities
– This study is in process of this study and will be a presentation
on the findings at a future TAC meeting

9 2015 Electric IRP Appendix A
23
Transmission
• Work to maintain Avista’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
• Study and quantify transmission and distribution efficiency projects
as they apply to EIA goals
– Navigant completed the study and will be filed May 30th as part of the
2012-13 compliance/ cost recovery/ prudence case in Washington

10 2015 Electric IRP Appendix A
24
Evaluation
• Continue participation in regional IRP and regional
planning processes and monitor regional surplus
capacity and continue to participate in regional capacity
planning processes.
– We participate in the NPCC’s 7th Plan, PNUCC, Regional IRPs
• Evaluate the impacts of targeting individual or groups of
energy efficiency options within PRiSM instead of
targeting quantities using avoided cost
–A test will be completed this summer using the 2013 IRP data to
compare the methodologies.
– The results will be discussed at a future TAC meeting along with
a decision whether or not to use PRiSM or the current avoided
cost methodology for the 2015 plan
11 2015 Electric IRP Appendix A
25
Evaluation (Continued)
• Evaluate with the TAC the impacts of different points
along the efficient frontier.
– For discussion at future TAC meeting

12 2015 Electric IRP Appendix A
26
Energy Independence Act Compliance
(Renewable Energy)
James Gall and John Lyons, Ph.D.
First Technical Advisory Committee Meeting
May 29, 2014
2015 Electric IRP Appendix A
27
The Energy Independence Act
• RCW 19.285 or Initiative Measure No. 937
– Voted into Washington law November 2006
– Utilities with more than 25,000 customers qualify
– Requires acquisition of all cost-effective conservation
• Renewable energy goals
– Based on a percentage of the two year average of Washington
state retail sales
– 3% by January 1, 2012 (166,047 MWh or 19 aMW)
– 9% by January 1, 2016 (506,000 MWh or 57.8 aMW)
– 15% by January 1, 2020 (867,000 MWh or 99 aMW)
2 2015 Electric IRP Appendix A
28
Energy Independence Act
• RCW 19.285 – The Energy Independence Act (EIA) or
Initiative Measure No. 937 (I-937)
• Requires utilities with over 25,000 customers to
obtain 15% of their electricity from qualified
renewable resources by 2020.
• Qualified resources include solar, wind, hydro
upgrades, biomass, and wave/ocean/tidal power.
• Requires the acquisition of all cost-effective energy
conservation.
• I-937 approved by Washington voters on November 6,
2006.

3 3 2015 Electric IRP Appendix A
29
Reporting Requirements
Annual compliance report (WAC 480-109-040) is due annually by June 1st:
• Report includes: background, alternative compliance (cost or low load
growth), annual loads, renewable energy target for last year, current year
progress, WREGIS certificates, incremental cost, and appendices

• Appendix A – UTC Compliance Report Spreadsheet: details about
eligible resources and renewable resource credits (RECs)

• Appendix B – Incremental Cost Calculations

• Appendices C, D and E – Clark Fork River, Spokane River and
Wanapum Hydro Upgrade Calculations

• Appendix F – Department of Commerce EIA Renewables Report

4 4 2015 Electric IRP Appendix A
30
Ongoing Issues
Active rulemaking by the Washington Commission and the
Department of Commerce
• Reporting issues – WREGIS and attestations
• Incremental hydro quantities
• Incremental cost calculation

5 2015 Electric IRP Appendix A
31
Incremental Cost Calculation
6
• Incremental hydro filed as a zero incremental cost
• Palouse wind: Incremental system cost- $8.2m
– Washington Share: $5.4m
• Idaho REC transfer: $350k
• Total Washington Incremental Cost: $5.7m
• 1.22% of Washington Revenue Requirement
2015 Electric IRP Appendix A
32
2013 EIA Compliance
MWh aMW
Required Renewable Energy 166,740 19.0
Spokane River
Long Lake #3 14,197 1.6
Little Falls #4 4,862 0.6
Clark Fork River
Cabinet Gorge 2-4 95,333 10.8
Noxon Rapids 1-4 55,697 6.4
Wanapum Fish Bypass 21,927 2.5
Total Hydro Upgrades 192,016 21.9
Palouse Wind (Includes apprentice credit) 356,432 40.7
7 7 2015 Electric IRP Appendix A
33
Avista’s Projected EIA Compliance
0
20
40
60
80
100
120
140
20
1
2
20
1
3
20
1
4
20
1
5
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1
6
20
1
7
20
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
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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 Hydro Upgrades Qualifying Resources Purchased RECs
Available Bank Requirement & Contingency Requirement
8 2015 Electric IRP Appendix A
34
Energy Storage Proposal for Washington
State Clean Energy Fund
John Gibson
First Technical Advisory Committee Meeting
May 29, 2014
2015 Electric IRP Appendix A
35
Agenda
Washington Clean Energy Fund
• Target Categories
• Schedule
• Avista Consortium
Vanadium Flow Battery
Energy Storage System Architecture
Use Case Value Streams

2015 Electric IRP Appendix A
36
Washington Clean Energy Fund
Target Categories
$15 Million in Total Funding:
Preliminary discussions on funding: Avista; PSE; Snohomish PUD

✓Integrate intermittent renewable energy projects through energy
storage and information technology (IT)
✓Demonstrate dispatch of energy storage resources from utility
energy control centers
-Use thermal properties and electric load of buildings or district
energy systems to store energy
✓Improve reliability and reduce cost of intermittent or distributed
energy resources
2015 Electric IRP Appendix A
37
Washington Clean Energy Fund
Schedule
2015 Electric IRP Appendix A
38
Washington State Clean Energy Fund
Avista Team

Avista Consortium
• UniEnergy Technologies – Vanadium Flow Battery
• Pacific Northwest National Laboratory – Value Stream Methodology
• Washington State University – Optimization Value Stream Algorithm
2015 Electric IRP Appendix A
39
Vanadium Flow Battery
Chemistry
•Charging the Battery:
–The electrical energy is converted into chemical energy stored in the vanadium ion
tanks
•Discharging the Battery:
–The vanadium electrolytes are pumped into battery central stack
–The chemical energy is converted into electrical energy by transferring electrons

2015 Electric IRP Appendix A
40
Vanadium Flow Battery
Performance
•Can be quickly brought up to full power when needed
– response time charge to discharge (50ms)
•Offers a long cycle life > (UET: 10,000 cycles)
•Energy efficiencies charge to discharge AC to AC 70%
•Does not present a fire hazard and uses no highly reactive or toxic substances
•Can sit idle for long periods of time without losing storage capacity

2015 Electric IRP Appendix A
41
Vanadium Flow Battery
Container
2015 Electric IRP Appendix A
42
Vanadium Flow Battery
System Footprint
2015 Electric IRP Appendix A
43
Energy Storage System
Architecture
SCADA
EMS
DMS
Value
Engine
Battery
Control
Vanadium Flow Battery
Use Cases – Value Streams
Automated FDIR and IVVC
2015 Electric IRP Appendix A
44
Avista Smart Grid System
Integration
2015 Electric IRP Appendix A
45
Washington State Clean Energy Fund
Use Cases - Value Streams
•Transmission System
•Distribution System
•Micro-grid Operations
•Maximizing the Total Value of Storage
•Demand Response and Energy Storage
2015 Electric IRP Appendix A
46
Use Case
Bulk Power /Transmission System

•Energy Shifting
–The use case will demonstrate the following grid services:
•Near-zero energy pricing market – abundant wind and water resource
•General arbitrage instrument – charging during low-price discharging during high
price
•Provide Grid Flexibility
–The use case will demonstrate the following grid services:
•Regulation services and load following grid services – battery operational
boundaries
•Services for ramping and flex rate markets

2015 Electric IRP Appendix A
47
Use Case
Distribution System

•Improved Distribution Systems Efficiency
–The use case will demonstrate the following grid services:
•Volt/Var control with local and/or remote information
–4-quadrant inverter controller to perform Volt/Var control
•Load shaping service
–Demand limiting strategy – demand threshold
–Deferment of distribution system upgrades
•Outage Management of Critical Loads
–The use case will demonstrate the following grid services:
•Critical load support for one customer or several customer load components
•Enhanced Voltage Control
–The use case will demonstrate the following grid services:
•Expand the voltage control strategy to support enhanced CVR

2015 Electric IRP Appendix A
48
Use Case
Micro-grid, Optimal Utilization of Energy Storage, Demand
Response

•Grid-connected and islanded micro-grid operations
–The use case will demonstrate the following grid services:
•Micro-grid operation while grid-connected
•Micro-grid operation in islanded mode
•Optimal Utilization of Energy Storage
–The use case will demonstrate the following grid services:
•The use-case must demonstrate the optimization of multiple use cases
•Demand Response and Energy Storage
–The use case will demonstrate the following grid services:
•The demand response can be coupled to storage to optimize the use of battery

2015 Electric IRP Appendix A
49
Example: Wind Generation
2015 Electric IRP Appendix A
50
Questions
17 2015 Electric IRP Appendix A
51
CEF - Systems Overview
2015 Electric IRP Appendix A
52
Battery Network Diagram
2015 Electric IRP Appendix A
53
WA State Clean Energy Fund - Grant
Schedule:
Project Award: June 20, 2014
Installation: 2nd Qtr 2015
Use Case Testing: All of 2015
All Use Cases In Service: 3rd Qtr 2016
Avista Consortium
SCADA
EMS
DMS
Value
Engine
Battery
Control
1.2 MW, 3.6MWh Capacity
Vanadium Flow Battery
2015 Electric IRP Appendix A
54
WA State Clean Energy Fund - Grant
Schedule:
Project Award: June 20, 2014
Installation: 2nd Qtr 2015
Use Case Testing: All of 2015
All Use Cases In Service: 3rd Qtr 2016
Avista Consortium
SCADA
EMS
DMS
Value
Engine
Battery
Control
1.2 MW, 3.6MWh Capacity
Vanadium Flow Battery
2015 Electric IRP Appendix A
55
2015 Electric IRP Appendix A
56
2015 Electric IRP Appendix A
57
Draft 2015 Electric IRP Work Plan

John Lyons, Ph.D.
First Technical Advisory Committee Meeting
May 29, 2014
2015 Electric IRP Appendix A
58
Technical Advisory Committee Meetings
•TAC 1 (May 29, 2014): TAC Meeting Expectations, 2013 IRP
Acknowledgement Letters, 2015 Action Plan Update, Pullman Energy Storage
Project, Energy Independence Act Compliance & Forecast, Demand Response
Study Discussion, and draft 2015 Electric IRP Work Plan.
•September 2014: Review conservation selection methodology, energy and
economic forecasts, generation options, and 2014 Shared Value Report.
•November 2014: Peak load forecast, reliability planning, Colstrip discussion,
energy storage technologies, 2015 IRP modeling, and energy efficiency.
•February 2015: Electric and natural gas price forecasts, transmission
planning, resource needs assessment, and market portfolio scenario
development.
•March 2015: Draft Preferred Resource Strategy (PRS), review of scenarios
and futures, and portfolio analysis.
•June 2015: Review of the final PRS and Action Items.

2 2 2015 Electric IRP Appendix A
59
2015 Draft Electric IRP Timeline
Preferred Resource Strategy (PRS) Tasks Target Date
Finalize energy demand forecast July 2014
Identify regional resource options for electric market price forecast September 2014
Identify Avista’s supply & conservation resource options September 2014
Finalize Peak Load Forecast September 2014
Update AURORAxmp database for electric market price forecast October 2014
Finalize data sets/statistics variables for risk studies October 2014
Energy efficiency load shapes input into AURORAxmp October 2014
Draft transmission study due October 2014
Energy efficiency load shapes input into AURORAxmp October 2014
Final transmission study due December 2014
Finalize Distribution Feeder Forecast December 2014
Select natural gas price forecast December 2014
Finalize deterministic base case December 2014
Due date for study requests January 15,2015
Base case stochastic study complete January 2015
Finalize PRiSM model January 2015
Develop efficient frontier and PRS January 2015
Simulation of risk studies “futures’ complete February 2015
Simulate market scenarios in AURORAxmp February 2015
Evaluate resource strategies against market futures and scenarios March 2015
Present preliminary study and PRS to TAC March 2015 3 3
2015 Electric IRP Appendix A
60
2015 Draft Electric IRP Timeline
Writing Tasks Target Date
File 2015 IRP Work Plan August 29, 2014
Prepare report and appendix outline October 2014
Prepare text drafts April 2015
Prepare charts and tables April 2015
Internal drafts released at Avista May 2015
External draft released to the TAC June 2015
Final editing and printing August 2015
Final IRP submission to Commissions and distribution to TAC August 31, 2015
4 4
2015 Electric IRP Appendix A
61
2015 IRP 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
5 5
2015 Electric IRP Appendix A
62
2015 Electric IRP Draft Outline
• Executive Summary
• Introduction and Stakeholder Involvement
• Economic and Load Forecast
– Economic Conditions
– Avista Energy and Peak Load Forecast
– Load Forecast Scenarios
• Existing Resources
– Avista Resources
– Contractual Resources and Obligations
6 6
2015 Electric IRP Appendix A
63
2015 Electric IRP Draft Outline
• Energy Efficiency and Demand Response
– Conservation Potential Assessment
– Demand Response Opportunities
•Long-Term Position
– Reliability Planning and Reserve Margins
– Resource Requirements
– Reserves and Flexibility Assessment
• Policy Considerations
– Environmental Concerns
– Greenhouse Gas Issues
– State and Federal Policies
7 7
2015 Electric IRP Appendix A
64
2015 Electric IRP Draft Outline
• Transmission Planning
– Avista’s Transmission System
– Future Upgrades and Interconnections
– Transmission Construction Costs and Integration
– Transmission and Distribution Efficiencies
• Generation Resource Options
– New Resource Options
– Avista Plant Upgrades
8 8
2015 Electric IRP Appendix A
65
2015 Electric IRP Draft Outline
• Market Analysis
– Marketplace
– Fuel Price Forecasts
– Market Price Forecast
– Scenario Analysis
• Preferred Resource Strategy
– Resource Selection Process
– 2015 Preferred Resource Strategy
– Efficient Frontier Analysis
– Avoided Cost
9 9
2015 Electric IRP Appendix A
66
2015 Electric IRP Draft Outline
• Portfolio Scenarios
– Portfolio Scenarios
– Tipping Point Analysis
• Action Plan
– 2013 Action Plan Summary
– 2015 Action Plan
10 10
2015 Electric IRP Appendix A
67

2015 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 2 Agenda
Tuesday, September 23, 2014
Conference Room 130
Topic Time Staff
1. Introduction & TAC 1 Recap 8:30 Lyons

2. Conservation Selection Methodology 8:35 Gall

3. Load and Economic Forecasts 9:15 Forsyth

4. Shared Value Report 10:45 Fielder

5. Lunch 11:30

6. Generation Options 12:30 Gall/Dempsey

7. Clean Power Plan Proposal Discussion 1:45 Lyons/Kalich

8. Adjourn 3:00

2015 Electric IRP Appendix A
68
2015 Electric IRP
TAC Meeting Expectations and Schedule
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
September 23, 2014
2015 Electric IRP Appendix A
69
Technical Advisory Committee
• The public process piece of the IRP – input on what to study, how to
study, and review of assumptions and results
• Wide range of participants in all or some of the process
• Open forum, but we need to stay on topic to get through the agenda
• Welcome requests for studies or different assumptions.
– Time or resources may limit the amount of studies we can do
– The earlier study requests are made, the more accommodating we can be
– January 15, 2015 is the final date to receive study requests
• Action Items – areas for more research in the next IRP
• This is not an advocacy forum
• Not a forum on a particular resource or resource type
• Supports rate recovery, but not a preapproval process
• Planning team is available by email or phone for questions or
comments between the TAC meetings
2 2015 Electric IRP Appendix A
70
Remaining TAC Meetings
•TAC 3 – Friday, November 21, 2014: Planning margin,
Colstrip discussion, cost of carbon, modeling overview and
conservation potential assessment methodology.
•TAC 4 – February 2015: Electric and natural gas price
forecasts, transmission planning, resource needs
assessment, market and portfolio scenario development,
energy storage and ancillary service evaluation
•TAC 5 – March 2015: Completed conservation potential
assessment, draft PRS, review of scenarios and futures and
portfolio analysis
•TAC 6 – June 2015: Review of final PRS and action items.
3 2015 Electric IRP Appendix A
71
2015 IRP Tasks for the PRS
Exhibit 1: 2015 Electric IRP Timeline
Task Target Date
Preferred Resource Strategy (PRS)
Finalize energy demand forecast July 2014
Identify Avista’s supply & conservation resource options September 2014
Finalize peak load forecast September 2014
Update AURORAxmp database for market price forecast October 2014
Energy efficiency load shapes input into AURORAxmp October 2014
Finalize datasets/statistics variables for risk studies November 2014
Transmission study due December 2014
Finalize distribution feeder forecast December 2014
Select natural gas price forecast December 2014
Finalize deterministic base case January 2015
Due date for study requests Jan. 15, 2015
Base case stochastic study complete January 2015
Develop efficient frontier and PRS January 2015
Finalize PRiSM model February 2015
Simulation of risk studies “futures” complete February 2015
Simulate market scenarios in AURORAxmp February 2015
Evaluate resource strategies against market futures and
scenarios
March 2015
Present preliminary study and PRS to TAC March 2015

4 2015 Electric IRP Appendix A
72
2015 IRP Writing Tasks – Work Plan
Writing Tasks
File 2015 IRP work plan August 2014
Prepare report and appendix outline October 2014
Prepare text drafts April 2015
Prepare charts and tables April 2015
Internal draft released at Avista May 2015
External draft released to the TAC June 2015
Final editing and printing August 2015
Final IRP submission and TAC August 31, 2015

5 2015 Electric IRP Appendix A
73
Conservation Modeling Options
James Gall
Second Technical Advisory Committee Meeting
September 23, 2014
2015 Electric IRP Appendix A
74
2013 IRP WUTC Acknowledgement
Request
….the Commission requests that Avista, together with input
from the TAC, investigate incorporating energy efficiency
into its 2015 IRP as a selectable resource within PRiSM.
1.The model cannot readily adapt to new scenarios, changes in
model assumptions, or the different avoided costs generated
under various resource strategies.
2.The model cannot choose to accelerate acquisition of
conservation, even in cases where the acceleration of
acquisition is the least-cost resource or provides substantial risk
mitigation value. Instead, the acquisition rate is defined by the
ramp rates within the CPA.
2 2015 Electric IRP Appendix A
75
Avista’s 2005-2013 IRP Conservation
Selection Methodology
1.Develop a Conservation Potential Assessment (CPA) study
2.Identify resource requirements prior to conservation
3.PRiSM selects generating resources to meet resource deficits
4.Avoided energy, capacity, and risk costs are derived from resource
selection
5.Potential conservation measures are compared to Avoided Costs
and the economic conservation is selected (uses 10% premium on
all avoided costs, including losses and T&D savings)
6.New resource requirements are developed based on selected
conservation
7.PRiSM develops an efficient frontier and the PRS is selected
3 2015 Electric IRP Appendix A
76
Pros & Cons with Avista’s Conservation
Selection Methodology
• Pros
– Generation resources selection is faster, allowing more
scenarios
– Conservation resources with capacity contribution can get a 10%
avoided cost premium
• Power Council’s proposed RPM model only includes conservation
adder on the avoided market prices for energy savings.
– Third party conservation resource selection
• Cons
– When selecting different portfolios along the efficient frontier,
conservation remains unchanged, unless scenario analysis is
used
– Third party conservation resource selection

4 2015 Electric IRP Appendix A
77
Lessons from Modeling Conservation in
PRiSM- Analysis Perspective
• Model produces conservation acquisition consistent with 2013 IRP.
• Short lived conservation measures get free energy savings after life
(due to code or other reasons), modeling this in PRiSM bias more
short term conservation because of long term free benefits. To avoid
this, levelized costs have to be included after the resource life.
• Ramp rates for each program year are required, but the model can
select a program to begin earlier than CPA, with more detail on
program population, costs, and constraints.
• Levelized program costs have to be used rather than upfront cost to
avoid detailed modeling beyond 20 years. This bias higher cost
programs as it doesn’t see any benefits beyond 20 years. End
effects may be required to be modeled.

5 2015 Electric IRP Appendix A
78
Lessons from Modeling Conservation in
PRiSM- Technical Perspective
• PRiSM currently resides in Excel with Lindo System’s What’s Best
as the optimization engine.
– The optimization is a MIP- Mixed Integer Program
– MIP’s solution time increases exponentially with additional variables
• Solution time without adjustable conservation is ~2 minutes.
• Adding conservation causes solution time issues, some simulations
are ~7 minutes, some go forever- typically on lower risk scenarios
along efficient frontier.
• Alternatives for resolving solution times.
1.Use existing method
2.Try alternative optimization engines
3.Re-write program into a programing language and use Gurobi as a solver
4.Use LP for efficient frontier analysis, and MIP for scenario and PRS selection

6 2015 Electric IRP Appendix A
79
Load and Economic Forecasts
Grant D. Forsyth, Ph.D.
Chief Economist
September 23, 2014
Second Technical Advisory Committee Meeting

2015 Electric IRP Appendix A
80
Main Topic Areas
•Service Area Economy

•Peak Load Forecast

•Long-run Forecast and Load Impacts of
Residential Solar Penetration
2 2015 Electric IRP Appendix A
81
Service Area Economy
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]

3 2015 Electric IRP Appendix A
82
Non-Farm Employment: A Long, Slow Recovery
Source: BLS and author’s calculations.
-7%
-6%
-5%
-4%
-3%
-2%
-1%
0%
1%
2%
3%
4%
Ju
n
-09
Au
g
-09
Oc
t
-09
De
c
-09
Fe
b
-10
Ap
r
-10
Ju
n
-10
Au
g
-10
Oc
t
-10
De
c
-10
Fe
b
-11
Ap
r
-11
Ju
n
-11
Au
g
-11
Oc
t
-11
De
c
-11
Fe
b
-12
Ap
r
-12
Ju
n
-12
Au
g
-12
Oc
t
-12
De
c
-12
Fe
b
-13
Ap
r
-13
Ju
n
-13
Au
g
-13
Oc
t
-13
De
c
-13
Fe
b
-14
Ap
r
-14
Ju
n
-14
Ye
a
r
-ov
e
r
-Ye
a
r
,

S
a
m
e

M
o
n
t
h

S
e
a
s
o
n
a
l
l
y

A
d
j
.
Non-Farm Employment Growth Since June 2009
Avista WA-ID MSAs U.S.
4 2015 Electric IRP Appendix A
83
Distribution of Employment: Services and
Government are Dominant
Source: BEA and author’s calculations.
Farm
1%
Goods
13%
Private Services
71%
Federal, civilian
2%
Military
1%
State
3%
Local
9%
Government
15%
WA-ID MSA Employment, 2012
5 2015 Electric IRP Appendix A
84
Population Growth: Slowly Recovering with
Employment Growth
Source: BEA, U.S. Census, and author’s calculations.
1.9%
1.4%
1.2%
0.8%
0.5% 0.5%
0.8%
0.0%
0.2%
0.4%
0.6%
0.8%
1.0%
1.2%
1.4%
1.6%
1.8%
2.0%
2007 2008 2009 2010 2011 2012 2013
An
n
u
a
l

G
r
o
w
t
h

Population Growth in Avista WA-ID MSAs
Proxy for
Customer Growth
6 2015 Electric IRP Appendix A
85
Peak Load Forecast
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]

7 2015 Electric IRP Appendix A
86
The Basic Model
•Monthly time-series regression model that initially excludes certain industrial
loads.

•Based on monthly peak MW loads since 2004. The peak is pulled from hourly
load data for each day for each month.

•Explanatory variables include HDD-CDD and monthly and day-of-week dummy
variables. The level of real U.S. GDP is the primary economic driver in the
model—the higher GDP, the higher peak loads. The historical impacts of DSM
programs are “trended” into the forecast.

•The coefficients of the model are used to generate a distribution of peak loads
by month based on historical max/min temperatures, holding GDP constant.
An expected peak load can then be calculated for the current year (e.g., 2014).
Model confirms Avista is a winter peaking utility for the forecast period;
however, the summer peak is growing faster than the winter peak.

•The model is also used to calculate the long-run growth rate of peak loads for
summer and winter using a forecast of GDP growth under the “ceteris paribus”
assumption for weather and other factors.

8 2015 Electric IRP Appendix A
87
Current Peak Load Forecasts for Winter and
Summer, 2015-2040
1,000
1,200
1,400
1,600
1,800
2,000
2,200
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
20
3
7
20
3
9
Me
g
a
w
a
t
t
s
Winter Peak Summer Peak
Peak Avg. Growth 2015-40
Winter 0.73%
Summer 0.85%
9 2015 Electric IRP Appendix A
88
MW Spread Between Peak Forecasts for Winter
and Summer, 2015-2040
100
105
110
115
120
125
130
135
140
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
20
3
9
20
4
0
Me
g
a
w
a
t
t
s
Forecast Spread: Winter Peak Less Summer Peak , MW
Projecting out,
line would
reach zero in
2106.
10 2015 Electric IRP Appendix A
89
Current and Past Peak Load Forecasts for
Winter Peak, 2013-2040
1,500
1,750
2,000
2,250
2,500
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
20
3
9
20
4
0
Me
g
a
w
a
t
t
s
Winter Peak: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP
11 2015 Electric IRP Appendix A
90
Current and Past Peak Load Forecasts for
Summer Peak, 2015-2014
1,250
1,500
1,750
2,000
2,250
2,500
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
20
3
9
20
4
0
Me
g
a
w
a
t
t
s
Summer Peak: Current and Past
2009 IRP 2011 IRP 2013 IRP 2015 IRP
12 2015 Electric IRP Appendix A
91
Distribution of Summer Temperature Anomalies
in the Northern Hemisphere
Temperature anomaly distribution: The frequency of occurrence (vertical axis) of local
temperature anomalies (relative to 1951-1980 mean) in units of local standard deviation
(horizontal axis). Area under each curve is unity. Image credit: NASA/GISS. See also
NASA/GISS Science Brief , by James Hansen, Makiko Sato, Reto Ruedy (August 2012) at
http://www.giss.nasa.gov/research/briefs/hansen_17/#fn1

13 2015 Electric IRP Appendix A
92
Distribution of Summer Temperature
Anomalies in the Spokane Region
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
-5.0 -4.5 -4.0 -3.5 -3.0 -2.5 -2.0 -1.5 -1.0 -0.5 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0
Fr
e
q
u
e
n
c
y
Z-statistic
Spokane Summer Anomaly Histogram
1951-1980 Reference Period 2001-2013 Period
Note: Due to the movement of the Spokane temperature gage to the Spokane International
Airport in 1947, this anomaly analysis was restricted to the 1947-2013/14 period.
14 2015 Electric IRP Appendix A
93
Distribution of Winter Temperature Anomalies
in the Spokane Region
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
-5.0 -4.5 -4.0 -3.5 -3.0 -2.5 -2.0 -1.5 -1.0 -0.5 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0
Fr
e
q
u
e
n
c
y
Z-statistic
Spokane Winter Anomaly Histogram
1951/52-1980/81 Reference Period 2001/02-2013/14 Period
Note: Due to the movement of the Spokane temperature gage to the Spokane International
Airport in 1947, this anomaly analysis was restricted to the 1947-2013/14 period.

15 2015 Electric IRP Appendix A
94
Long-Term Load Forecast and the Time
Dynamics of Residential Solar Penetration
Grant D. Forsyth, Ph.D.
Chief Economist
[e-mail]

16 2015 Electric IRP Appendix A
95
U.S. Penetration Rate for Residential Net Metering
y = 0.000045e0.401291x
0.00%
0.05%
0.10%
0.15%
0.20%
0.25%
0.30%
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Penetration Rate: Share of U.S. Residential Customers with Net Metering
Share of Customers Expon. (Share of Customers)
Source: EIA and author’s calculations.
California, Arizona, and
Hawaii major drivers.
Avista’s Current Penetration
17 2015 Electric IRP Appendix A
96
Basic Forecast Approach
2014
Time
2019 2040 2020
1)Monthly econometric model by
schedule for each class.
2)Customer and UPC forecasts.
3) 20-yr MA for “normal weather.”
4)Economic drivers: GDP, industrial
production, employment growth,
population, price, household size.
5)ARIMA error correction.
6)Native load (energy) forecast derived
from retail load forecast.
1)Boot strap off medium term forecast.
2)Apply long-run load growth relationships to
develop simulation model for high/low
scenarios.
3)Include different scenarios for renewable
penetration with controls for price elasticity,
average household size, and EV/PHEVs.

Medium Term Long Term
18 2015 Electric IRP Appendix A
97
The Long-Term Residential Relationship, 2020-
2040
Load = Customers Χ Use Per Customer (UPC)

Load Growth ≈ Customer Growth + UPC Growth
Assumed to be same as
population growth, commercial
growth will follow residential,
and no real change in industrial.
Assumed to be a function of
multiple factors including
renewable penetration.
19 2015 Electric IRP Appendix A
98
The Basic Idea: Base-Line Residential Customer
Growth Starting in 2020
0.50%
0.60%
0.70%
0.80%
0.90%
1.00%
1.10%
1.20%
1.30%
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
20
3
9
20
4
0
Annual Residential Customer Growth Rates
Medium Term Long Term
Average annual growth rate
from 2014-2040 = 1%
20 2015 Electric IRP Appendix A
99
Assumptions for Residential UPC Growth
•The Time-Path of Renewable Penetration Rate (Share of
Customers with PV)

•Starting PV size, generation per Customer, capacity factor, and
the time-path of PV size

•Own Price Elasticity

•Average Household Size Elasticity

•Long-Run Trend for EV/PHEV adoption.
21 2015 Electric IRP Appendix A
100
Scenario analysis assuming 1% p.a. residential
customer growth and a solar capacity factor of
0.13:

•Base-Line Scenario: Residential penetration continues to grow in a linear fashion from 0.06%
to 0.30% by 2040. PV system size does not change from the current average of 3,000 watts.

•Low-Shock Scenario: Residential penetration at an exponential rate from 0.06% to 1% by
2025, and thereafter. PV additions grow to 6,000 watts by 2040.

•Medium-Shock Scenario: Residential penetration at an exponential rate from 0.06% to 5% by
2025, and thereafter. PV additions grow to 6,000 watts by 2040.

•High-Shock Scenario: Residential penetration at an exponential rate from 0.06% to 10% by
2025, and thereafter. PV additions grow to 6,000 watts by 2040.

Based on historical norms, the following assumptions are also made:
1. Residential and commercial customer growth will be the same in the long-run.
2. Commercial load growth and residential load growth will follow each other based on a
historical spread. This assumption is a proxy for commercial price impacts and renewable
penetration.
3. Industrial load and customer growth are low and industrial load and customer growth are not
strongly correlated with residential or commercial loads.

22 2015 Electric IRP Appendix A
101
Base-Line Residential UPC Growth Compared
with EIA’s Residential Reference Case
-1.60%
-1.40%
-1.20%
-1.00%
-0.80%
-0.60%
-0.40%
-0.20%
0.00%
0.20%
0.40%
0.60%
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
20
3
9
20
4
0
Annual Residential UPC Growth Rate
UPC Growth, Base-Line No Shock Renewables
EIA Refrence Case Use Per Household Growth
Medium Term Long Term
EIA assuming population
shift to warmer climate
states will push up AC load.
23 2015 Electric IRP Appendix A
102
Native Load Scenarios, 2020-2040
950
1,000
1,050
1,100
1,150
1,200
1,250
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
20
3
9
20
4
0
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Load Forecast Scenarios, Average Megawatts
Base-Line No Shock with Renewables Exponential Low Shock
Exponential Medium Shock Exponential High Shock
Medium Term Long Term
24 2015 Electric IRP Appendix A
103
Native Load Growth Scenarios, 2020-2040
-2.0%
-1.5%
-1.0%
-0.5%
0.0%
0.5%
1.0%
1.5%
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
20
3
9
20
4
0
Base-Line and Exponential Scenarios: Native Load Growth
Base-Line No Shock with Renewables Exponential Low Shock
Exponential Medium Shock Exponential High Shock
Medium Term Long Term
25
2015 Electric IRP Appendix A
104
KWH Average Annual Load Growth by Scenario,
2014-2040
0.82%0.81%
0.75%
0.68%
0.08%
0.62%0.61%
0.56%
0.50%
0.02%
0.0%
0.1%
0.2%
0.3%
0.4%
0.5%
0.6%
0.7%
0.8%
0.9%
0.3%1%5%10%50%
Av
e
r
a
g
e

A
n
n
u
a
l

T
o
t
a
l

L
o
a
d

G
r
o
w
t
h

i
n

K
W
H
Assumed Residential Penetration Rate
Avg. Annual Residential Load Growth Avg. Annual Total Load Growth26 2015 Electric IRP Appendix A
105
KWH Load Changes Compared to the Base-
Line Scenario, 2020-2040
-0.3%
-1.8%
-3.7%
-19.0%
-0.2%
-1.5%
-3.1%
-16.0%
-25%
-20%
-15%
-10%
-5%
0%
1%5%10%50%
Assumed Residential Penetration Rate
KWH Residential, % Diff Compared to Base-Line No Shock
KWH Total Load, % Diff Compared to Base-Line No Shock27 2015 Electric IRP Appendix A
106
Final Comment on EV/PHEV Penetration:
Large Forecast Variation
Forecast Source Forecasted Penetration Rate as Share of Vehicles by
2030-2050 Period
U.C. Berkley 65% by 2030 for EVs
EPRI 60% to 65% by 2035 for PHEVs
ORNL 40% by 2035 for PHEVs, 10% by 2050 for EVs
PNNL 30% by 2035-2045 for PHEVs
UMTRI 5% to 25% by 2040 for PHEVs
U.S. DOE 5% to 20% by 2035 for PEVs
Source: From 2013 presentation by Patrick J. Balducci, Pacific Northwest National Laboratory, at the
2013 Pacific Northwest Regional Economic Conference.
28 2015 Electric IRP Appendix A
107
Creating Shared Value
Avista’s 2014 Report on Our Operations
Casey Fielder
Second Technical Advisory Committee Meeting
September 23, 2014
2015 Electric IRP Appendix A
108
Our Approach
• Engage with stakeholders throughout the company
• Cross-company Shared Value Action Team
Consumer Affairs
Customer Service
Electric Operations
Energy Solutions/DSM
Environmental
Facilities
Gas Operations

Generation & Production
Health & Safety
Human Resources
Rates
Resource Planning
Supply Chain
2 2015 Electric IRP Appendix A
109
Why Report?
• Tell our story
• Educate about our operations
• Communicate the information our stakeholders want to
know
• Enhance transparency

3 2015 Electric IRP Appendix A
110
Creating Shared Value
Customers, Shareholders,
Communities, Employees
Sustainability
Protect the future
Compliance
Laws, Licenses, Codes of Conduct, Philanthropy

Goodwill, Reputation
Reputation
Business/Society
The “Shared Value” Pyramid
4 2015 Electric IRP Appendix A
111
Defining Shared Value
Harvard Business Review – Jan. 2011
The principle of shared value…involves creating economic value in a way
that also creates value for society by addressing its needs and
challenges. Businesses must reconnect company success with social
progress. Shared value is not social responsibility, philanthropy, or even
sustainability, but a new way to achieve economic success.

5 2015 Electric IRP Appendix A
112
A snapshot in time of what Avista does well that grows our business and at the same
time provides “social” value
Shared Value – The Opportunity
6 2015 Electric IRP Appendix A
113
Highlights from 2014 Report
7 2015 Electric IRP Appendix A
114
Highlights from 2014 Report
8 2015 Electric IRP Appendix A
115
Highlights from 2014 Report
9 2015 Electric IRP Appendix A
116
Highlights from 2014 Report
10 2015 Electric IRP Appendix A
117
Highlights from 2014 Report
11 2015 Electric IRP Appendix A
118
Materiality
12 2015 Electric IRP Appendix A
119
Materiality
13 2015 Electric IRP Appendix A
120
The Role of Our Stakeholders
14 2015 Electric IRP Appendix A
121
Determining Content Materiality
0 20 40 60 80 100 120 140
V. System Reliability
D. Customer Satisfaction
S. Resource Planning
T. Safety
J. Ethical Business Practices
I. Environmental Performance
C. Corporate Citizenship
H. Energy Security
L. Financial Performance
R. Public Policy
F. DSM Program
A. Avista's Energy Efficiency
G. Employee Satisfaction
M. GHG Footprint
N. Global Climate Exchange
K. Executive Compensation
P. Human Resources
W. Supply Chain
O. Governance
B. Biodiversity
E. Direct Use of Natural Gas
Z. Works Force Diversity
Q. NGO Relations
U. Stakeholder Engagement
Y. Water Use
X. Waste Dischaarge
Importance to Stakeholders
15
0 20 40 60 80 100 120 140
V. System Reliability
D. Customer Satisfaction
S. Resource Planning
T. Safety
J. Ethical Business Practices
I. Environmental Performance
C. Corporate Citizenship
H. Energy Security
L. Financial Performance
R. Public Policy
F. DSM Program
A. Avista's Energy Efficiency
G. Employee Satisfaction
M. GHG Footprint
N. Global Climate Exchange
K. Executive Compensation
P. Human Resources
W. Supply Chain
O. Governance
B. Biodiversity
E. Direct Use of Natural Gas
Z. Works Force Diversity
Q. NGO Relations
U. Stakeholder Engagement
Y. Water Use
X. Waste Dischaarge
Importance to Stakeholders Internal External
2015 Electric IRP Appendix A
122
Materiality Exercise
Consider each of the topics on the list for:

-- The importance you think each has for the stakeholders
of Avista
-- The relevance or impact each could have for Avista

Plot the letter of each topic on the grid depending on the
intersection of the values of importance to stakeholders and
relevance for Avista
16 2015 Electric IRP Appendix A
123
125 Years of Shared Value
Available at avistautilities.com
Feedback: [e-mail]
17 2015 Electric IRP Appendix A
124
Generation Options
Thomas Dempsey, P.E. and James Gall
Second Technical Advisory Committee Meeting
September 23, 2014
2015 Electric IRP Appendix A
125
Natural Gas Generation Options
• Existing site vs. new site (“Brownfield” vs. “Greenfield”)
• Simple cycle combustion turbines (peaking)
• Simple cycle piston engines (peaking/hybrid,
operation/load following)
• Combined cycle (base load/load following)
• Simple cycle combustion turbine with subsequent
conversion to combined cycle

2 2015 Electric IRP Appendix A
126
Natural Gas Generation Options
Considerations
3
• Efficiency
– Fuel efficiency
– Responsible use of resources
– Environmental impacts
• Flexibility- meets operational requirements
– Start time
– Part load efficiency
– Ability to, and speed of, cycling
• Costs
– Upfront installation
– Fuel
– Ongoing operations & maintenance
2015 Electric IRP Appendix A
127
Efficiency
• Greater efficiency means lower fuel costs
• Greater efficiency means lower emissions
– NOx, SO2, VOC’s, CO, CO2
• Efficiency is very important for options expected
to have many run hours, but less important for
options selected for peaking service or reserves
• Other considerations, such as water or other
consumable use is also considered
4 2015 Electric IRP Appendix A
128
Flexibility
• A flexible plant is quick to start, quick to full load, can
withstand large frequent load swings (i.e., backing up variable
resources), has low emissions across its operational range,
and can be operated with minimal staff.
5 2015 Electric IRP Appendix A
129
Costs
• Avista has access to an extensive turbine database
including machine price data that allows us to choose
more effective cost options.
• Initial capital cost
– Brownfield vs. Greenfield
– Economies of scale
• Ongoing operations & maintenance costs
• Fuel costs
6 2015 Electric IRP Appendix A
130
Thermoflow
• Sophisticated program allowing Avista to create
preliminary plant designs
• Allows for detailed initial cost estimates
• Initial plant layouts
• Site specific performance modeling
• Plant Engineering And Cost Estimation (PEACE)
7 2015 Electric IRP Appendix A
131
Thermoflow PEACE Output
8 2015 Electric IRP Appendix A
132
Thermoflow PEACE Output
9 2015 Electric IRP Appendix A
133
Available Gas Turbine Upgrades For
Avista Plants
• Supplemental Compression- enhances
capability of simple cycle 7EA machines at the
Rathdrum CT
• Inlet Evaporation System- increases summer
capability
• High efficiency turbine blades
• Water injected NOx control to allow for firing
temperature increase
10 2015 Electric IRP Appendix A
134
Kettle Falls Efficiency Improvements
• Fuel stabilization- fuel drying or conditioning to
keep the boiler operating at a continuously
efficient point
• Turbine and generator efficiency improvements
to achieve greater output using the same
amount of fuel
11 2015 Electric IRP Appendix A
135
Hydro Upgrades
• Same assumptions and options as 2013 IRP, adjusted for cost
inflation
• Post Falls- A detailed study is being performed to study long-term
options for the 104 year old project- results will not be available for
this IRP cycle

Project MW Capacity
Factor
Winter
Peak
Credit
Summer
Peak
Credit
Capital
Cost
(Mil $)
$/MWh-
Levelized
Long Lake 2nd
Powerhouse
68 34% 100% 100% $140 $108
Monroe Street/Upper
Falls 2nd Powerhouse
80 34% 31% 0% $152 $93
Cabinet Gorge 2nd
Powerhouse*
110 17% 0% 0% $231 $197
* Project is limited to water rights
12
DRAFT
2015 Electric IRP Appendix A
136
Natural Gas Turbine Resource Options
Resource Option Technology
Plant Size
(MW) (59F)
Capital Cost
Excludes AFUDC
(2014$/kW)
Fixed O&M
(2014$/kW/Yr)
Variable
Costs
(2014$/MWh)
Net HHV Heat
Rate(s)
(Btu/kWh)
Advanced Large Frame CT Frame SC 203 608 2 3.50 9,931
Modern Large Frame CT Frame SC 171 636 2 2.50 10,007
Modern Large Frame CT with HRSG Option Frame SC 170 710 3 2.50 10,009
Advanced Small Frame CT Frame SC 96 814 3 2.50 11,265
Frame/Aero Hybrid CT
Advanced Aero
SC 101 965 3 3.00 8,916
Large Reciprocating Engine Facility NG Recip 184 1,048 7 3.00 8,427
Small Reciprocating Engine Facility (Option 1) NG Recip 110 1,072 8 3.00 8,427
Small Reciprocating Engine Facility (Option 2) NG Recip 93 1,075 8 3.00 7,700
Modern Small Frame CT Frame SC 45 1,206 4 2.50 10,252
Aero CT option 1 2 on 1 SS 45 1,221 6 2.50 10,392
Aero CT option 2 Aero SS 42 1,255 6 2.50 9,359
1 on 1 Advanced CCCT option 1 1 on 1 CC 341 1,045 18 3.75 6,631
1 on 1 Advanced CCCT option 2 1 on 1 CC 343 1,045 18 3.75 6,895
1 on 1 Advanced CCCT option 3 1 on 1 CC 294 1,091 19 3.50 6,790
1 on 1 modern CCCT option 3 1 on 1 CC 286 1,099 15 3.00 6,720
3 x 2 small CCCT 3 on 2 CC 225 1,601 27 3.50 6,980
2 x 1 small CCCT 2 on 1 CC 150 1,645 34 3.50 6,968
Add HRSG to Large Frame CT 1 on 1 CC 286 635 20 3.50 6,720
DRAFT
13
2015 Electric IRP Appendix A
137
Levelized costs for Natural Gas-Fired
Resources
• In past IRP’s, Avista communicated levelized costs for all
resources.
• Levelized costs work well for energy only resources, but
do not communicate the cost of capacity
• Rather than showing levelized costs for capacity
resources, the following slide shows capacity cost vs.
energy costs for capacity resources
• Least cost resources represent the right mix of cost
between low cost capacity and energy
14 2015 Electric IRP Appendix A
138
Fixed vs. Variable Costs
15
DRAFT
2015 Electric IRP Appendix A
139
Renewables & Storage
16
Resource MW Capacity
Factor
Winter
Peak
Credit
Summer
Peak
Credit
Capital
Cost *
(2014$/kW)
$2015/MWh-
Levelized
Wind On-System 99 35% 0% 0% $2,050 $102
Solar Photovoltaic
Fixed Array
5.0 14% 0% 60% $2,100 $197
Solar Photovoltaic
Fixed Array
25.0 14% 0% 60% $2,000 $180
Solar Photovoltaic with
Single Axis Tracking
25.0 18% 0% 70% $2,500 $185
Battery Storage 25.0 N/A 100% 100% $4,000 N/A
* Capital Costs excludes AFUDC
DRAFT
2015 Electric IRP Appendix A
140
Wind Levelized Costs Forecast
Assumptions:
1) Cost shown are 2014 dollars levelized for first 20 years of asset life
2) ITC benefit taken up front, rather than utility amortization method 17 2015 Electric IRP Appendix A
141
Solar Experience Curve (Past)
World Solar Photovoltaic Production,1975-2012
Data from Earth Policy Institute and Bloomberg
As production increase, costs fall
18 2015 Electric IRP Appendix A
142
Solar Experience Curve (Future)
How could costs change with 10 times the cumulative installation
19 2015 Electric IRP Appendix A
143
Solar Levelized Costs Forecast
Assumptions:
1) Cost shown are 2014 dollars levelized for first 20 years of asset life
2) ITC benefit taken up front, rather than utility amortization method
173
148
138 131 124
136
118 110 105 99 93
81 75 71 67
$0
$20
$40
$60
$80
$100
$120
$140
$160
$180
$200
2016 2020 2025 2030 2035
20
1
4

$
/
M
W
h
Base Case 30% ITC 30% ITC + 20% CF
20 2015 Electric IRP Appendix A
144
Fixed Solar on Summer Peak (7/16/14)
1606
1485: 7.5% reduction, 24%
Peak Credit
1556: 3% reduction, 50% Peak Credit
25 MW would get 60% peak credit 21 2015 Electric IRP Appendix A
145
Fixed Solar on Winter Peak (1/21/14)
1715
25 MW would get 0% peak credit 22 2015 Electric IRP Appendix A
146
Standby Generation
• Avista is exploring the use of customer’s standby
generation for meeting peak and non-spinning reserve
requirements
• Portland General Electric currently has a similar program
with over 100 MW enrolled in the program
• 30 MW of capability is required to have a viable program
(e.g. 60 customers with 500 kW generators)
• Feasibility study is expected to be finished by the end of
the year – update will be made at a future TAC meeting
23 2015 Electric IRP Appendix A
147
Clean Power Plan Discussion
John Lyons, Ph.D. and Clint Kalich
Second Technical Advisory Committee Meeting
September 23, 2014
2015 Electric IRP Appendix A
148
Introduction
• Clean Power Plan Overview

• Avista 111(d) Model

• Clean Power Plan Modeling Inputs Discussion

2 2015 Electric IRP Appendix A
149
Clean Power Plan
• June 2, 2014 proposal covers certain existing fossil-fueled
resources under 111(d) of the Clean Air Act
• Goal is about a 30% reduction in CO2 emissions intensity
from 2005 by 2030
• Goals set using 2012 base year data
• Comments are now due by December 1, 2014
•http://www2.epa.gov/carbon-pollution-standards/clean-power-
plan-proposed-rule
• EPA anticipates final rule in June 2015
• Proposal includes state-by-state CO2 emissions intensity
reduction goals
• States submit a compliance plan one year after the final rule,
or two years if a multi-state plan is proposed
3 2015 Electric IRP Appendix A
150
4 2015 Electric IRP Appendix A
151
Resources Covered
Washington (Coal/Gas)
• Centralia Coal
• Big Hanaford
• Chehalis
• Encogen
• Ferndale
• Frederickson
• Goldendale
• Grays Harbor
• March Point
• Mint Farm
• River Road
• Sumas
5
Oregon (Coal/Gas)
• Boardman Coal
• Beaver
• Coyote Springs 1
•Coyote Springs 2
• Hermiston
• Klamath Cogen
• Port Westward

Montana (All Coal)
• Colstrip 1 & 2
•Colstrip 3 & 4
• Hardin
• J E Corette
• Lewis & Clark
• Yellowstone

Idaho (All Gas)
•Rathdrum, LLC
(aka Lancaster)
• Langley Gulch
*Plants in bold italics serve Avista customer load 2015 Electric IRP Appendix A
152
Building Blocks
• Block 1: Heat Rate Improvement – 6% improvement on coal plants

• Block 2: Re-dispatch to Existing Natural Gas Combined Cycle
Plants (NGCC) – dispatch NGCC in place of coal up to 70%

• Block 3: Renewable and Nuclear – maintain nuclear at risk and
increase renewables up to 21% in the western region by 2030

• Block 4: End-use Energy Efficiency – 10.7% cumulative savings by
2030
6 2015 Electric IRP Appendix A
153
Avista 111(d) Modeling Discussion Agenda
• Disclaimers and Contact Information
• Purpose of Model
• External Release of Model
• Data and Assumptions
• Future of Model, Including Upgrades
• Model Introduction
• Observations
7 2015 Electric IRP Appendix A
154
Disclaimers and Contact Information
• The Avista 111(d) model (and this presentation) is based on
preliminary analysis and subject to change
• Parties using the Avista 111(d) model should independently
verify its results
• No warranty of the Avista 111(d) model is made or implied
• Users must holds Avista harmless for any and all uses of
the Avista 111(d) model
• Use of the Avista 111(d) model is free; simply notify Avista
of your use, or who you pass the model along to
– ensures you and others receive any offered updates
– email [e-mail]
8 2015 Electric IRP Appendix A
155
The Purpose of Avista’s 111(d) Model
• To emulate the draft EPA rule 111(d)
• Decipher the EPA math
• Focus on the building blocks discussed by EPA, as well as
potential other blocks that Avista believes may provide
similar impacts
• Help Avista make decisions with regard to EPA’s draft rules
9 2015 Electric IRP Appendix A
156
Purpose of Avista’s 111(d) Model, Cont.
• Inform its potential comments on the draft rule
• Support policy-level recommendations
• Integrated resource (and other) planning
• Quantify potential compliance costs
• Assist with external party communication

10 2015 Electric IRP Appendix A
157
External Release of Avista 111(d) Model
• There is a lot of confusion about the EPA rule
• Model may assist in understanding/quantifying 111(d)
proposal
• Avista provides its model for free use
• Avista cannot provide passwords to allow reverse
engineering
• No warranty is granted or implied

11 2015 Electric IRP Appendix A
158
Data and Assumptions
• Most data from EPA worksheets *
• Minor other “behind-the-scenes” assumptions
• Some assumptions can be changed by the user
• All regulated states are included in the model
• User can combine states to perform a regional view
• Default choices are already built into the model
12
* See http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-state-goal-data-computation_1.xlsx and
http://www2.epa.gov/sites/production/files/2014-06/20140602tsd-plant-level-data-unit-level-inventory_0.xlsx

2015 Electric IRP Appendix A
159
Future of Model and Upgrades
• Updates will be provided as deemed necessary by Avista
• Updates will include enhancements and new features
• User feedback will help dictate much of the future release
features and frequency
• Changes to the proposed rule will be incorporated in future
releases as more information becomes known
• Model may be revised by Avista without notification
13 2015 Electric IRP Appendix A
160
Model Introduction
14 2015 Electric IRP Appendix A
161
Some Observations
• Compliance costs appear much higher than EPA estimates
• Retirement without replacing with qualifying non-carbon
resources is much less impactful on the emissions rate than
building replacement resources
• Higher conservation or renewables means fewer mass-
based emissions reduction
• EPA rule does not appear focused on electricity system
reliability
• 2012 base year has very high hydro generation
– and a correlated low carbon emissions level
15 2015 Electric IRP Appendix A
162
Some Observations, Cont.
• Hydro/renewables variability is ignored in the math
• States receive no credit for early action (e.g., Centralia,
aggressive conservation)
• Idaho has only two gas-fired plants regulated by 111(d), one
of which operated only half of the 2012 base year
• For Oregon and Washington the only EPA options are
conservation and renewables, as coal plants already are in
the baseline
• In Montana, retiring coal for gas does not reduce emissions
rate

16 2015 Electric IRP Appendix A
163
2012 Operations at Coyote Springs 2
(OR) and Rathdrum LLC (ID)
17
An
n
u
a
l

C
a
p
a
c
i
t
y

F
a
c
t
o
r

2015 Electric IRP Appendix A
164
Idaho Comparison: 2012 Langley Gulch and
Rathdrum Power LLC Plant Operations
18 Annual Capacity Factor 2015 Electric IRP Appendix A
165
Historical Carbon Emissions
(millions of CO2 tons)
19 2015 Electric IRP Appendix A
166
Pacific Northwest Hydroelectricity vs.
Dalles Inflow Variability
60%
70%
80%
90%
100%
110%
120%
130%
140%
150%
160%
90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10 11 12
%
o
f

1
9
9
0
-20
1
2

A
v
e
r
a
g
e
Comparison of Northwest Generation vs. Dalles Flow
Calendar Year Averages
Flow Generation
20
Year
2015 Electric IRP Appendix A
167
Pacific Northwest Hydroelectricity vs.
Coal Emissions (Centralia)
21 2015 Electric IRP Appendix A
168
Hydro Variability in WA
22 2015 Electric IRP Appendix A
169
Clean Power Plan Modeling Inputs
Discussion
• Base Case assumptions
• Scenarios
23 2015 Electric IRP Appendix A
170

2015 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 3 Agenda
Friday, November 21, 2014
Conference Room 130
Topic Time Staff
1. Introduction & TAC 2 Recap 8:30 Lyons

2. Planning Margin 8:35 Gall

3. Colstrip Discussion 9:15 Lyons

4. Cost of Carbon 10:45 Lyons

5. Lunch 11:30

6. IRP Modeling Overview 12:30 Gall

7. Conservation Potential Assessment 1:45 Kester

8. Adjourn 3:00

2015 Electric IRP Appendix A
171
2015 Electric IRP
TAC Meeting Expectations and Schedule
John Lyons, Ph.D.
Second Technical Advisory Committee Meeting
November 21, 2014
2015 Electric IRP Appendix A
172
Technical Advisory Committee
• The public process of the IRP – input on what to study, how to study, and
review of assumptions and results

• Technical forum with a range of participants with different areas of input
and expertise

• Open forum, but we need to stay on topic to get through the agenda and
allow all participants to ask questions and make comments

• Welcome requests for studies or different assumptions.
– Time or resources may limit the amount of studies
– The earlier study requests are made, the more accommodating we can be
– January 15, 2015 is the final date to receive study requests

• Action Items – areas for more research in the next IRP
2 2015 Electric IRP Appendix A
173
Technical Advisory Committee
• Technical forum on inputs and assumptions, not an advocacy forum

• Focus is on developing a resource strategy based on sound assumptions
and inputs, instead of a forum on a particular resource or resource type

• We request that everyone maintain a high level of respect and
professional demeanor to encourage an ongoing conversation about the
IRP process

• Supports rate recovery, but not a preapproval process

• Planning team is available by email or phone for questions or comments
between the TAC meetings

3 2015 Electric IRP Appendix A
174
Remaining TAC Meetings
•TAC 4 – February 2015: Electric and natural gas price
forecasts, transmission planning, resource needs
assessment, market and portfolio scenario development,
energy storage and ancillary service evaluation
•TAC 5 – March 2015: Completed conservation potential
assessment, draft preferred resource strategy (PRS), review
of scenarios, market futures, and portfolio analysis
•TAC 6 – June 2015: Review of final PRS and action items.
4 2015 Electric IRP Appendix A
175
2015 IRP Tasks for the PRS
Exhibit 1: 2015 Electric IRP Timeline
Task Target Date
Preferred Resource Strategy (PRS)
Finalize energy demand forecast July 2014
Identify Avista’s supply & conservation resource options September 2014
Finalize peak load forecast September 2014
Update AURORAxmp database for market price forecast October 2014
Energy efficiency load shapes input into AURORAxmp October 2014
Finalize datasets/statistics variables for risk studies November 2014
Transmission study due December 2014
Finalize distribution feeder forecast December 2014
Select natural gas price forecast December 2014
Finalize deterministic base case January 2015
Due date for study requests Jan. 15, 2015
Base case stochastic study complete January 2015
Develop efficient frontier and PRS January 2015
Finalize PRiSM model February 2015
Simulation of risk studies “futures” complete February 2015
Simulate market scenarios in AURORAxmp February 2015
Evaluate resource strategies against market futures and
scenarios
March 2015
Present preliminary study and PRS to TAC March 2015

5 2015 Electric IRP Appendix A
176
2015 IRP Writing Tasks – Work Plan
Writing Tasks
File 2015 IRP work plan August 2014
Prepare report and appendix outline October 2014
Prepare text drafts April 2015
Prepare charts and tables April 2015
Internal draft released at Avista May 2015
External draft released to the TAC June 2015
Final editing and printing August 2015
Final IRP submission and TAC August 31, 2015

6 2015 Electric IRP Appendix A
177
TAC #2 Recap
• Introduction & TAC 1 Recap – Lyons
• Conservation Selection Methodology – Gall
• Load and Economic Forecasts – Forsyth
• Shared Value Report – Fielder
• Generation Options – Gall/Dempsey
• Clean Power Plan Proposal Discussion – Lyons/Kalich

7 2015 Electric IRP Appendix A
178
Today’s Agenda
• Introduction & TAC 2 Recap (8:30) – Lyons
• Planning Margin (8:35) – Gall
• Colstrip Discussion (9:15) – Lyons
• Cost of Carbon (10:45) – Lyons
• Lunch (11:30)
• IRP Modeling Overview (12:30) – Gall
• Conservation Potential Assessment (1:45) – Kester
• Adjourn 3:00
• Reminders: restrooms are across the hall and all visitors
need Avista escorts to the lobby to leave the building

8 2015 Electric IRP Appendix A
179
Planning Margin (Reserve Planning)
James Gall
Third Technical Advisory Committee Meeting
November 21, 2014
2015 Electric IRP Appendix A
180
What is the role of reserves for peak
planning
•Planning Margin1: Generally, the projected demand is based on a 50/50
forecast. Based on experience, for Bulk Power Systems that are not energy-
constrained, reserve margin is the difference between available capacity
and peak demand, normalized by peak demand shown as a percentage to
maintain reliable operation while meeting unforeseen increases in demand
(e.g. extreme weather) and unexpected outages of existing capacity
•Operating Reserves: is required capacity to meet an instantaneous
loss of generation.
– New rule in WECC, 3% of load and 3% of operating generation is
carried. Half of the capacity must be “synced” to the grid (spinning) and
the other half must be available to sync within 10 minutes (non-
spinning/supplemental).
•Regulation is required intra hour capacity to meet instantaneous
load changes instantly
1. http://www.nerc.com/pa/RAPA/ri/Pages/PlanningReserveMargin.aspx. 50/50 is also referred to as a
1-in-2 forecast
2015 Electric IRP Appendix A
181
NERC's Reference Reserve Margin
• is equivalent to the Target Reserve Margin Level
provided by the Regional/subregion’s own specific
margin based on load, generation, and transmission
characteristics as well as regulatory requirements. If not
provided, NERC assigned 15 percent Reserve Margin
for predominately thermal systems and 10 percent for
predominately hydro systems. As the planning reserve
margin is a capacity based metric, it does not provide an
accurate assessment of performance in energy limited
systems, e.g., hydro capacity with limited water
resources.

http://www.nerc.com/pa/RAPA/ri/Pages/PlanningReserveMargin.aspx 2015 Electric IRP Appendix A
182
2013 IRP WUTC Acknowledgement
Request
•In its updated action plan, Avista committed to re-assess
with the TAC the benefits and costs of the Company’s
2013 IRP planning margin to determine if a different level
is warranted in the 2015 IRP. The Commission supports
this approach.
• The 2013 IRP used the following planning margin
– Greater of 1 hour or 18 hour sustained peak deficit
• Includes the top six load hours of three consecutive days

– Winter: 14% adder to the 1 in 2 peak forecast + Ancillary Services Requirement
(~6% operating reserves + 1.3% regulation reserve) = 21% – 22 %

– Summer: 0% adder to the 1 in 2 peak forecast + Ancillary Services Requirement
(~6% operating reserves + 1.3% regulation reserve) = 7% - 8%

4 2015 Electric IRP Appendix A
183
North American Planning Margin Survey
• Planning margin added to peak load is most
common
• Some plan for 5% LOLP, others 1 in 10 years
• Operating reserves is often included in estimates
• Organized market have firm requirements
• Northwest utilities/organizations recommend higher
planning margins
2015 Electric IRP Appendix A
184
Regional Planning Margins
• Organized systems

• Non Northwest Utilities
PJM 15.7%
MISO 14.8%
TVA 15.0%
SPP 13.6%
NYISO 17.1%
ISO New England 15.0%
ERCOT 13.8%
California PUC 15.0%
New Brunswick Power 22.0%
Hydro Quebec 8.0%
Nova Scotia Power 20.0%
Hydro One 20.0%
FPL 20.0%
Progress Energy 20.0%
Entergy- New Orleans 12.0%
Sunflower Coop 12.0%
Kansas City B of PU 12.0%
Basin Electric 15.0%
LADWP 25.0%
San Diego Gas & Electric 15.0%
Roseville Electric 15.0%
Dominion 15.6%
Minnesota Power 11.3%
Indianoplis Light & Power 12.7%
Duke- Indiana 13.9%
Duke- Carolina's 14.5%
Oklahoma Gas & Electric 12.0%
Platte River Power Authority 15.0%
XCEL- Colorado 16.3%
XCEL- New Mexico 13.6%
Colorado Springs Utilities 18.0%
Salt River Project 12.0%
APS 15.0%
UNS Electric 15.0%
El Paso Electric 15.0%
Sierra Pacific 15.0%
Nevada Power 12.0%
Public Service Co of NM 13.0%
Tri-State G&T 15.0%
2015 Electric IRP Appendix A
185
• Northwest Utilities

• Northwest Organizations
Northwest Planning Margins
PSE (2018-19) 14.0%
PSE (2020+) 16.0%
PacifiCorp 13.0%
PGE 12.0%
Clark PUD 18.0%
Cowlitz PUD 23.0%
EWEB 17.0%
Northwestern 0.0%
Idaho Power 10.3%
Fortis 10.0%
BC Hydro 20.0%
WECC- PNW Summer 17.9%
WECC- PNW Winter 19.9%
WECC- PNW Summer 18.8%
WECC- PNW Winter 21.6%
NPCC- Summer 24.0%
NPCC- Winter 23.0%
NWPP (NPCC) <28.0%
WECC (NPCC) 18.0%
PNUCC 12.0%-20% 2015 Electric IRP Appendix A
186
Single Largest Resource Contingency
Utility % Resource (MW)
Public Service of CO 9% Comanche- 525
Public Service of NM 13% San Juan- 248
LADWP 8% Scattergood- 450
Salt River Project 6% Springerville- 415
Arizona Public Service 7% Redhawk- 500
El Paso Electric 12% Palo Verde- 207
Sierra Pacific 33% Tracy CCCT- 553
Nevada Power 10% Lenzie- 551
Largest shaft as a percent of 2014 forecast peak load
Western Interconnect utilities with a control area
Utility % Resource (MW)
Puget Sound Energy 6% Mint Farm- 297
PacifiCorp- West 15% Chehalis- 477
PacifiCorp- East 9% Lake Side 2- 628
Portland General Electric 16% Boardman- 517
Bonneville Power Admin 7% Coulee- 805
Idaho Power 10% Langley Gultch-318
BC Hydro 5% Various- 500
Avista- Summer 16% Coyote Springs 2- 277
Avista- Winter 20% Coyote Springs 2- 312
2015 Electric IRP Appendix A
187
Planning Margins Contrasts Between
Interconnected and Electrical Islands
• Since Avista is part of a larger power system it can
leverage assets of the system to help meet peaks rather
than rely entirely on its only system keeping planning
margins low
• This is the opposite from Avista’s newly acquired Alaska
Electric Light & Power subsidiary; AELP must provide all
its own reserves for reliability and plans on a 100%
planning margin + largest single contingency within its
core system.
• The Northwest Planning Conservation Council (NPCC)
attempts provide direction on system reliability on a
regional basis for northwest interconnect utilities.
2015 Electric IRP Appendix A
188
Northwest Power Conservation Council’s
LOLP Results for 2019
http://www.nwcouncil.org/media/7148382/100914-raac-tech-2019-review.pdf
2015 Electric IRP Appendix A
189
Northwest Market Depth
January January January July July July Jan July
Year 1 Hour 4 Hour 10 Hour 1 Hour 4 Hour 10 Hour Margin Margin
2017 12,222 8,014 5,315 11,323 10,740 9,829 28% 50%
2018 11,864 7,663 4,979 11,034 10,457 9,557 27% 49%
2019 11,503 7,309 4,639 10,742 10,170 9,283 26% 47%
2020 11,138 6,951 4,296 10,447 9,881 9,006 24% 46%
2021 9,514 5,334 2,694 9,182 8,623 7,759 20% 41%
2022 9,014 4,842 2,217 8,754 8,201 7,349 19% 39%
2023 8,638 4,474 1,863 8,450 7,903 7,063 18% 38%
2024 8,258 4,101 1,506 8,143 7,602 6,775 16% 36%
2025 7,875 3,725 1,145 7,833 7,298 6,483 15% 35%
2026 6,683 2,541 (23) 7,386 6,857 6,055 14% 33%
2027 6,291 2,158 (391) 7,070 6,548 5,758 13% 32%
2028 5,896 1,770 (763) 6,750 6,234 5,457 11% 31%
2029 5,497 1,379 (1,138) 6,428 5,918 5,154 10% 29%
2030 5,093 984 (1,517) 6,102 5,599 4,848 9% 28%
Assumptions:
• 1% load growth rate to match NPCC’s peak load forecast
• Uses NPCC’s assumptions for shares of borderline resources contributing to NW
• Centralia, Boardman, Big Hanaford, Corette offline as forecasted
• Only new resources under construction are assumed
• Excludes wind resources
• Operating reserves and regulation requirements are satisfied ~8% of load
• Winter import is 2,500 MW, summer exports IPP resources
Violation of 5% LOLP
2015 Electric IRP Appendix A
190
Avista’s Peak Situation
• Peak can occur in summer or winter, but winter
peak predominate concern
• Large single largest contingency
• Peak load is 5 percent of the Northwest’s peak
load
• Well connected to other utilities
• Equal mix of hydro and thermal resources
• Have mix of flexible hydro and flexible natural
gas fired units to meet flexibility requirements

2015 Electric IRP Appendix A
191
Spokane Temperature Volatility
0%
5%
10%
15%
20%
25%
30%
35%
40%
45%
60 63 66 69 72 75 78 81 84 87 90 93 96 99 102105 108111
Fr
e
q
u
e
n
c
y
Hottest Day Average Temperature
Summer Temperature Variation
0%
2%
4%
6%
8%
10%
12%
14%
16%
-20 -17 -14 -11 -8 -5 -2 1 4 7 10 13 16 19 22 25 28 31
Fr
e
q
u
e
n
c
y
Coldest Day Average Temperature
Winter Temperature Variation
Winter Summer
Mean 4 82
Tail (10%) -9 86
Extreme -17 90
Stdev 9 3
Recent
Events
2014: 5
2008: -7
2004: -9
2014: 84
2008: 86
2006: 87
Temperature Statistics
2015 Electric IRP Appendix A
192
Flexibility Requirements (99th Percentile)
2013 CY Data
DRAFT 2015 Electric IRP Appendix A
193
Flexibility Requirements (95th Percentile)
2013 CY Data
DRAFT 2015 Electric IRP Appendix A
194
2013 IRP Planning Margin vs Market
Reliance Cost Trade-Off
0
5
10
15
20
25
30
35
40
45
-
50
100
150
200
250
300
12%13%15%16%18%19%21%22%24%25%27%28%30%31%
in
c
r
e
m
e
n
t
a
l

c
o
s
t

(
$
M
i
l
l
/
Y
r
)
ma
r
k
e
t

c
o
n
t
r
i
b
u
t
i
o
n

(
M
W
)
planning margin
MW
Annual Cost
Winter Planning Margin in addition to Ancillary Services Requirements
Avista’s Assumption: 14%
Use if Avista is
an electrical
island
2015 Electric IRP Appendix A
195
2015 IRP Planning Margin Proposal
• Greater of 1 Hour or 18 Hour sustained peak deficit
• Winter
– 14% Planning Margin +
– Control Area Operating Reserves +
– Regulation (16 MW)
• Summer
– 0% Planning Margin +
– Control Area Operating Reserves +
– Regulation (16 MW)
• Market Power Available
– Winter: Through 2018
– Summer: Available throughout the study
22.6% Planning Margin
for January 2015
2015 Electric IRP Appendix A
196
1 Hour Net Load/Resource Position
(No Short-Term Market)
Temporary short position until capacity
sale contract expires (150 MW)
Apr ‘19, WNP-3
Expires (82 MW)
Aug ‘18, Wells Contract
Expires (28 MW)
Lancaster Tolling
Contract Ends
2015 Electric IRP Appendix A
197
18 Hour Net Load/Resource Position
(No Short-Term Market)
(700)
(600)
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
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
Me
g
a
w
a
t
t
s
January
August
2015 Electric IRP Appendix A
198
Colstrip Discussion
John Lyons, Ph.D.
Third Technical Advisory Committee Meeting
November 21, 2014
2015 Electric IRP Appendix A
199
Future of Colstrip – Planning
• Direction from the Washington Commission Acknowledgement of the 2013
IRP:
– “Continue to evaluate scenarios related to the continued operation of
units 3 and 4 of the coal-fired generating facility in Colstrip, Montana.
As a component of this evaluation, Avista should provide an
assessment of the impact on rates of a hypothetical portfolio that does
not include these units.” (Docket No. UE-121421)

• Idaho Commission Acknowledgement
– “We expect the Company to consider and discuss at the TAC meetings
the various concerns and suggestions that are and have been offered.
In particular, we expect the Company to monitor federal developments,
such as the promulgation of federal environmental regulations, and to
account for their impact in its resource planning. We also encourage
the Company to continue exploring the use of DR as a resource, and to
be actively involved in and apprise us of matters relating to Colstrip.”
(Order No. 32997)

2 2015 Electric IRP Appendix A
200
2013 IRP Comments Regarding Colstrip
• No public comments received in Washington

• Summary comments to the Idaho PUC
– Colstrip risks regarding continued operation:
• Regional Haze
• Greenhouse gas regulations
• Permitting for prevention of significant deterioration
• National Ambient Air Quality Standards
• Mercury and Air Toxics Rule
• Coal combustion wastes
• Coal costs and the Rosebud mine
– Colstrip retirement

3 2015 Electric IRP Appendix A
201
Colstrip Ownership Information
4
Colstrip Basic Data Colstrip Ownership Percentages
Colstrip
Unit #
Size
(MW)
Year
Online
Avista NorthWestern
Energy, LLC
PacifiCorp Portland
General
Electric
PPL
Montana,
LLC
Puget
Sound
Energy
Unit #1 307 1975 0% 0% 0% 0% 50% 50%
Unit #2 307 1976 0% 0% 0% 0% 50% 50%
Unit #3 740 1984 15% 0% 10% 20% 30% 25%
Unit #4 740 1986 15% 30% 10% 20% 0% 25%
Total 2,094 11% 11% 7% 14% 25% 32%
• 9% of Avista’s owned and contracted capacity
• 14.86% of 2013 energy profile (Draft 2014 Washington
Department of Commerce Fuel Mix Report)

2015 Electric IRP Appendix A
202
Colstrip Economic Benefits
• The plant employs 360 people and the mine has 373
employees
• $104 million in annual Montana state and local taxes
(4.5% of all state revenue collections)
• 3,740 additional jobs and 7,700 more residents in
Montana
• $360 million in additional personal income
• $638 million more in additional Montana economic output
• Second lowest cost resource after hydroelectric for Avista
• Baseload resource with stable fuel price

Data from The Economic Contribution of Colstrip Steam Electric Station Units 1-4, November 2010.

5
2015 Electric IRP Appendix A
203
0
20
40
60
80
100
120
19
8
0
19
8
1
19
8
2
19
8
3
19
8
4
19
8
5
19
8
6
19
8
7
19
8
8
19
8
9
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
20
1
0
20
1
1
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Transportation Industrial Commercial Residential
Electric Power Centralia WA Jim Bridger WA Colstrip
Washington State Carbon Emissions & Goals

In state and
imported coal
is 16% of total
emissions
Source: EIA- does not include agriculture and waste management and estimates differ than WA Ecology
2020 Goal
(1990 levels)
2035 Goal
(25% below 1990)
2050 Goal
(50% below 1990)
6 2015 Electric IRP Appendix A
204
Issues Related to Colstrip in this IRP
7
Modeling Assumptions:
• Greenhouse gas regulations:
– emissions performance standards (CA, OR and WA)
– 30% WECC-wide reduction identified pursuant to 111(d)
• National Ambient Air Quality Standards
• Mercury and Air Toxics Rule (HAPs)
• Regional Haze

Emerging Issues:
• Finalization of the 111(d) rule at the federal and state levels
• Coal combustion residuals
• Washington Executive Order 14-04
• Cost of closing the plant and continued use of the site
2015 Electric IRP Appendix A
205
Colstrip Modeling in the 2015 IRP
Expected Case Assumptions:
• Assumes compliance with known environmental regulations
(discussed in the previous slide)
• Expected Case assumptions do not speculate – alternatives
considered under futures/scenarios studies
• Colstrip Units #3 – 4 in service through IRP modeling period
• Cost of carbon (to be discussed in the next presentation)

Draft Alternative Colstrip Scenarios:
• SCR on units 3 and 4 in 2025 and 2026
• No SCR, shut down units 3 and 4 by end of 2026

8 2015 Electric IRP Appendix A
206
Carbon Prices in the 2015 Electric IRP
John Lyons, Ph.D.
Third Technical Advisory Committee Meeting
November 21, 2014
2015 Electric IRP Appendix A
207
Background
• Washington:
– “Incorporate a non-zero expected value cost of carbon into the
Expected Case. Avista should also work with the Technical
Advisory Committee to investigate incorporating a range of
prospective carbon policies into the Expected Case stochastic
analysis.” (UE-121421 – 2013 IRP Acknowledgement Letter)
• Forms of carbon regulation:
– Cap and trade: an example is AB 32 in California
– Direct regulation: EPA proposal under 111(d), RCW 80.80
– Carbon tax: British Columbia
– Indirectly through an RPS
• Four cases plus two others selected by the TAC (Expected Case,
Benchmark Case, 111(d) Case and No Colstrip Case)

2 2015 Electric IRP Appendix A
208
State of Carbon Regulation
• No carbon prices for resources in our jurisdictions
• Washington goal of 50 percent below 1990 emissions by
2050, but no implementation strategy.
– 970 pounds/MWh for new baseload resources (RCW 80.80)
• Emissions offset requirements for new baseload thermal
resources in Oregon and Washington
• No carbon prices in Idaho
• Federal: 111(b) and 111(d) proposals
• Other jurisdictions modeled in WECC includes their
applicable prices: British Columbia’s carbon tax and
California’s AB32.

3 2015 Electric IRP Appendix A
209
2013 IRP Expected Case Carbon Assumptions
• In the 2013 IRP, the implied cost of carbon in the expected
case was $95.33 per metric ton.
– Implied cost to the whole region from coal plant retirements and
the cost to replace the lost capacity.
– Avista’s implied cost was much lower than the region because of
no expected lost capacity from coal. Avista’s implied cost
included higher electric market prices ($1.79/MWh or 3.5%) due
to the lost capacity between 2020-2033.
• Assuming the price adder is from a 7,000 heat rate natural
gas-fired plant the implied 2013 IRP carbon price is
$4.70/metric ton levelized between 2020-2033.

4 2015 Electric IRP Appendix A
210
Draft 2015 Expected Case Assumptions
• Target 30% minimum reduction in carbon emissions rate from
2005 for plants covered under 111(d)
• Adjust load forecast assumption to include additional conservation
• 21% RPS for the region (not necessarily state-by-state)
• 10% probability of carbon cost adder to generation ($12 nominal
in 2020 with 5% escalation)
• Options:
– Will determine actionable measures needed to reduce existing
plant emissions (rate or mass based)
– Retire enough plants to hit 30% and calculate carbon price
necessary to force retirement
– Increased energy efficiency above utility forecasts
– 2020 start date, but not the same EPA glide path
• Scenario Purpose: provides market prices and conditions used to
determine the Preferred Resource Strategy
5 2015 Electric IRP Appendix A
211
Benchmarking Case
• Assumes that 111(d) does not occur so we have a
benchmark to show the costs of the 111(d) proposal and
other carbon scenarios
• Maintains existing RPS, emissions performance
standards, plant retirements and existing energy
efficiency programs
• Scenario Purpose: only used to show costs and effects
of the 111(d) proposal and regional haze programs

6 2015 Electric IRP Appendix A
212
EPA 111(d) Draft Rule Case
• Assumes suggested adoption of EPA building blocks for
each state in the WECC
• 21% RPS – state-level requirement
• 10.7% DSM – state-level requirement
• 6% heat rate improvements at coal plants
• Shut down of planned/announced coal retirements
• Caps EGU output to EPA level, with the exception of an
adjustment for Langley Gulch to show a full year of
output
• Scenario Purpose: shows the impacts of the 111(d) draft
rule

7 2015 Electric IRP Appendix A
213
No Colstrip Case
• Uses Expected Case assumptions, but removes Colstrip
from the resource stack in 2026
• Does not make assumptions about why the plant is no
longer available, but shows the costs and how it would
be replaced
• Scenario Purpose: answers question posed by the
Washington Commission in the 2013 IRP
acknowledgement letter

8 2015 Electric IRP Appendix A
214
Other Potential Cases for Discussion
• Regional cap and trade for carbon emissions
• Coal limitations without retirement
• All U.S. WECC coal retires by a certain date
• Social cost of carbon as a price adder

9 2015 Electric IRP Appendix A
215
2013 IRP Modeling Approach
James Gall
Third Technical Advisory Committee Meeting
November 21, 2014

2015 Electric IRP Appendix A
216
2015 IRP Modeling Process
Preferred
Resource
Strategy

AURORA
“Wholesale Electric
Market”

500 Simulations

PRiSM
“Avista Portfolio”

Efficient Frontier

Fuel Prices
Fuel Availability
Resource Availability
Demand
Environmental Considerations
Existing Resources
Resource Options
Transmission
Resource & Portfolio Margins
Conservation
Trends
Existing
Resources
Avista Load
Forecast
Energy,
Capacity,
& RPS
Balances New Resource Options & Costs
T&D Efficiency
Projects
Conservation / DR
Measures/Costs
Mid-Columbia Prices
Stochastic Inputs Deterministic Inputs
Capacity
Value
Avoided
Costs
2015 Electric IRP Appendix A
217
3rd party software- EPIS, Inc.
Electric market fundamentals- production cost
model
Simulates generation dispatch to meet load
Outputs:
– Market prices
– Regional energy mix
– Transmission usage
– Greenhouse gas emissions
– Power plant margins, generation levels, fuel costs
– Avista’s variable power supply costs
Electric Market Modeling
2015 Electric IRP Appendix A
218
AURORA Inputs
Regional loads
Fuel prices
Hydro levels
Wind variation
Environmental resolutions
Resource availability
Transmission

2015 Electric IRP Appendix A
219
Regional Loads
Forecast load growth for all regions in the Western Interconnect
Consider both peak and energy
Use regional published studies and public IRP’s
Stochastic modeling simulates load changes due to weather and
considers regional correlation of weather patterns
Load changes due to economic reasons are difficult to quantify and
are usually picked up as IRP’s are published every two years
Peak load is becoming more difficult to quantify as “Demand
Response” programs my cause data integrity issues
Energy demand forecasts need to be net of conservation

2015 Electric IRP Appendix A
220
California
Northwest
Desert SW
Rocky Mountains
Canada
-
50,000
100,000
150,000
200,000
250,000
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
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Me
g
a
w
a
t
t
s
Western Interconnect Peak Load Forecast
Energy & Peak Forecast (draft)
Energy AAGR
Canada 1.95%
Rocky Mtns. 1.18%
Desert SW 1.61%
California 0.99%
Northwest 0.82%
Peak AAGR
Canada 1.80%
Rocky Mtns. 1.23%
Desert SW 1.46%
California 1.00%
Northwest 0.95%
California
Northwest
Desert SW
Rocky Mountains
Canada
-
50,000
100,000
150,000
200,000
250,000
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
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Western Interconnect Energy Load Forecast
2015 Electric IRP Appendix A
221
Electric Vehicles (PH/EV)
Customer load shapes will be a result of PHEV
To address this- a load adder will be applied to reflect new demand
with a majority of load added in off peak hours
By 2030 the following are the percent of vehicle sales,
25%: CA
15%: AZ, CO, OR, WA
10%: NM, NV,UT
5%: WY, MT, ID
Beyond 2030 growth is equal to traditional vehicle growth (1/2 of
population growth)

-
500
1,000
1,500
2,000
2,500
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
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Western Interconnect PH/EV
Load
2015 Electric IRP Appendix A
222
Rooftop Solar
• As with PH/EV, rooftop solar will impact future load
growth and its hourly profile
• Future growth will be dependent upon policy choices
• Assumes 20-40% growth, before leveling off to long run
growth 1-3% in 2020’s

2015 Electric IRP Appendix A
223
Natural Gas Prices
Natural gas prices are one of the most difficult inputs to quantify
A combination of forward prices and consultant studies will be used
as the “Expected Case” for this IRP. This work should be complete
by December 2014
500 different prices using an auto regressive technique will be
modeled, the mean value of the 500 simulations will be equal to the
“Expected Case” forecast
A controversial input for these prices is the amount of variance
within the 500 simulation.
– Historically prices were highly volatile, recent history is more stable
– Final variance estimates will look at current market volatility and implied
variance from options contracts

2015 Electric IRP Appendix A
224
Henry Hub Natural Gas Prices *
* Based on methodology described above, to be updated
$0.00
$2.00
$4.00
$6.00
$8.00
$10.00
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
$
p
e
r

D
t
h
2013 IRP
Forwards (11/20/2014)
Avista 2014 Forecast
Actuals
Levelized price is $5.37/dth
2015 Electric IRP Appendix A
225
Coal Prices
With lower natural gas prices and EPA regulations the
demand for US based coal is lower, but potential exports
may stabilize the industry
Western US coal plants typically have long-term
contracts and many are mine mouth
Rail coal projects are subject to diesel price risk
Prices will be based on review of coal plant publically
available prices and EIA mine mouth and rail forecasts

2015 Electric IRP Appendix A
226
Hydro
80 years of hydro conditions are used for the Northwest
states, British Columbia and California provided by BPA
– Hydro levels change monthly
– AURORA dispatches the monthly hydro based on whether its
run-of-river or storage.
For stochastic studies the hydro levels will be randomly
drawn from the 80-year record
A new Columbia River Treaty could change regional
hydro patterns, but until there is resolution, no changes
will be included

2015 Electric IRP Appendix A
227
Northwest State Hydro Volatility
Mean: 15,587 aMW
2015 Electric IRP Appendix A
228
-
5,000
10,000
15,000
20,000
25,000
El Niño Neutral La Niña All Data
Av
e
r
a
g
e

M
e
g
a
w
a
t
t
s
Mean
2 Stdev High
2 Stdev Low
Northwest Hydro Variability (1929-2008)
28% 52% 20% Annual Probability
14 2015 Electric IRP Appendix A
229
Wind
Wind generation in the Northwest’s is the fastest growing resource
type
RECs and PTC’s have caused wind facilities to economically
generate in oversupply periods in the Northwest- particularly in the
spring months
Wind is modeled using an autoregressive technique to simulate
output in similar to reported data available from BPA, CAISO, and
other publically available data sources- also considers correlation
between regions
For stochastic studies several wind curves, will be drawn from to
simulate variation in wind output each year

2015 Electric IRP Appendix A
230
Wind Generation Profile (January 2007-14 from BPA)
Hour of January
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1 18 3552 69 86
10
3
12
0
13
7
15
4
17
1
18
8
20
5
22
2
23
9
25
6
27
3
29
0
30
7
32
4
34
1
35
8
37
5
39
2
40
9
42
6
44
3
46
0
47
7
49
4
51
1
52
8
54
5
56
2
57
9
59
6
61
3
63
0
64
7
66
4
68
1
69
8
71
5
73
2
Ca
p
a
c
i
t
y

F
a
c
t
o
r
Mean: 23.3%
Stdev: 27.8%
2015 Electric IRP Appendix A
231
Modeled Wind Generation Profile
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1 20 39 58 77 96
11
5
13
4
15
3
17
2
19
1
21
0
22
9
24
8
26
7
28
6
30
5
32
4
34
3
36
2
38
1
40
0
41
9
43
8
45
7
47
6
49
5
51
4
53
3
55
2
57
1
59
0
60
9
62
8
64
7
66
6
68
5
70
4
72
3
74
2
Ca
p
a
c
i
t
y

F
a
c
t
o
r
Mean: 27.7%
Stdev: 24.1%
Hour of January
2015 Electric IRP Appendix A
232
Oversupply
Hours Mid-Columbia Prices Were Less Than $0/MWh
Source: Powerdex daily average prices- substantially more hours had trades with negative pricing
Jan Feb Mar Apr May Jun Jul Aug
2011 8 10 4 31 39 85 25 0
2012 0 0 8 60 84 260 137 3
2013 0 0 0 0 31 0 11 0
2014 0 0 36 20 67 34 2 0
0
50
100
150
200
250
300
Mi
d
-Co
l
u
m
b
i
a

P
r
i
c
e

H
o
u
r
s

B
e
l
o
w

Z
e
r
o
Total
202
552
42
159
2015 Electric IRP Appendix A
233
Western Interconnect Coal Capacity
Forecast
Announced retirements are 42% of coal plant capacity in the
west between 2010 and 2035

0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
45,000
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
Me
g
a
w
a
t
t
s
2015 Electric IRP Appendix A
234
Cooling Water Issues
Once-through cooling
– California plants with this cooling technology must be
converted to alternative cooling methods or retired
– For modeling purposes: older natural gas units will be
retired and Diablo Canyon will be retrofitted
Traditional water cooling
– New NG resources are finding it more difficult to use
water cooling- for new resources air cooling will be
assumed

2015 Electric IRP Appendix A
235
Once-Through Cooling Affect
14,167 MW of natural gas plants in California are
affected by once-through-cooling rules
Represents 29% of California’s natural gas fleet

0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
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
Me
g
a
w
a
t
t
s
2015 Electric IRP Appendix A
236
Western State’s Renewable Portfolio
Standards Capacity/Energy Forecast
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
40,000
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
Na
m
e
p
l
a
t
e

(
M
W
)
Hydro
Geothermal
Biomass
Wind
Solar
Added Energy (aMW)
2015 Electric IRP Appendix A
237
PRiSM- Preferred Resource Strategy
Model
Internally developed using Excel based
linear/mixed integer program model (What’s Best)
Selects new resources to meet Avista’s capacity,
energy, and renewable energy requirements
Outputs:
– Power supply costs (variable and fixed)
– Power supply costs variation
– New resource selection (generation/conservation)
– Emissions
– Capital requirements

2015 Electric IRP Appendix A
238
PRiSM
Find optimal resource strategy to meet resource deficits over
planning horizon
Model selects its resources to reduce cost, risk, or both.
Objective Function:
– Minimize: Total Power Supply Cost on NPV basis (2016-2054)-
Focus on first 20 years of the plan
– Subject to:
•Risk level
•Capacity need +/- deviation
•Energy need +/- deviation
•Renewable portfolio standards
•Resource limitations, sizes, and timing

2015 Electric IRP Appendix A
239
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
2015 Electric IRP Appendix A
240
Conservation Potential
Assessment
Technical Advisory Committee Meeting
November 21, 2014
2015 Electric IRP Appendix A
241
2
Outline
Study Approach
LoadMAP Overview
Market Characterization
Baseline Projection
Measure Development
Ramp Rate Development
Economic Screening
Potential Results
Consistency with Council Methodology

2015 Electric IRP Appendix A
242
3
Study objectives
Characterize
the Market
Base-year energy use by segment
Prototypes and energy analysis (BEST) Avista forecast data
Codes and standards RTF data Secondary data
Project the
Baseline
End-use forecast by segment
Screen Measures
and Options
Measure descriptions Avista program data
Avista avoided costs NWPCC/RTF workbooks
Technical and economic potential
Establish Customer
Acceptance
Avista programs Other studies
Market acceptance/ramp rates
Achievable potential
Synthesize Sensitivity analysis
Study results
Avista billing data Avista program data Energy Market Profiles
Avista GenPOP, RBSA, CBSA and other surveys Secondary data Previous study results
Study approach
2015 Electric IRP Appendix A
243
4

LoadMAPTM analysis tool
LoadMAP stands for Load
Management, Analysis and Planning
– Analyzes EE, DR, distributed
generation/renewables and
electricification trends
– Used for more than 40 potential
assessments in last six years
LoadMAP modeling features
– Embodies principles of rigorous end-use
models (like EPRI’s REEPS and
COMMEND)
– Uses stock-accounting
– Uses a simple decision logic
– Models are customized by end use
User friendly and transparent
algorithms:
– Excel-based model
– Can easily update all assumptions and
results flow through to pre-formatted
charts and tables
– Conduct sensitivity analysis
– Answer what-if questions from senior
management
2015 Electric IRP Appendix A
244
5
Segmentation for the CPA
Dimension Segmentation
Variable Dimension Examples
1 State Washington and Idaho
2 Sector Residential, Commercial, Industrial
3 Segment
Residential: by housing type and income
Commercial: by building type
Industrial: as a whole
4 Vintage Existing and new construction
5 End uses Cooling, heating, ventilation, lighting, water heat, refrigeration,
motors, etc. (customized for each sector)
6 Appliances/end uses
and technologies
Technologies such as lamp type, air conditioning equipment, motors
by size, etc.
7
Equipment efficiency
levels for new
purchases
Baseline efficiency and an array of higher-efficiency options as
appropriate for each technology
2015 Electric IRP Appendix A
245
6
We begin with a high-level market characterization
Washington Customers 2013 Electricity
Sales (GWh)
Residential 200,134 2,452
General Service 27,142 416
Large General Service 3,352 1,557
Extra Large Commercial 9 266
Extra Large Industrial 13 614
Pumping 2,361 136
Total 233,011 5,440
Source: Avista 2012 CPA
Idaho Customers 2013 Electricity
Sales (GWh)
Residential 99,580 1,182
General Service 19,245 323
Large General Service 1,456 700
Extra Large Commercial 3 70
Extra Large Industrial 6 196
Pumping 1,312 59
Total 121,602 2,530
Avista (WA and ID) Customers 2013 Electricity
Sales (GWh)
Residential 299,714 3,634
General Service 46,387 739
Large General Service 4,808 2,257
Extra Large Commercial 12 336
Extra Large Industrial 19 810
Pumping 3,673 195
Total 354,613 7,970
2015 Electric IRP Appendix A
246
7
We disaggregate sectors into most important segments
Residential
Avista Total
Number of
Customers
Annual Use
(GWh) % of Sales Intensity
(kWh/HH)
Single Family 168,339 2,399 66% 14,251
Multi Family 23,456 202 6% 8,612
Mobile Home 10,022 128 4% 12,772
Low Income 97,896 905 25% 9,245
Total 299,714 3,634 100% 12,125
Source: Avista 2012 CPA
2015 Electric IRP Appendix A
247
8
Market profiles characterize how
customers use energy in the base
year.
• All buildings/dwellings
• New construction

Basic Equation:

where
Energy = annual energy use
e = equipment technology
N = number of homes
Sate = saturation of homes with the equip
UECe = unit energy consump in homes with
the equipment present

This sample market profile is captured
from LoadMAP. Saturations and UECs
are inputs to the model. LoadMAP
calculates the intensity and usage. Values
shown in the Total line match the market
characterization control totals.

We develop energy market profiles for each sector


e
eeUECSatNEnergy )(
Source: Avista 2012 CPA
2015 Electric IRP Appendix A
248
9
Energy market profiles summarized
Source: Avista 2012 CPA

Annual Intensity for Average Household % of Use by End Use, All Homes
2015 Electric IRP Appendix A
249
10
Data sources for energy market profiles
Model Inputs Description Key Sources
Market size Base-year residential dwellings, commercial
floor space, and industrial employment
Avista billing data, GenPOP survey, American
Community Survey, NEEA surveys and
reports, NPCC Sixth Plan
Annual intensity
Residential: Annual energy use
(kWh/household)
Commercial: Annual energy use (kWh/ sq ft) Industrial: Annual energy use (kWh/employee)
Avista billing data, AEG Energy Market
Profiles database , NEEA surveys and reports,
AEO, previous studies
Appliance/equipment
saturations
Fraction of dwellings with an
appliance/technology;
Percentage of commercial floor space or
industrial employment with
equipment/technology
GenPOP survey, NEAA surveys and reports,
RECS, AEG Energy Market Profiles, and other
secondary data
UEC/EUI for each end-
use technology
UEC: Annual electricity use for a technology in
dwellings that have the technology
EUI: Annual electricity use per square
foot/employee for a technology in floor space
that has the technology
NEAA surveys and reports, RTF/SEEM data,
RTF UES workbooks, engineering analysis,
BEST prototype simulations, engineering
analysis
Appliance/equipment
vintage distribution Age distribution for each technology NEEA surveys and reports, secondary data (DEEM, EIA, EPRI, DEER, etc.)
Efficiency options for
each technology
List of available efficiency options and annual
energy use for each technology
RTF, Council workbooks, prototype
simulations, engineering analysis,
appliance/equipment standards, secondary
data, previous studies 2015 Electric IRP Appendix A
250
11
We develop a baseline projection
Projects energy market profiles into the future
• Baseline projection is an end-use forecast of energy usage absent the effects
of future conservation programs. Includes the effects of appliance standards
and building codes, but holds efficiency purchasing trends at current levels
(assumes no naturally-occurring conservation).
Model Inputs Description Key Sources
Customer growth
forecasts
Forecasts of new construction in
residential and C&I sectors Data provided by Avista’s Forecasting Department
Equipment purchase
shares for baseline
projection
For each equipment/technology,
purchase shares for each efficiency
level; specified separately for existing
equipment replacement and new
construction
Avista program results
Shipments data from AEO
AEO regional forecast assumptions
RTF data on current market baseline
NEEA surveys and reports
Appliance/efficiency standards analysis
Exogenous forecast
drivers
Retail price forecasts
Personal income forecasts
Other
Avista forecasts
AEO

Utilization model
parameters Elasticities for each forecast driver
EPRI’s REEPS and COMMEND models
AEO
Avista’s historical weather data and normal weather data (cooling & heating degree days) 2015 Electric IRP Appendix A
251
12
Timeline of current residential appliance standards
Today's Efficiency or Standard Assumption 1st Standard (relative to today's standard)
2nd Standard (relative to today's standard)
End Use Technology 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Central AC
Room AC
Evaporative Central AC
Evaporative Room AC
Cooling/Heating Heat Pump
Space Heating Electric Resistance
Water Heater (<=55 gallons)
Water Heater (>55 gallons)
Screw-in/Pin Lamps
Linear Fluorescent T12
Refrigerator/2nd Refrigerator
Freezer
Dishwasher Conventional
(355kWh/yr)
Clothes Washer
Clothes Dryer
NAECA Standard
NAECA Standard
Conventional
(MEF 1.26 for top loader)
Conventional (EF 3.01)
Cooling EER 11.0
SEER 13
EER 9.8
Conventional
Conventional
Water Heating
EF 0.95
Heat Pump Water Heater
EF 0.90
EF 0.90
Advanced Incandescent - tier 2 (45 lumens/watt)
T8
SEER 14.0/HSPF 8.0SEER 13.0/HSPF 7.7
Electric Resistance
Incandescent
5% more efficient (EF 3.17)
Appliances
25% more efficient
25% more efficient
14% more efficient (307 kWh/yr)
MEF 1.72 for top loader MEF 2.0 for top loader
Lighting
Advanced Incandescent - tier 1 (20 lumens/watt)
2015 Electric IRP Appendix A
252
13
Example of a residential baseline projection
Source: Avista 2012 CPA
• Growth of 32% from ‘09 to '33, or 1.5% per year on average.
• Per household basis, use is increasing slightly at 4% for the forecast period, or
0.2% per year.
Total Annual Use (MWh) Annual Use per Household (kWh)
2015 Electric IRP Appendix A
253
14
ECM identification & characterization
•Develop measure list using
• Council workbooks
• Existing programs
• AEG databases
•Characterization
• Description
• Costs
• Savings
• Applicability
• Lifetime
•Data sources
• RTF
• Avista data
• AEG’s database
• BEST simulations
•Measure Crosswalk
Example:
Water heating measures
Conventional (EF 0.95)
Heat pump water heater (EF 2.3)
Solar water heater
Low-flow showerheads
Timer / Thermostat setback
Tank blanket
2015 Electric IRP Appendix A
254
15
ECM savings and costs
• Measure savings change relative to baseline throughout study (as shown)
• We use a market baseline, consistent with RTF/Council
• Measure costs change with market projections and expectations
Example of Savings Calculation for
Screw-in Lighting Technologies
2015 Electric IRP Appendix A
255
16
Calculating the three levels of potential
ECM data
Economic
screening
Customer
adoption
2015 Electric IRP Appendix A
256
17
Estimating potential and ramp rates
Technical potential assumes most efficient option is chosen by all customers

Economic potential assumes all customers choose the highest-efficiency option
that passes economic screen
•Use TRC and Avista’s avoided cost to perform economic screen

Achievable potential is a subset of economic potential
•Calculated by applying ramp rates to economic potential
•Our approach for Avista:
Start with ramp rates from the 6th Power Plan
Map the Council ramp rates to ECMs in our analysis
Adjust the starting point for each measure’s ramp rate to align with Avista’s recent program
accomplishments
2015 Electric IRP Appendix A
257
18
Customer adoption (ramp) rates
Residential ramp rates from NWPCC
Lost Opportunity
Ramp Rates:
Applied to equipment
units each year that are
turning over into a new
purchase decision.
Non-Lost Opportunity
Ramp Rates:
Applied cumulatively to
all applicable
opportunities in the
market over time.
2015 Electric IRP Appendix A
258
19
Residential conservation potential
For 2014 to 2023,
ten-year achievable
potential savings are
about 252 GWh.

This is 28.8 aMW.
2014 2015 2018 2023 2028 2033
Cumulative WA and ID Savings (MWh)
Achievable Potential 21,848 42,786 147,588 251,961 392,098 547,119
Economic Potential 231,078 335,111 744,684 1,041,719 1,390,377 1,549,252
Technical Potential 963,411 1,037,905 1,338,457 1,473,324 1,727,383 1,911,746
Cumulative Savings (aMW)
Achievable Potential 2.5 4.9 16.8 28.8 44.8 62.5
Economic Potential 26.4 38.3 85.0 118.9 158.7 176.9
Technical Potential 110.0 118.5 152.8 168.2 197.2 218.2
Example from Avista 2012 CPA
0
50
100
150
200
250
2014 2015 2018 2023 2028 2033
En
e
r
g
y

S
a
v
i
n
g
s

(
a
M
W
)
Achievable Potential
Economic Potential
Technical Potential
2015 Electric IRP Appendix A
259
20
Achievable Potential in 2018
Top measures in the residential sector
Example from Avista 2012 CPA
Measure/Technology
2018
Cumulative
Savings (MWh)
% of Total
Interior Lighting Screw-in 39,805 27%
Electric Furnace 17,175 12%
Interior Specialty Lighting 16,484 11%
Exterior Screw-in Lighting 14,121 10%
Water Heater <= 55 Gal 11,129 8%
Water Heater - Tank Blanket/Insulation 7,317 5%
Thermostat - Clock/Programmable 6,783 5%
Water Heater - Low Flow Showerheads 5,885 4%
Water Heater - Pipe Insulation 4,790 3%
Electric Resistance 3,738 3%
Water Heater - Faucet Aerators 3,244 2%
Central AC 2,687 2%
Water Heater - Thermostat Setback 2,626 2%
Refrigerator 2,187 1%
Insulation - Infiltration Control 1,692 1%
Furnace Fan 1,170 1%
Personal Computers 1,111 1%
Insulation - Foundation 791 1%
Freezer 789 1%
TVs 745 1%
2015 Electric IRP Appendix A
260
21
AEG Consistency with Council Methodology
End-use model — bottom-up
•Building characteristics, fuel and equipment saturations
•Stock accounting based on measure life
•Codes and standards that have been enacted are included in baseline
•Lost- and non-lost opportunities treated differently
Measures – comprehensive list
•RTF measure workbooks
•BPA data
•AEG databases, which draw upon same sources used by RTF
Economic potential, total resource cost (TRC) test
•Considers HVAC interactions, non-energy benefits
•Avoided costs include 10% credit based on Conservation Act
Achievable potential – ramp rates
•Based on Sixth Plan ramps rates, but modified to reflect Avista’s program history

2015 Electric IRP Appendix A
261
Ingrid Rohmund
[e-mail]

Bridget Kester
[e-mail]

Fuong Nguyen
[e-mail]

Sharon Yoshida
[e-mail]

Thank You!
2015 Electric IRP Appendix A
262

2015 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 4 Agenda
Tuesday, February 24, 2015
Red Lion River Inn – Shoreline Ballroom A, Spokane, WA
Topic Time Staff
1. Introduction & TAC 3 Recap 8:30 Lyons

2. Demand Response Study 8:45 Doege

3. Natural Gas Price Forecast 9:15 Dorr
Break
4. Electric Price Forecast 10:30 Gall

5. Lunch 11:30
6. Resource Requirements 12:30 Kalich
Break
7. Interconnection Studies 1:15 Maguire

8. Market Scenarios and Portfolio Analysis 2:15 Lyons

9. Adjourn 3:00

TAC meeting location: Red Lion River Inn Spokane
Shoreline Ballroom A
700 N. Division
Spokane, WA 99202

Directions: http://www.redlion.com/river-inn-spokane/map-directions

2015 Electric IRP Appendix A
263
2015 Electric IRP
TAC Meeting Expectations and Schedule
John Lyons, Ph.D.
Fourth Technical Advisory Committee Meeting
February 24, 2015
2015 Electric IRP Appendix A
264
Technical Advisory Committee
• The public process of the IRP – input on what to study, how to study, and
review assumptions and results

• Technical forum with a range of participants with different areas of input
and expertise

• Open forum, but we need to stay on topic to get through the agenda and
allow all participants to ask questions and make comments

• Welcome requests for studies or different assumptions.
– Time or resources may limit the amount of studies
– The earlier study requests are made, the more accommodating we can be
– January 15, 2015 was the final date to receive study requests

• Action Items – areas for more research in the next IRP
2 2015 Electric IRP Appendix A
265
Technical Advisory Committee
• Technical forum on inputs and assumptions, not an advocacy forum

• Focus is on developing a resource strategy based on sound assumptions
and inputs, instead of a forum on a particular resource or resource type

• We request that everyone maintain a high level of respect and
professional demeanor to encourage an ongoing conversation about the
IRP process

• Supports rate recovery, but not a preapproval process

• Planning team is available by email or phone for questions or comments
between the TAC meetings

3 2015 Electric IRP Appendix A
266
Remaining TAC Meetings
•TAC 5 – March 24, 2015: Completed conservation potential
assessment, draft preferred resource strategy (PRS), review
of scenarios, market futures, and portfolio analysis
•TAC 6 – June 24, 2015: Review of final PRS and action
items.
4 2015 Electric IRP Appendix A
267
TAC #3 Recap
• Introduction & TAC 2 Recap – Lyons
• Planning Margin – Gall
• Colstrip Discussion – Lyons
• Cost of Carbon – Lyons
• IRP Modeling Overview – Gall
• Conservation Potential Assessment – Kester

5 2015 Electric IRP Appendix A
268
Today’s Agenda
• Introduction & TAC 3 Recap (8:30) – Lyons
• Demand Response Study (8:45) – Doege
• Natural Gas Price Forecast (9:15) – Scott
– Break
• Electric Price Forecast (10:30) – Gall
• Lunch (11:30)
• Resource Requirements (12:30) – Kalich
– Break
• Interconnection Studies (1:15) – Maguire
• Market Scenarios and Portfolio Analysis (2:15) – Lyons
• Adjourn 3:00
6 2015 Electric IRP Appendix A
269
Demand Response
Potential Assessment Study
Study & Report by: Applied Energy Group & Avista

Prepared by Leona Doege
Fourth Technical Advisory Committee Meeting
February 24, 2015
2015 Electric IRP Appendix A
270
Purpose of Study
2013 Electric IRP Action Item

Answer the following questions:
• How much capacity for DR?
• How long will it take to reach it (ramp rate)?
• How much will it cost?

2 2015 Electric IRP Appendix A
271
Demand Response
Customers making a change to their consumption in
response to a price or incentive signal.

Graph Source: FERC Demand Response Report 2006
3 2015 Electric IRP Appendix A
272
Demand Response History at Avista
•2001: Nickel buyback program

•2006: Public plea, & bilateral agreements
(emergency load shedding)

•2007-2009: Idaho 2-year residential direct load control
pilot

•2012-2014 : Washington: 2.5-year residential & WSU
direct load control demonstration (SGDP- Pullman)
4 2015 Electric IRP Appendix A
273
Study Approach

• Review U.S. Demand Response Programs
Categorized DR Programs
• Segmented Avista C&I customers
• Identify DR Programs relevant to Avista & C&I customers
• Develop & discuss assumptions
• Develop framework
5 2015 Electric IRP Appendix A
274
Demand Response Programs Relevant to
Avista
Load Aggregator
6 2015 Electric IRP Appendix A
275
Demand Response Options Overview
DLC Firm RTP
Targeted Segment Sch 11 & 21 Sch 21 & 25 Sch 11, 21 & 25
Resource
Availability
Varies Year Around Year Around
Event Notification Day Ahead Day ahead –
preferred or 30 min
Day Ahead
Max Event Hrs/YR 60 hours 60 hours 60 Hours
Event Duration 4 to 6 hours each 1 to 8 hours each 4 hours each
Type of Response Space & water heat Non-essential loads
or back-up gen.
Load curtailment or
back-up gen.
Participant
Incentive
$60 annually SH
$50 annually WH
Determined & paid
by 3rd party
On-Off peak price
differential
Other Directly admin by
Avista
Admin by 3rd party
Need AMI
10-15 max events
per year. Need AMI
7 2015 Electric IRP Appendix A
276
Summary of Results
Graph from page 30 of report
8 2015 Electric IRP Appendix A
277
DR Potential by Option
from page 30 of report
9 2015 Electric IRP Appendix A
278
Program Costs & Potential
Stand Alone
Interactive
Charts from pages 32 & 33 of report
Firm Curtailment and standby generation have overlapping capacity 10 2015 Electric IRP Appendix A
279
Standby Generation Partnership

Prepared by Marc Schaffner
Fourth Technical Advisory Committee Meeting
February 24, 2015
11 2015 Electric IRP Appendix A
280
What is Standby Generation Partnership?
A prospective partnership between customers and
Avista to meet future peak load needs utilizing
existing and future standby distributed generation.

12 2015 Electric IRP Appendix A
281
Standby Generation Opportunities
• Interconnect customers diesel or natural gas-powered generators to
Avista’s distribution system
• Utilize standby generator output as a peak resource and to improve
voltage regulation on Avista’s electric distribution system
• Introduce natural gas blending to diesel-powered generators for
cleaner, more economical operation
• Utilize standby generators as a cost-effective non-spinning reserve
• Conduct an in-house pilot by interconnecting Avista’s standby
generators at its headquarters in Spokane

13 2015 Electric IRP Appendix A
282
2015 Electric IRP
Natural Gas Price Forecast
Eric Scott, Manager of Natural Gas Resources
Fourth Technical Advisory Committee Meeting
February 24, 2015
2015 Electric IRP Appendix A
283
North American Pipeline Infrastructure
2 2015 Electric IRP Appendix A
284
Pacific Northwest Supply and Infrastructure
AECO
Canadian gas coming out of Alberta, Canada
Rockies
U.S. domestic gas coming from Wyoming and Colorado
Sumas
Canadian gas coming out of British Columbia, Canada
Malin
South central at the Oregon and California border
Stanfield
Intersection of two major pipelines in North Central Oregon

Williams Northwest Pipeline
TransCanada Gas Transmission Northwest
TransCanada Foothills
TransCanada Alberta
Spectra Energy
Ruby Pipeline

Jackson Prairie Storage
Mist Storage
SU
P
P
L
Y

PI
P
E
L
I
N
E
S

ST
O
R
A
G
E

3 2015 Electric IRP Appendix A
285
Types of Pipeline Contracts
Firm Transport
• Contractual rights to:
• Receive
• Transport
• Deliver
• From point A to point B
Interruptible Transport
• Contractual rights to:
• Receive
• Transport
• Deliver
• From point A to Point B AFTER FIRM TRANSPORT HAS BEEN SCHEDULED
Seasonal Transport
• Firm service available for limited periods (Nov-Mar) or for a limited amount (TF2 on NWP)
Alternate Firm Transport
• The use of firm transport outside of the primary path
• Priority rights below firm
• Priority rights above interruptible
4 2015 Electric IRP Appendix A
286
Pipeline Rate Structure
• Pipeline charges a higher demand charge and a lower variable or commodity charge
Straight Fixed Variable (SFV)
• Pipeline charges a lower demand charge and a higher variable or commodity charge
Enhanced fixed variable
• Pay the same demand and variable costs regardless of how far the gas is transported
Postage Stamp Rate
• Pay a variable and demand charge based on how far the gas is transported Mileage Based
5 2015 Electric IRP Appendix A
287
TransCanada Gas Transmission
Northwest (GTN)
• Mileage Based
• Point to Point
• Alternate firm allowed in path
• Mostly – demand based with a couple Nomination based points
• Demand based refers to gas that will be taken off the pipeline based
on the demand behind the delivery point.
• Nomination based refers to the pipeline only delivering what was
nominated (requested).
• Usually requires upstream transportation
6 2015 Electric IRP Appendix A
288
Mileage Base: Pay
based on how far
you move the gas
Jackson Prairie
7 2015 Electric IRP Appendix A
289
Williams Northwest Pipeline (NWP)
• Postage Stamp Based
• Point to Point
• Delivery to ‘zones’ allowed
• Alternate firm allowed in and out of path
• Demand based delivery
• Demand based refers to gas that will be taken off the pipeline based
on the demand behind the delivery point.
• Nomination based refers to the pipeline only delivering what was
nominated (requested).
• May or may not require upstream transportation
• Enhanced fixed variable structure
8 2015 Electric IRP Appendix A
290
Postage Stamp:
Same costs
regardless of
distance or locations
Jackson Prairie
9 2015 Electric IRP Appendix A
291
Natural Gas Pricing Fundamentals
10 2015 Electric IRP Appendix A
292
What Drives the Natural Gas Market?
Natural Gas Spot Prices

Supply
– Type: Conventional vs. Non-conventional
– Location
– Cost
Demand
– Residential/Commercial/Industrial
– Power Generation
– Natural Gas Vehicles
Legislation
– Environmental
Energy Correlations
– Oil vs. Gas
– Coal vs. Gas
– Natural Gas Liquids
Weather
Storage
11 2015 Electric IRP Appendix A
293
12 2015 Electric IRP Appendix A
294
13 2015 Electric IRP Appendix A
295
14 2015 Electric IRP Appendix A
296
Natural Gas Storage
15 2015 Electric IRP Appendix A
297
The Short Term Fundamentals
Bulls
Dwindling rig counts
Economic recovery
LNG & Ethanol Plants
Weather – Normal is now bullish
Bears
Demand is weak
Storage is full
Oil Prices are near 5 year lows
Record Production

16 2015 Electric IRP Appendix A
298
US Production – Where will it come from?
17 2015 Electric IRP Appendix A
299
Shale gas refers to natural
gas that is trapped within
shale formations.

Shales are fine-grained
sedimentary rocks that can
be rich sources of
petroleum and natural gas.

Over the past decade, the
combination of horizontal
drilling and hydraulic
fracturing has allowed
access to large volumes of
shale gas that were
previously uneconomical to
produce.

What is Shale Gas?
18 2015 Electric IRP Appendix A
300
Evolving Flow Dynamics
19 2015 Electric IRP Appendix A
301
The Link Between Rig Counts and Production
20 2015 Electric IRP Appendix A
302
Our friends to the North - Production
21 2015 Electric IRP Appendix A
303
LNG Export is the New Import
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
*As of January 8th, 2015 22 2015 Electric IRP Appendix A
304
IRP Natural Gas Price Forecast Methodology
1.Two fundamental forecasts (Consultant #1 & Consultant #2)
2.Forward prices
3.Year 1: forward price only
4.Year 2: 75% forward price / 25% average consultant forecasts
5.Year 3: 50% forward price / 50% average consultant forecasts
6.Year 4 – 6: 25% forward price / 75% average consultant forecasts
7.Year 7+: 50% average consultant without CO2 / 50% average
consultant with CO2

23 2015 Electric IRP Appendix A
305
Forecasted Levelized Price
24 2015 Electric IRP Appendix A
306
Henry Hub Forecasted Prices
25 2015 Electric IRP Appendix A
307
2015 Electric IRP
Electric Market Forecast
James Gall, Senior Power Supply Analyst
Fourth Technical Advisory Committee Meeting
February 24, 2015
2015 Electric IRP Appendix A
308
14
24 24
122 130
22
38 43
59
46 52 60
33 33 25 20
33 35
22 27 29
$0
$20
$40
$60
$80
$100
$120
$140
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
$
p
e
r

M
W
h
Mid-Columbia Flat Firm Price Index History
Energy Crisis
Natural Gas Market Tightens
Shale Development Cheap Natural
Gas, good
hydro
Forwards
as of Feb.
18, 2015
2 2015 Electric IRP Appendix A
309
Natural Gas vs. Electric Prices (2003-14)
y = 7.7832x + 3.9974
R² = 0.9589
$0
$10
$20
$30
$40
$50
$60
$70
$80
$0 $2 $4 $6 $8 $10
Mi
d
-C
$

p
e
r

M
W
h
Stanfield $ per DTh
3 2015 Electric IRP Appendix A
310
Market Indicators
$0
$5
$10
$15
$20
$25
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
$
p
e
r

M
W
h
Daily Price Standard Deviation
Off Peak
On Peak
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
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
Po
w
e
r
/

G
a
s

x

1
0
0
0
Implied Market Heat Rate
4.57
6.13 7.02
3.89
7.95
3.62
7.24
4.43
(2.45)
1.30
7.71
4.54
-$4
-$2
$0
$2
$4
$6
$8
$10
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
St
a
n
f
i
e
l
d

x

7

-
Mi
d

C
Spark Spread
4 2015 Electric IRP Appendix A
311
US Power Generation
0
100
200
300
400
500
600
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
Av
e
r
a
g
e

G
i
g
a
w
a
t
t
s
Renewables Oil Hydro Nuclear Natural Gas Coal
5 2015 Electric IRP Appendix A
312
Fuel Mix Comparison
Biomass
1%
Coal
41%
Natural Gas
27%
Geothermal0%
Nuclear20%
Oil0%
Other
0%
Solar
0%
Hydro
7%
Wind
4%
Biomass1%
Coal31%
Natural Gas
29%
Geothermal2%
Nuclear
8%
Oil0%
Other0%
Solar1%
Hydro22%
Wind6%
US Western Interconnect US Total
6 2015 Electric IRP Appendix A
313
US Greenhouse Gas Emissions
All Sources
Source: http://epa.gov/statelocalclimate/resources/state_energyco2inv.html
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
Residential Commercial
Industrial Electric Power
Transportation
7 2015 Electric IRP Appendix A
314
Western Greenhouse Gas Emissions
Source: http://epa.gov/statelocalclimate/resources/state_energyco2inv.html
1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
WY 40 39 43 41 43 40 41 41 44 42 44 44 42 43 44 43 43 43 44 41 42 41 43
WA 8 8 10 10 12 8 11 9 12 11 14 14 11 14 14 14 9 12 13 13 13 7 6
UT 29 28 30 30 31 29 30 31 31 32 33 32 33 34 34 35 35 37 38 35 34 33 31
OR 2 4 5 4 5 3 3 3 6 6 7 9 6 8 8 8 6 10 10 9 10 6 7
NV 17 18 19 18 20 18 20 19 21 21 25 24 21 23 25 26 17 17 18 18 17 14 15
NM 27 23 26 27 28 27 28 29 29 30 31 30 28 30 30 32 32 31 30 32 29 31 29
MT 16 17 18 15 18 17 14 16 18 18 17 18 16 18 19 19 19 20 20 17 20 16 15
ID 0 0 0 0 0 0 0 0 0 0 0 1 0 1 1 1 1 1 1 1 1 0 1
CO 31 31 32 32 33 33 34 34 35 35 39 41 40 40 40 40 41 42 41 38 39 38 39
CA 40 38 46 42 49 37 33 36 39 43 53 58 44 43 46 42 46 50 51 48 43 36 48
AZ 33 33 35 37 38 32 32 35 37 39 44 45 45 46 51 50 52 55 57 52 54 52 51
TOTAL 242 238 263 256 278 245 245 253 273 278 306 315 286 299 312 310 302 316 321 303 301 275 284
0
50
100
150
200
250
300
350
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
8 2015 Electric IRP Appendix A
315
3rd party software- EPIS, Inc.
Electric market fundamentals- production cost
model
Simulates generation dispatch to meet load
Outputs:
– Market prices
– Regional energy mix
– Transmission usage
– Greenhouse gas emissions
– Power plant margins, generation levels, fuel costs
– Avista’s variable power supply costs
Electric Market Modeling
9 2015 Electric IRP Appendix A
316
Stochastic Approach
Simulate Western Electric market hourly for next 20
years (2016-35)
– That is 175,248 hours for each study
Model 500 potential outcomes
– Variables include fuel prices, loads, wind, hydro, outages,
inflation
– Simulating 87.6 million hours
Run time is about 5 days on 30 processors
Why do we do this?
– Allows for complete financial evaluation of resource alternatives
– Without stochastic prices we cannot account for tail risk

10 2015 Electric IRP Appendix A
317
Aurora Pricing Example- Supply/Demand
Curve
-$100
-$50
$0
$50
$100
$150
$200
$250
$300
$350
0 10,000 20,000 30,000 40,000 50,000
$
p
e
r

M
W
h
Capability (MW)
Hydro (Must Run for Negative Pricing)
CCCT
Peakers
Demand
Hydro Availability
Fu
e
l

P
r
i
c
e
s
/
V
a
r
i
a
b
l
e

O
&
M

Other Resource Availability
Nuclear/ Co-Gen/ Coal/ Other
Wind (Net PTC/REC)
Market Price
11 2015 Electric IRP Appendix A
318
Modeled Western Interconnect Topology
12 2015 Electric IRP Appendix A
319
Greenhouse Gas Reduction Modeling
• California, BC, and Alberta include CO2 price adder
• 10% probability for other states to have future carbon
price adder (“Tax”)
– Price is $12 per metric ton beginning in 2020, with a 5%
escalator
• Meets EPA 111(d) glide path reduction for total region by
2030
• Load growth is lowered to less than 1% across the
Western Interconnect to account for increased
conservation
• No new coal-fired generation
• Uses existing state Renewable Portfolio Standards
13 2015 Electric IRP Appendix A
320
Western Resource Planned Retirements
0
5
10
15
20
25
30
35
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
Gi
g
a
w
a
t
t
s
Oil
Coal
Natural Gas
Note: Includes only announced plants, and small coal plants in carbon constrained states
Majority of natural gas retirements are once through cooling
2015 Electric IRP Appendix A
321
New Resources to Western Interconnect
-
20
40
60
80
100
120
140
160
-
2
4
6
8
10
12
14
16
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
Cu
m
u
l
a
t
i
v
e

G
i
g
a
w
a
t
t
s
Gi
g
a
g
a
w
a
t
t
s
Storage Biomass
Wind Geothermal
Hydro Solar
Net Meter Natural Gas
Cumulative
2015 Electric IRP Appendix A
322
Resource Type Mix Forecast
(Western Interconnect)
Nuclear
Hydro
Other
Coal
Wind
Solar
Natural Gas
0
20,000
40,000
60,000
80,000
100,000
120,000
140,000
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
Me
g
a
w
a
t
t

A
v
e
r
a
g
e
16 2015 Electric IRP Appendix A
323
Stanfield Natural Gas Price Forecast
Levelized mean price $4.85/dth
Note: Coefficient of variation (stdev/mean) in 2016 is 15%, in 2035, the volatility increases to 56%
$0
$2
$4
$6
$8
$10
$12
$14
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
$
p
e
r

D
e
k
a
t
h
e
r
m
Mean
25th Percentile
75th Percentile
95th Percentile
17 2015 Electric IRP Appendix A
324
Mid-Columbia Electric Price Forecast
(Mean of 500 iterations)
Levelized Prices
Flat: $37.29/MWh
On Peak: $41.08/MWh
Off Peak: $32.24/MWh
$0
$10
$20
$30
$40
$50
$60
$70
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
$
p
e
r

M
W
h
Flat
On-Peak
Off Peak
18 2015 Electric IRP Appendix A
325
Mid-Columbia Electric Price Forecast
(Flat Price Statistics)
Note: Coefficient of variation (stdev/mean) in 2016 is 22%, in 2035, the volatility increases to 52%
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
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
$
p
e
r

M
W
h
Mean
95th Percentile
25th Percentile
75th Percentile
19 2015 Electric IRP Appendix A
326
IRP Price Forecast Comparison
(Flat Prices)
$0
$10
$20
$30
$40
$50
$60
$70
$80
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
$
p
e
r

M
W
h
2015 IRP
2013 IRP
Forwards (02/15/2015)
20 2015 Electric IRP Appendix A
327
Implied Market Heat Rate
-
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
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
20
3
2
20
3
3
20
3
4
20
3
5
Im
p
l
i
e
d

M
a
r
k
e
t

H
e
a
t

R
a
t
e
2015 IRP
2013 IRP
Actual & Forwards (02/18/2015)
21 2015 Electric IRP Appendix A
328
Greenhouse Gas Emissions Forecast
(US Western Interconnect Total)
0
50
100
150
200
250
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
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
US Western Interconnect
Western Internconnect 111d Plants
22 2015 Electric IRP Appendix A
329
Greenhouse Gas Emission Forecast
(State Level)
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
Wyoming 33.3 33.7 34.0 33.2 32.4 32.2 31.2 31.0 31.6 30.7 31.7 31.9 27.3 27.5 25.6 25.0 25.4 25.5 24.4 24.5
Washington 6.5 6.7 7.1 6.7 6.9 5.7 6.0 5.8 6.0 5.4 4.3 4.3 4.2 4.2 4.4 4.3 4.6 4.5 4.8 4.6
Utah 28.9 28.8 29.0 28.7 27.5 27.2 26.8 26.3 26.4 25.8 20.5 20.3 20.4 20.5 20.5 20.4 20.5 20.3 20.2 20.5
Oregon 6.2 6.0 6.6 6.5 6.6 4.8 5.2 5.1 5.4 5.0 5.6 5.9 6.3 6.6 6.8 6.7 7.0 6.9 7.3 7.0
New Mexico 14.3 14.9 14.5 13.6 13.8 13.5 12.7 13.1 13.2 12.5 13.6 13.5 12.9 13.4 13.3 12.7 13.3 13.1 12.5 13.0
Nevada 12.7 12.5 11.7 11.7 11.2 11.4 10.2 9.7 9.9 9.5 9.2 9.4 9.7 9.8 10.1 10.1 10.8 10.9 11.2 11.3
Montana 15.8 15.8 15.5 15.4 16.0 15.4 15.4 15.9 15.4 15.0 15.8 15.2 15.2 15.7 15.3 15.3 16.3 15.9 16.1 16.9
Idaho 1.1 1.7 1.8 1.9 1.7 1.9 2.2 2.2 2.3 2.3 2.2 2.4 3.0 3.1 3.2 3.7 3.7 4.3 4.5 4.4
Colorado 32.2 31.7 30.1 31.4 30.9 29.4 31.1 30.9 30.1 31.5 31.6 30.6 32.6 32.2 31.3 32.6 32.4 31.3 32.3 32.0
California 46.9 47.1 48.0 49.9 52.1 53.9 56.2 57.5 58.6 58.8 59.1 59.2 59.3 59.4 59.7 60.2 62.0 62.6 63.9 64.7
Arizona 51.3 49.9 50.4 48.5 41.6 40.8 40.1 38.6 39.0 37.6 35.3 35.3 35.1 34.4 34.7 34.4 34.5 34.5 34.3 33.8
USA 249.248.248.247.240.236.237.236.238.234.229.228.226.226.225.225.230.229.231.232.
0
50
100
150
200
250
300
Mi
l
l
i
o
n

M
e
t
r
i
c

T
o
n
s
2015 Electric IRP Appendix A
330
EPA 111d Goal Comparison
Note: EPA 2030 goal is adjusted for Langley Gulch and plants residing outside of the Western Interconnect
0
200
400
600
800
1,000
1,200
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
EP
A

l
b
s

p
e
r

M
W
h
Western Interconnect States
2030 Goal
24 2015 Electric IRP Appendix A
331
111(d) EPA State Goal Comparison
801
702
537
1,108
324
1,763
1,048
647
372
1,322
215
1,666
669
922
305
1,082
277
1,667
679
539
313
1,228
231
1,699
0
500
1,000
1,500
2,000
West AZ CA CO ID MT NM NV OR UT WA WY
EP
A

l
b
s

p
e
r

M
W
h
2030 Goal
IRP Forecast
25 2015 Electric IRP Appendix A
332
0
20
40
60
80
100
120
140
160
180
50
10
0
15
0
20
0
25
0
30
0
35
0
40
0
45
0
50
0
55
0
60
0
65
0
70
0
75
0
80
0
85
0
90
0
95
0
10
0
0
It
e
r
a
t
i
o
n
s

o
f

5
0
0
111d lbs per MWh
2020
2030
Washington Emission Volatility
2030 Goal 215 lbs/MWh
2020 Goal 264 lbs/MWh
26 2015 Electric IRP Appendix A
333
2015 Electric IRP
Resource Requirements
Clint Kalich, Manager of Resource Planning and Analysis
Fourth Technical Advisory Committee Meeting
February 24, 2015
2015 Electric IRP Appendix A
334
L&R Methodology Review
• Sum up resource capabilities against loads
– Reduced by planned outages
• Capacity
– Planning Margin
– Operating Reserves and Regulation (~8%)
– Largest deficit months between 1- and 18-hour
analyses
2 2015 Electric IRP Appendix A
335
L&R Methodology Review
• Energy
– Reduced by planned and forced (5-year average)
– Maximum potential thermal generation over the year
–80-year hydro average, adjusted down to 10th percentile
• Renewable Portfolio Standards
– 3% / 9% / 15% requirement of Washington retail load in 2012 /
2016 / 2020
– Qualifying resources less any forward sales obligations
– Banking provisions help smooth out year-to-year variation
• Final resource need determined by shortest position
each year

3 2015 Electric IRP Appendix A
336
Energy Position (aMW)
Year Jan Aug
2014 0 0
2015 0 94
2016 23 81
2017 34 84
2018 36 73
2019 17 (4)
2020 64 (11)
2021 53 (18)
2022 42 (22)
2023 43 (32)
2024 36 (34)
2025 29 (40)
2026 21 (47)
2027 (249) (268)
2028 (257) (274)
2029 (265) (281)
2030 (274) (292)
2031 (282) (295)
2032 (290) (302)
2033 (298) (309)
2034 (307) (316)
2035 (315) (323)
Year Jan Aug
2014 0 0
2015 0 94
2016 23 81
2017 34 84
2018 36 73
2019 17 (4)
2020 64 (11)
2021 53 (18)
2022 42 (22)
2023 43 (32)
2024 36 (34)
2025 29 (40)
2026 21 (47)
2027 (249) (268)
2028 (257) (274)
2029 (265) (281)
2030 (274) (292)
2031 (282) (295)
2032 (290) (302)
2033 (298) (309)
2034 (307) (316)
2035 (315) (323)
4 2015 Electric IRP Appendix A
337
18-Hour Capacity Position (MW)
Year Jan Aug
2014 0 0
2015 0 (212)
2016 (60) (48)
2017 151 38
2018 155 30
2019 106 (10)
2020 (7) (14)
2021 (25) (8)
2022 (43) (18)
2023 (49) (35)
2024 (64) (44)
2025 (78) (57)
2026 (93) (70)
2027 (387) (313)
2028 (401) (326)
2029 (416) (339)
2030 (432) (357)
2031 (447) (359)
2032 (463) (373)
2033 (478) (387)
2034 (494) (400)
2035 (509) (414)
Year Jan Aug
2014 0 0
2015 0 (212)
2016 (60) (48)
2017 151 38
2018 155 30
2019 106 (10)
2020 (7) (14)
2021 (25) (8)
2022 (43) (18)
2023 (49) (35)
2024 (64) (44)
2025 (78) (57)
2026 (93) (70)
2027 (387) (313)
2028 (401) (326)
2029 (416) (339)
2030 (432) (357)
2031 (447) (359)
2032 (463) (373)
2033 (478) (387)
2034 (494) (400)
2035 (509) (414)
5 2015 Electric IRP Appendix A
338
1-Hour Capacity Position (MW)
Year Jan Aug
2014 0 0
2015 0 (266)
2016 (99)36
2017 115 177
2018 118 167
2019 69 124
2020 (44)120
2021 (62)126
2022 (80)114
2023 (87)96
2024 (101)87
2025 (116)73
2026 (131)59
2027 (425) (185)
2028 (440) (199)
2029 (455) (214)
2030 (470) (232)
2031 (486) (235)
2032 (501) (250)
2033 (517) (265)
2034 (532) (280)
2035 (548) (295)
Year Jan Aug
2014 0 0
2015 0 (266)
2016 (99)36
2017 115 177
2018 118 167
2019 69 124
2020 (44)120
2021 (62)126
2022 (80)114
2023 (87)96
2024 (101)87
2025 (116)73
2026 (131)59
2027 (425) (185)
2028 (440) (199)
2029 (455) (214)
2030 (470) (232)
2031 (486) (235)
2032 (501) (250)
2033 (517) (265)
2034 (532) (280)
2035 (548) (295)
6 2015 Electric IRP Appendix A
339
Washington RPS Position (aMW RECs)
0
20
40
60
80
100
120
140
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
Qualifying Hydro Upgrades Qualifying Resources Purchased RECs
Available Bank Requirement & Contingency Requirement
7 2015 Electric IRP Appendix A
340
Impact of Major Contracts (Winter Capacity)
114
92
21
171 171
145
63
(200)
(150)
(100)
(50)
-
50
100
150
200
2014 2015 2016 2017 2018 2019 2020
Me
g
a
w
a
t
t
s
Mid-C WNP-3
PGE Net
8 2015 Electric IRP Appendix A
341
Year Jan Aug
2014 0 0
2015 0 (266)
2016 (99)36
2017 115 177
2018 118 167
2019 69 124
2020 (44)120
2021 (62)126
2022 (80)114
2023 (87)96
2024 (101)87
2025 (116)73
2026 (131)59
2027 (425) (185)
2028 (440) (199)
2029 (455) (214)
2030 (470) (232)
2031 (486) (235)
2032 (501) (250)
2033 (517) (265)
2034 (532) (280)
2035 (548) (295)
Year Jan Aug
2014 0 0
2015 0 (266)
2016 (99)36
2017 115 177
2018 118 167
2019 69 124
2020 (44)120
2021 (62)126
2022 (80)114
2023 (87)96
2024 (101)87
2025 (116)73
2026 (131)59
2027 (425) (185)
2028 (440) (199)
2029 (455) (214)
2030 (470) (232)
2031 (486) (235)
2032 (501) (250)
2033 (517) (265)
2034 (532) (280)
2035 (548) (295)
Position Summaries

Energy 18-Hr Cap 1-Hr Cap Year Jan Aug
2014 0 0
2015 0 94
2016 23 81
2017 34 84
2018 36 73
2019 17 (4)
2020 64 (11)
2021 53 (18)
2022 42 (22)
2023 43 (32)
2024 36 (34)
2025 29 (40)
2026 21 (47)
2027 (249) (268)
2028 (257) (274)
2029 (265) (281)
2030 (274) (292)
2031 (282) (295)
2032 (290) (302)
2033 (298) (309)
2034 (307) (316)
2035 (315) (323)
Year Jan Aug
2014 0 0
2015 0 94
2016 23 81
2017 34 84
2018 36 73
2019 17 (4)
2020 64 (11)
2021 53 (18)
2022 42 (22)
2023 43 (32)
2024 36 (34)
2025 29 (40)
2026 21 (47)
2027 (249) (268)
2028 (257) (274)
2029 (265) (281)
2030 (274) (292)
2031 (282) (295)
2032 (290) (302)
2033 (298) (309)
2034 (307) (316)
2035 (315) (323)
Year Jan Aug
2014 0 0
2015 0 (212)
2016 (60) (48)
2017 151 38
2018 155 30
2019 106 (10)
2020 (7) (14)
2021 (25) (8)
2022 (43) (18)
2023 (49) (35)
2024 (64) (44)
2025 (78) (57)
2026 (93) (70)
2027 (387) (313)
2028 (401) (326)
2029 (416) (339)
2030 (432) (357)
2031 (447) (359)
2032 (463) (373)
2033 (478) (387)
2034 (494) (400)
2035 (509) (414)
Year Jan Aug
2014 0 0
2015 0 (212)
2016 (60) (48)
2017 151 38
2018 155 30
2019 106 (10)
2020 (7) (14)
2021 (25) (8)
2022 (43) (18)
2023 (49) (35)
2024 (64) (44)
2025 (78) (57)
2026 (93) (70)
2027 (387) (313)
2028 (401) (326)
2029 (416) (339)
2030 (432) (357)
2031 (447) (359)
2032 (463) (373)
2033 (478) (387)
2034 (494) (400)
2035 (509) (414)
9 2015 Electric IRP Appendix A
342
Rely on the Wholesale Market?
• Market is made up of real generating assets
• Largest market reliance questions for Avista
– Is there enough surplus in region to meet our and
other utilities’ future needs?
– Are we willing to expose ourselves to market
volatility?
10 2015 Electric IRP Appendix A
343
Rely on the Wholesale Market?
• 5% is considered by industry to be a minimum level for reliability
•2021 likely will be worse given closure of Boardman and Centralia Unit
1 in 2020 (over 1,200 MW)
• 2026 loss of Centralia Unit 2 (670 MW)
Northwest Power and Conservation
Council Year 2020 Reliability Assessment
11 2015 Electric IRP Appendix A
344
Resource Option Capacity Contributions
12
Technology Type
Name-
plate
(MW)
Winter
Capacity
Summer
Capacity Technology Type
Name-
plate
(MW)
Winter
Capacity
Summer
Capacity
GE - 7F.05 Gas Peaker 203.0 109% 97%Rathdrum Supplemental Compression Upgrade 24.0 100% 100%
GE - 7F.04 Gas Peaker 170.5 109% 96%Rathdrum CT 2055 Uprates Upgrade 5.0 100% 100%
GE - 7F.04- Add HRSG Gas CCCT 115.3 107% 96%Kettle Falls Upgrade Upgrade 12.0 100% 100%
GE - 7EA Gas Peaker 96.1 106% 96%Rathdrum CT: Inlet Evaporation Upgrade 4.3 0% 403%
GE - LMS100PA Gas Hybrid 101.2 105% 94%Kettle Falls Fuel Stabilization Upgrade 3.0 100% 100%
Jenbacher 920 flex Gas Recip 9.3 100% 100%Long Lake 2nd Powerhouse Upgrade 68.0 100% 100%
Siemens- SGT-800-50 Gas Peaker 45.1 110% 96%Post Falls Upgrade Upgrade 22.0 24% 0%
GE - LM6000- PF Sprint Gas Peaker 42.5 107% 95%Monroe St 2nd Powerhouse Upgrade 80.0 31% 0%
GE - 7F.05 1x1 Gas CCCT 341.3 106% 97%Cabinet Gorge 2nd Powerhouse Upgrade 110.0 0% 0%
GE - 7F.04 1x1 Gas CCCT 285.8 107% 96%Direct Load Control Customer 7.2+100% 100%
Wind On System Wind 33.0 0% 0%Firm Curtailment Customer 7.5+100% 100%
Solar Photovoltaic Fixed Solar 10.0 0% 62%Time-Of-Use Customer 1+ 100% 100%
Solar Photovoltaic 1 Axis Solar 10.0 0% 70%Critical Peak Pricing Customer 4+ 100% 100%
Battery Storage Battery 25.0 100% 100%StandbyGeneration Customer 20+ 100% 100%
Northeast CT Water Injection Upgrade 7.5 100% 100%
2015 Electric IRP Appendix A
345
Resources Acquisitions Are Lumpy
(600)
(500)
(400)
(300)
(200)
(100)
0
100
200
300
400
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
Me
g
a
w
a
t
t
s
Position CCCT Net
LMS-100 Net Recips Net
13 2015 Electric IRP Appendix A
346
Options to Address Lumpiness
• Wait until size of need is larger
– Pro: no surplus, Con: exposed to market
• Build smaller-sized units
– Pro: closely meets need, Con: higher cost machines
• Partner with other utilities
– Pro: better match of need, Con: not much interest
14 2015 Electric IRP Appendix A
347
2015 Electric IRP
Interconnection Studies
Richard Maguire, System Planning Engineer
Fourth Technical Advisory Committee Meeting
February 24, 2015
2015 Electric IRP Appendix A
348
Federal Standards of Conduct
1.No non-public transmission information can be
shared with Avista Merchant Function
employees
2.There are Avista Merchant Function employees
attending today
3.We will not be sharing any non-public
transmission information
2 2015 Electric IRP Appendix A
349
Agenda
• Introduction to Avista System Planning
• Two Big Changes This Year
• Recent Avista Projects
• Generation Interconnection Study Process
• Large Generation Interconnection Queue
• Integrated Resource Plan (IRP) Requests
• Future Transmission Planning Initiatives

3 2015 Electric IRP Appendix A
350
Introduction to Avista System Planning
• Transmission system planning
• Distribution system planning
• Asset Management
• We all care about:
– Federal, regional, and state compliance
– Regional system coordination
– Internal standards and processes
4 2015 Electric IRP Appendix A
351
Big Change #1 – Regional Coordination

• WECC
“has been approved by the Federal Energy Regulatory
Commission (FERC) as the Regional Entity for the
Western Interconnection”
• Peak Reliability
“is listed on the NERC Compliance Registry to perform
the Reliability Coordinator (RC) and Interchange
Authority (IA) functions as statutory activities”
PeakWECC
tageSanDiegoOu
WECC 2
5 2015 Electric IRP Appendix A
352
Big Change #2 – NREC TPL Standards
• Background
– Loss of two or more elements (N-1-1)
• If you have 300 elements (line, xfmr, bus, etc)
– 300 X 299 = 89,700 outage events
– If order does not matter (AB = BA)
» COMBIN(300,2) = 44,850 outage events
– 44,850 analysis takes about 12 hours on my laptop
• “Out with the old”: TPL-xxx-3
– N-1-1 termed, ‘Category C’
– Engineering judgment allowed pairing down the list
• “In with the new”: TPL-xxx-4
– N-1-1 termed, ‘P6’
– More ‘teeth’ in standard means more testing necessary
• We need to look at all P6 events
– Takes about a month on a study machine for all cases
6 2015 Electric IRP Appendix A
353
Big Change #2 – What are we doing?
• People possibilities
– We could work longer, or we could take work home
– We could take on risk and use engineering judgment
– We could hire another engineer
• Process possibilities
– We are working with PowerWorld Corporation to
enhance their ‘Distributed Computing’ environment
– We are investigating new study machine purchases
– A collection of machines working concurrently REALLY
reduces analysis times
7 2015 Electric IRP Appendix A
354
Recent Transmission Projects
8 2015 Electric IRP Appendix A
355
Lancaster ‘Loop-in’
9 2015 Electric IRP Appendix A
356
Moscow Station
10 2015 Electric IRP Appendix A
357
Noxon Station
11 2015 Electric IRP Appendix A
358
Generation Interconnection Study Process
• Typical Process for Generation Requests
• We generally get requests via two sources:
• External developers
• Internal IRP requests
• Typical process:
• We hold a scoping meeting to discuss particulars
• We outline a study plan
• We augment WECC approved cases for our studies
• We analyze the system against the standards
• We publish our findings and recommendations

12 2015 Electric IRP Appendix A
359
Generate Study Cases
13 2015 Electric IRP Appendix A
360
Analyze Study Cases
14 2015 Electric IRP Appendix A
361
Publish Results
www.oasis.oati.com/avat/index.html
15 2015 Electric IRP Appendix A
362
LGIA #43 – 150 MW Wind Project
16 2015 Electric IRP Appendix A
363
2015 IRP Request Snapshot
Station Request (MW) POI Voltage Cost Estimate ($ million)
Kootenai County 100 230 kV 12 - 16.1
Kootenai County 350 230 kV 47.2
Rathdrum 26 115 kV 2.84 - 10.9
Rathdrum 50 115 kV 10.7 – 18.7
Rathdrum 200 115 kV 10.3 - 48.5
Rathdrum 50 230 kV 7 – 16.8
Rathdrum 200 230 kV 15.5 – 21.5
Thornton 30 230 kV .4
Thornton 100 230 kV .4
Othello 25 115 kV 2
Northeast 10 115 kV 0
Kettle Falls 10 115 kV 0
Long Lake 68 115 kV 19.7
Monroe Street 80 115 kV 7
Post Falls 10 115 kV 2.1
Post Falls 20 115 kV 5.2

[1] Preliminary estimates are given as -25% to +75% 17 2015 Electric IRP Appendix A
364
Cost Assignment for Generation Integration
• Simulate Generation Integration
– Develop new list of “gen” violated elements
– Compare new list to previous violated elements
(without gen)
• New violated elements are assigned to gen project
– If previous violated elements need a corrective action
advanced in time
• Consider assignment of advancement cost to gen project
– Any projects that improve transmission service to
existing AVA customers need consideration as a
network upgrade
18 2015 Electric IRP Appendix A
365
2015 IRP Study Notes
• These are pre-feasibility studies
– Limited cases and scenarios
– No stability studies
• All generation fully on
• Results include incremental issues, not base
case issues
• $$ estimates for planned projects are flexible
19 2015 Electric IRP Appendix A
366
Kootenai: 100 MW to 350 MW
• $16 to $48 Million
• Overlaps existing projects
• 426 MW existing already
20 2015 Electric IRP Appendix A
367
Rathdrum: 26 MW to 200 MW
• $2.84 to $48.5 Million
• Overlaps existing projects
• 426 MW existing already
21 2015 Electric IRP Appendix A
368
Thornton: 30 MW to 100 MW
• $400 K for new breaker

22 2015 Electric IRP Appendix A
369
Othello: 25 MW
• $2 Million
• Station work only
23 2015 Electric IRP Appendix A
370
Long Lake: 68 MW
• $19.7 Million
• 108 MW existing + 9 mile
24 2015 Electric IRP Appendix A
371
Monroe Street: 80 MW
• $7 Million
• College & Walnut Station
25 2015 Electric IRP Appendix A
372
Post Falls: 10 MW to 20 MW
• $2.1 to $5.2 Million
• Congested area already
26 2015 Electric IRP Appendix A
373
Future Planning Initiatives
27 2015 Electric IRP Appendix A
374
Future Initiatives
• Big Bend
– New 230 kV transformation needed
• Coeur d’ Alene
– Noxon Station work
– 115 kV rebuilds
• Lewiston / Clarkston
– Voltage issues
• Palouse
– Two transformer outage scenario
• Spokane
–Long-term 230 kV transformation additions

28 2015 Electric IRP Appendix A
375
2015 Electric IRP
Market Scenarios and Portfolio Analysis
John Lyons, Ph.D. – Senior Resource Policy Analyst
Fourth Technical Advisory Committee Meeting
February 24, 2015
2015 Electric IRP Appendix A
376
Scenarios in the 2015 IRP
• Scenarios are modeled to provide details about
the impacts of different critical planning
assumptions that could impact future resource
choices, such as:
–Technological innovations
–Regulatory changes
–Environmental regulations or legislation
–Load and resource changes

2 2015 Electric IRP Appendix A
377
2015 IRP Scenario Types

1.Deterministic Market Scenarios: use expected input
levels (natural gas prices, hydro, loads, wind, and
thermal outages)

2.Stochastic Market Scenarios: use Monte Carlo analysis

3.Portfolio Scenarios: show alternative portfolios to
highlight the cost differences from the PRS

3 2015 Electric IRP Appendix A
378
Market Scenarios
4
Stochastic scenarios test the preferred resource strategy
(PRS) across several fundamentally different futures:
•Expected Case
•Expected Case without Colstrip (2027-2035)
•Benchmarking Case
•111(d) draft rule by state meets 2020 goals
•Social Cost of Carbon

4 2015 Electric IRP Appendix A
379
Portfolio Scenarios
5
•Shut down Colstrip in 2026
•2013 PRS
•High and low load forecasts
•All load growth with renewables and peakers for capacity:
•All hydro, wind, solar
•All deficits met by market purchases
•Efficient frontier
•Efficient frontier with tail risk
•TAC requested high cost Colstrip case
•Retire CCCT/coal and replace with renewables
•Increased distributed solar penetration

5 2015 Electric IRP Appendix A
380

2015 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 5 Agenda
Tuesday, May 19, 2015
Conference Room 130
Topic Time Staff
1. Introduction & TAC 4 Recap 8:30 Lyons

2. Review of Market Futures 8:40 Gall

3. Ancillary Services Valuation 9:30 Shane

4. Conservation Potential Assessment 10:00 Kester (AEG)

5. Lunch 11:30

6. Draft 2015 PRS & Portfolio Analysis 12:30 Planning Group

7. Adjourn 3:00

2015 Electric IRP Appendix A
381
2015 Electric IRP
TAC Meeting Expectations and Schedule
John Lyons, Ph.D.
Fifth Technical Advisory Committee Meeting
May 19, 2015
2015 Electric IRP Appendix A
382
Technical Advisory Committee
• The public process of the IRP – input on what to study, how to study, and
review assumptions and results

• Technical forum with a range of participants with different areas of input
and expertise

• Open forum, but we need to stay on topic to get through the agenda and
allow all participants to ask questions and make comments

• Welcome requests for studies or different assumptions.
– Time or resources may limit the amount of studies
– The earlier study requests are made, the more accommodating we can be
– January 15, 2015 was the final date to receive study requests

• Action Items – areas for more research in the next IRP
2 2015 Electric IRP Appendix A
383
Technical Advisory Committee
• Technical forum on inputs and assumptions, not an advocacy forum
• Focus is on developing a resource strategy based on sound assumptions
and inputs, instead of a forum on a particular resource or resource type
• We request that everyone maintain a high level of respect and
professional demeanor to encourage an ongoing conversation about the
IRP process
• Supports rate recovery, but not a preapproval process
• Planning team is available by email or phone for questions or comments
between the TAC meetings
•TAC 6 – June 24, 2015: Review of final PRS, draft 2015 IRP document
and Action Items.

3 2015 Electric IRP Appendix A
384
TAC #4 Recap
• Introduction & TAC 3 Recap – Lyons
• Demand Response Study – Doege
• Natural Gas Price Forecast – Scott
• Electric Price Forecast – Gall
• Resource Requirements – Kalich
• Interconnection Studies – Maguire
• Market Scenarios and Portfolio Analysis – Lyons

4 2015 Electric IRP Appendix A
385
Today’s Agenda
• Introduction & TAC 4 Recap (8:30) – Lyons
• Review of Market Futures (8:40) – Gall
• Ancillary Services Valuation (9:30) – Shane
• Conservation Potential Assessment (10:00) – Kester (AEG)
• Lunch (11:30)
• Draft 2015 PRS and Portfolio Analysis (12:30) – Planning
Group
• Adjourn 3:00
5 2015 Electric IRP Appendix A
386
Market Futures
James Gall
Fifth Technical Advisory Committee Meeting
May 19, 2015
DRAFT
2015 Electric IRP Appendix A
387
Introduction
• Follow up presentation to the “Expected Case”
market price forecast from the previous TAC
meeting- this presentation shows alternatives
prices given each future scenario
• Used to value the cost of energy and resource
options for potential resource strategies
• Illustrate macro level impacts of environmental
policies
2 2015 Electric IRP Appendix A
388
Market Futures Overview
• Expected Case
– Stochastic, meets regional 111(d) goals, 10% probability of $13.23 CO2 “tax”
(1st yr), Stanfield $4.65/dth levelized, 80 year hydro
• Benchmark Case
– Similar to expected case, stochastic, no CO2 “tax”, no 111d goal
• Social Cost of Carbon
– Stochastic case, similar to expected case, except includes ~$21/short ton
CO2 “tax” levelized
• Colstrip Retires
– Stochastic case, similar to expected case, except Colstrip 1-4 retires by the
end of 2026 and replaced with natural gas combined cycle plants
• State-by-State 111(d)
– Deterministic case, each state meets 111(d) goals
– MWh credit remains in state generated in
– Includes a low water year scenario
3 2015 Electric IRP Appendix A
389
20-year Levelized Flat Mid-C Electric
Price Comparison (Stochastic)
$38.48 $38.71 $38.08
$45.41
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
Expected Case Colstrip Retires Benchmark Social Cost of
Carbon
Le
v
e
l
i
z
e
d

$

p
e
r

M
W
h
4 2015 Electric IRP Appendix A
390
Cost to Serve
US West: Production + Fixed Costs
$20.9 $21.1 $20.9
$24.5
$0
$5
$10
$15
$20
$25
$30
Expected
Case
Colstrip
Retires
Benchmark Social Cost of
Carbon
Le
v
e
l
i
z
e
d

C
o
s
t

(
B
i
l
l
i
o
n
s
)
5 2015 Electric IRP Appendix A
391
US West: Greenhouse Gas Emissions
Comparison
-
50
100
150
200
250
300
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
Mi
l
l
i
o
n
s

o
f

M
e
t
r
i
c

T
o
n
s
Expected Case
Colstrip Retires
Benchmark
Social Cost of Carbon
6 2015 Electric IRP Appendix A
392
Meeting 111(d) Targets in 2030
0
400
800
1,200
1,600
2,000
West AZ CA CO ID MT NM NV OR UT WA WY
EP
A

I
b
s
/
M
W
h
Goal
Expected Case
Colstrip Retires
Benchmark Case
Social Cost of Carbon
7 2015 Electric IRP Appendix A
393
How to Meet the Proposed 111(d) in 2020
& 2030 State by State
• Resource Retirements:
– Northwest: Centralia and Boardman must close by end of 2019
– Other States: Most of SW coal must retire earlier
• Conservation:
– Continue acquisition levels from Expected Case
• Renewables:
– Arizona & Utah must increase penetration
– Other states stay on current steady track
• NW Carbon Pricing
– WA & OR required $1.25/ton charge nominal 2020-2035
– ID required $3.00/ton 2020-2029 and $1.50/ton 2030-2035
8 2015 Electric IRP Appendix A
394
Mid-C Market Price Impact of the 111(d)
Proposal Scenario (Deterministic)
$38.40 $39.02
$0
$5
$10
$15
$20
$25
$30
$35
$40
$45
$50
Expected Case 111d Proposal
Le
v
e
l
i
z
e
d

$

p
e
r

M
W
h
9
Assumes average hydro conditions
2015 Electric IRP Appendix A
395
111(d) Impact in a Low Water Year
• Can the Northwest meet 111(d) goals in a low
water year?
• Modeled 1941 water year (10th percentile year)
• Solve for Carbon Price to meet goal in each year
– WA: $18/ton (2020), $18/ton (2030)
– OR: $19/ton (2020), $15/ton (2030)
– ID: $23/ton (2020), $14/ton (2030)
– Neighboring states have small price increases
10 2015 Electric IRP Appendix A
396
Mid-C Market Prices: 111(d) Low Water Year
2030 With Water Year = 1941
$48.89 $49.50
$53.68
$57.80
$0
$10
$20
$30
$40
$50
$60
$70
Expected Case 111d Proposal Expected Case
(1941)
111d Proposal
(1941)
An
n
u
a
l

A
v
e
r
a
g
e

F
l
a
t

P
r
i
c
e

($
/
M
W
h
)
Low Water Year
Increases Prices
$4.79/MWh (10%)
Holding 111(d)
Emissions will Increase
Prices by $8.91/MWh or
18% over average
conditions
111(d) will bring
minor impact to
NW prices with
average water
conditions
11 2015 Electric IRP Appendix A
397
Financial Impact to Western States
• Proposed 111(d) goal’s annual levelized cost to
the US West is $340 million over the Expected
Case in an Average Water Year.
• In Low Water Year the US West will pay up to
$1.6 billion (2020) beyond the Expected Case’s
Low Water Year cost, declining to $175 million
in 2030. (levelized $755 million)

12 2015 Electric IRP Appendix A
398
Ancillary Services Valuation
Xin Shane
Fifth Technical Advisory Committee Meeting
May 19, 2015
2015 Electric IRP Appendix A
399
Ancillary Services Valuation Basics
What?

• The U.S. Federal Energy Regulatory
Commission (FERC) defines ancillary
services as: "those services necessary to
support the transmission of electric power
from seller to purchaser given the
obligations of control areas and
transmitting utilities within those control
areas to maintain reliable operations of
the interconnected transmission system.“

• FERC identifies six different ancillary
services:
– scheduling and dispatch
– reactive power and voltage control
– loss compensation
– load following
– system protection
– energy imbalance

Why?

• Ancillary services are a significant
value component of a generating
unit

• The Washington UTC asked
Avista to “use the Company’s new
modeling capabilities to evaluate
the benefits of storage resources
to Avista’s generation portfolio.”
2 2015 Electric IRP Appendix A
400
Overview of ADSS Model
• Mixed-Integer linear program
• Full emulation of utility power supply problem
– hourly analysis out to 20+ years
– trading floor behavior
– energy and ancillary services
– unit- and engineering-level system definitions
– modeling of transmission and market hubs
3
Avista Decision Support System
2015 Electric IRP Appendix A
401
Hydro Modeling in ADSS
• Cascading hydro
• “Engineering level” representation
• Full power curve modeling
• Flow limitations
– ramping rates
– minimums/maximums
–in-stream flow limits
– dissolved gas
• Plant head
– impacts of flow on head (“live” tailrace)
–in-plant head losses
– impacts of head on efficiency curves
• Operating considerations
– min/max up/down times
– must run
– dispatch and merit order
– motoring/condensing
– AGC control
– start-up/shut-down costs
– min/max turbine/generator limits
– rough zones, thermal limits
– flash boards, Obermeyer gates
– unit steady states
– elevation targets
– water right limits

4 2015 Electric IRP Appendix A
402
Thermal Modeling in ADSS
• “Engineering level” representation
• Weather impacts
– barometric pressures
– dew point
– temperature
– humidity
• Detailed heat rate curves
• Start-up & shut down costs
– fuel, O&M, ramp rates
• Multiple fuels
• Detailed emissions modeling
–NOX, SOX, VOX, Hg, CO2
– generation-level production
– permit limit optimization (allocation)
• Multiple operating stages
– duct firing
• Operating considerations
– ramp rates
– min/max up/down times
– must run
– dispatch and merit order (on and off)
– AGC control
– min/max turbine/generator limits
– thermal limits
–equal wear cycling
– unit steady-states
– water right limits
5 2015 Electric IRP Appendix A
403
Colstrip

Avista
BA
Broadview
Townsend
Ownership
Change
BPA/Colstrip
Garrison
Taft
Dworshak
Hatwai
Hot Springs
BPA PTP
196 MW
Coyote
Springs 2
BPA PTP
97 MW
Benton
Mid-C
Market
125 MW
BPA PTP
240 MW
Ownership
Changes
AVA/PAC/AVA
50 MW
BPA PTP
210 MW
BPA EI
230 MW
Ownership
Change
BPA/AVA
John
Day COB Market
(MC+$2.00)
PGE IS
100 MW
BPA PTP
250 MW
Judith Gap
Great Falls
Eastern
Market (Sell Only)
(MC-$0.50)
Transmission Assumptions

AVA $0/MWh, 0.0% losses
NWE $5/MWh, 4.0% losses
BPA PTP $3/MWh, 1.9% losses
Colstrip 5.5% losses (to Garrison)
PGE IS 2.0% losses
Total BPA PTP Firm Rights 568 MW (416 MW 10-1-14)
Colstrip Output >196 MW must go thru NWE
No transmission required to sell to NWE

Firm Transmission
ST-Firm Transmission
Eastern
Market (Sell Only)
(MC-$0.50)
Transmission/Market Modeling in ADSS
6 2015 Electric IRP Appendix A
404
Reserve Modeling in ADSS
ADSS
Reserves
Regulation
Regulation Up
Regulation Down
Operating
Reserve
Spinning Reserve
Non-spinning reserve
Load Following
Load Following Up
Load Following Down
Standby
Reserve
7 2015 Electric IRP Appendix A
405
Storage Valuation
Key Input Assumptions
• Storage Specification
– Max Storage = 3×Capacity
• e.g., 1 MW = 3 MWh
– 85% Efficiency
– Hourly Charge/Discharge Rate = 100%
of Capacity
– Capable of All Ancillary Services
• Regulation +/- 100%
• Load following +/- 100%
• Spin/non-spin +/- 100%
• Model Input
– Year 2012 Historical Data
– Year 2015 Gas and Power Prices
– Average Hydro

Study Scenario
• By Size
– 35 MW, 30 MW, 25 MW, 10 MW, 5 MW
and 1 MW
• By Ancillary Service Product Type
– Charge/Discharge only
– With Load Following/Contingency
Reserve/Regulation
• By Energy Consumption Rate
– 10%, 25% and 50% of Load Following
and Regulation

8 2015 Electric IRP Appendix A
406
Storage Valuation Results
9
Battery Value Summary by Size
Battery Cap (MW) Annual Value Annual Value/KW
35 1,201,590$ 34.33$
30 1,024,569$ 34.15$
25 923,291$ 36.93$
10 381,407$ 38.14$
5 189,000$ 37.80$
1 36,862$ 36.86$
Battery Value Summary by Capability for 25MW
Capability Annual Value - 25 MW Incremental
Charge/Discharge Only 629,082$ 64.2%
Load Following 905,114$ 276,032$ 28.2%
SpinR/NSpinR 678,906$ 49,824$ 5.1%
Regulation(AGC)653,402$ 24,320$ 2.5%
Battery Value Summary by Energy Cost Ratio of AS for 25MW
Energy Cost Ratio Annual Value
0.10 884,093$
0.25 923,291$
0.50 876,962$
2015 Electric IRP Appendix A
407
New Generating Resource Ancillary
Services Valuation
• New Resources Included in Study
– 100 MW CCCT
– 100 MW LMS
– 100 MW Recip
– 25 MW Diesel Back-up Generator

• Model Input
– Based on Historical Data of Years 2010-14
– Portfolio Contracts adjusted to Year 2020 Conditions
– Load adjusted to Year 2020 Conditions

• Run Scenario: for each new resource
– Base Case Run with Existing Portfolio of Year 2020 Conditions
– Energy-Only Run (i.e., no ability to generate ancillary services)
– Energy/Capacity Run (i.e., ability to generate energy and ancillary services)

10
Ancillary service value will be unique to each system
New Generating Resources Ancillary Services
Capability
Ancillary Service
Value ($/kw year)
100 MW CCCT Load Following/SpinR/Reg 0.00$
100 MW LMS Load Following/SpinR/NSpinR/Reg 1.12$
100 MW Recip Load Following/SpinR 0.61$
25 MW Diesel Back-up Generator NSpinR -$
2015 Electric IRP Appendix A
408
Why Are Ancillary Service Values Low

11 2015 Electric IRP Appendix A
409
Avista
Conservation Potential
Assessment
Presentation to the Technical Advisory Committee
May 19, 2015
2015 Electric IRP Appendix A
410
2
Outline
• Study Approach
•Market Characterization
•Baseline Projection
•Measure Development
•Economic Screening
•Ramp Rate Development
• Potential Results
•Overall – Washington and Idaho
•Washington by sector
•Idaho by sector
• Consistency with Council Methodology
• Supplemental slides
•Market characterization for all three sectors for WA and ID

2015 Electric IRP Appendix A
411
3
AEG Uses a Bottom-up Analysis Approach
Establish objectives
Characterize the
Market
Base-year energy use by segment
Prototypes and energy analysis (AEG’s BEST)
Avista Forecast data Customer surveys Secondary data

Project the
Baseline
End-use projection by segment
Screen EE
Measures
Measure descriptions Emerging technologies
RTF data Avoided costs AEG’s DEEM
Technical and economic potential
Establish Customer
Acceptance
Program results
Council ramp rates
Other studies

Achievable potential
Avista data Secondary data
Customer surveys AEG’s Energy Market Profiles
2015 Electric IRP Appendix A
412
Overview of Analysis Approach
Using the Residential Sector
2015 Electric IRP Appendix A
413
5
Step 1a: Characterize the Market

Segment Number of
Customers
Annual
Sales
(GWh)
% of Sales Intensity
(kWh/HH)
Single Family 195,222 2,626 70% 13,450
Multi Family 17,229 139 4% 8,082
Mobile Home 12,526 151 4% 12,063
Low Income 96,112 837 22% 8,711
Total 321,089 3,753 100% 11,690
Avista Sales in 2013
8,081 GWh
High-level characterization by sector – Washington and Idaho combined
2015 Electric IRP Appendix A
414
6
Step 1a: Characterize the Market
Residential characterization by state
• Full market
characterization for
Washington and Idaho is
provided in the
supplemental slides
• The following slides focus
on Washington

Washington
Segment Number of
Customers
Annual
Sales
(GWh)
% of Sales Intensity
(kWh/HH)
Single Family 129,893 1,783 70% 13,726
Multi Family 11,964 99 4% 8,236
Mobile Home 7,691 95 4% 12,354
Low Income 64,092 570 22% 8,892
Total 213,640 2,546 100% 11,919
Idaho
Segment Number of
Customers
Annual
Sales
(GWh)
% of Sales Intensity
(kWh/HH)
Single Family 65,329 843 70% 12,902
Multi Family 5,265 41 3% 7,733
Mobile Home 4,835 56 5% 11,599
Low Income 32,020 267 22% 8,349
Total 107,449 1,207 100% 11,233
2015 Electric IRP Appendix A
415
7
Step 1b: Develop Market Profiles by Sector and Segment
Base-year annual energy use by segment and end use

Annual Intensity for Average Household - Washington
Data Sources:
•Avista billing data and residential GenPOP appliance saturation survey
•Residential Building Stock Assessment (NEEA)
•Commercial Building Stock Assessment (NEEA)
•Secondary data as needed to fill gaps
Total 2013 Residential Sales by End Use -
Washington
2015 Electric IRP Appendix A
416
8
Step 2: Project the Baseline
• Baseline projection provides
foundation for estimating
potential future savings
from conservation initiatives
and reflects
•Household growth and
electricity price forecasts
(from Avista)
•Appliance standards in place
at end of 2014 (AEG
database)
•No naturally occurring
conservation or future utility
programs
•Alignment with Avista load
forecast
Residential Baseline Energy Projection (GWh)
Residential Baseline Electricity Use per Household (kWh/hh)
2015 Electric IRP Appendix A
417
9
Develop measure list using
Council workbooks
Existing programs
AEG databases
Characterization
Description
Costs
Savings
Applicability
Lifetime
Data sources
RTF
Avista data
AEG’s database
BEST simulations
Measure Crosswalk
Step 3: Screen EE Measures
Example:
Water heating measures
Conventional (EF 0.95)
Heat pump water heater (EF 2.3)
Solar water heater
Low-flow showerheads
Timer / Thermostat setback
Tank blanket
2015 Electric IRP Appendix A
418
10
• Measure savings change relative to baseline throughout study (as shown)
• We use a market baseline, consistent with RTF/Council
• Measure costs change with market projections and expectations
Example of Savings Calculation for
Screw-in Lighting Technologies
Step 3: Screen EE Measures
2015 Electric IRP Appendix A
419
11
Step 4: Estimate Potential Future Savings
Use LoadMAP model to estimate potential

Technical Potential
Theoretical upper limit of EE, where all efficiency measures are phased in regardless of cost

Economic Potential
Also a theoretical upper limit of EE, but includes only cost-effective measures

Achievable Potential
EE potential that can be realistically achieved by utilities, accounting for customer adoption rates and how quickly programs can be implemented

2015 Electric IRP Appendix A
420
12
Estimating Potential and Developing Ramp Rates
•Technical potential assumes most efficient option is chosen by all customers

•Economic potential assumes all customers choose the highest-efficiency
option that passes economic screen
•Use TRC and Avista’s avoided cost to perform economic screen

•Achievable potential is a subset of economic potential
•Calculated by applying ramp rates to economic potential
•Our approach for Avista:
• Start with ramp rates from the 6th Power Plan
• Map the Council ramp rates to ECMs in our analysis
• Adjust the starting point for each measure’s ramp rate to align with Avista’s recent program
accomplishments
2015 Electric IRP Appendix A
421
13
Customer Adoption (Ramp) Rates
Residential ramp rates from NWPCC
Lost Opportunity
Ramp Rates:
Applied to equipment
units each year that are
turning over into a new
purchase decision.
Non-Lost Opportunity
Ramp Rates:
Applied cumulatively to
all applicable
opportunities in the
market over time.
2015 Electric IRP Appendix A
422
14
Summary of Changes since Previous study
•Updated base year from 2011 to 2013
• Refined the market segmentation
• Incorporated Avista’s GenPOP residential saturation survey
• Supplemented with NEEA’s Residential Building Stock Assessment (RBSA) and
Commercial Building Stock Assessment (CBSA) data
• Characterized summer peak demand, in addition to annual energy use by segment and
end use
•Also estimated potential summer-peak savings
• Used updated forecasting assumptions for baseline projection
• Developed revised ramp rates using Council ramp rates as starting point and adjusting to
reflect Avista program results in recent years
•Developed estimates based solely on Council ramp rates for comparison purposes
• Incorporated new avoided costs
• And otherwise updated all measure, technology and modeling assumptions
•There was substantial change in lighting: LED prices came down and lamps are readily available
and acceptable to customers

2015 Electric IRP Appendix A
423
Summary of Conservation Potential
Across All Sectors
2015 Electric IRP Appendix A
424
16
2016 2017 2020 2025 2035
Cumulative WA and ID Savings (GWh)
Achievable Potential 34 74 236 574 1,090
Economic Potential 68 139 360 733 1,292
Technical Potential 173 344 837 1,581 2,506
Cumulative Savings (aMW)
Achievable Potential 3.9 8.5 27.0 65.6 124.5
Economic Potential 7.7 15.8 41.1 83.7 147.5
Technical Potential 19.7 39.3 95.5 180.5 286.1
Avista Conservation Potential – All Sectors
From 2015 to 2025,
cumulative achievable
potential savings are 574
GWh, or 65.6 aMW.

Achievable potential in
2025 is about 78% of
economic potential.

Washington and Idaho combined
2015 Electric IRP Appendix A
425
17
Avista Conservation Potential – All Sectors
Washington and Idaho combined
In the early years, savings from residential and commercial are about the
same. Starting in 2020, savings are more likely to come from the commercial
sector as a result of appliance standards. Industrial consistently contributes
about 20% of the savings each year.
2015 Electric IRP Appendix A
426
18
2016 2017 2020 2025 2035
Cumulative WA and ID Savings (GWh)
Achievable Potential 13.1 29.9 87.1 168.6 274.1
Economic Potential 29.3 60.1 136.7 219.4 333.8
Technical Potential 84.5 168.7 400.1 718.9 1,116.7
Cumulative Savings (aMW)
Achievable Potential 1.5 3.4 9.9 19.3 31.3
Economic Potential 3.3 6.9 15.6 25.0 38.1
Technical Potential 9.6 19.3 45.7 82.1 127.5
Avista Conservation Potential – Residential
From 2016 to 2025,
cumulative achievable
potential savings are 169
GWh, or 19.3 aMW.

Achievable potential in
2025 is about 77% of
economic potential.

Washington and Idaho combined
2015 Electric IRP Appendix A
427
19
Energy savings by end use
Avista Residential Savings Potential – WA & ID
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017 Cumulative
Energy Savings
(MWh)
% of
Total
Interior Lighting - Screw-in/Hard-wire (LED) 13,616 45.6%
Ducting - Repair and Sealing 5,057 16.9%
Exterior Lighting - Screw-in/Hard-wire (LED) 4,152 13.9%
Water Heater - Pipe Insulation 2,264 7.6%
Water Heater - Faucet Aerators 1,037 3.5%
Behavioral Programs 688 2.3%
Thermostat - Clock/Programmable 674 2.3%
Insulation - Ducting 621 2.1%
Water Heater - Low-Flow Showerheads 419 1.4%
Electronics - Personal Computers 285 1.0%
Total 28,800 96.4%
2015 Electric IRP Appendix A
428
20
Avista Residential Savings Potential – WA & ID
Cumulative achievable energy savings potential over time
% of Cumulative Achievable Potential Cumulative Achievable Potential (GWh)
2015 Electric IRP Appendix A
429
21
2016 2017 2020 2025 2035
Cumulative WA and ID Savings (GWh)
Achievable Potential 13.2 28.4 104.7 304.4 617.3
Economic Potential 29.2 59.7 171.1 395.3 727.7
Technical Potential 71.2 141.7 352.8 694.2 1,095.9
Cumulative Savings (aMW)
Achievable Potential 1.5 3.2 12.0 34.7 70.5
Economic Potential 3.3 6.8 19.5 45.1 83.1
Technical Potential 8.1 16.2 40.3 79.2 125.1
Avista Conservation Potential – Commercial
From 2016 to 2025,
cumulative achievable
potential savings are 304
GWh, or 34.7 aMW.

Achievable potential in
2025 is about 77% of
economic potential.

Washington and Idaho combined
2015 Electric IRP Appendix A
430
22
Energy savings by end use
Avista Commercial Savings Potential – WA & ID
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017 Cumulative
Energy Savings
(MWh)
% of
Total
Interior Lighting - Linear LED 6,604 23.3%
Interior Lighting - Screw-in/Hard-wire
LED and CFL 3,889 13.7%
Chiller - Chilled Water Reset 1,362 4.8%
Exterior Lighting - Linear LED 1,135 4.0%
Interior Lighting - High-Bay Fixtures T5
and LED 1,130 4.0%
HVAC - Duct Repair and Sealing 1,068 3.8%
Interior Lighting - Occupancy Sensors 975 3.4%
Interior Lighting - Skylights 831 2.9%
Exterior Lighting - Screw-in/Hard-wire
CFL and LED 702 2.5%
Exterior Lighting – HID T5 and LED 671 2.4%
Total Top 10 Measures 18,367 64.7%
2015 Electric IRP Appendix A
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23
Avista Commercial Savings Potential – WA & ID
Cumulative achievable energy savings potential over time
% of Cumulative Achievable Potential Cumulative Achievable Potential (GWh)
2015 Electric IRP Appendix A
432
24
2016 2017 2020 2025 2035
Cumulative WA and ID Savings (GWh)
Achievable Potential 7.8 16.0 44.4 101.5 199.0
Economic Potential 9.1 18.8 52.1 118.4 230.8
Technical Potential 17.1 33.9 83.7 168.4 293.2
Cumulative Savings (aMW)
Achievable Potential 0.9 1.8 5.1 11.6 22.7
Economic Potential 1.0 2.1 5.9 13.5 26.3
Technical Potential 1.9 3.9 9.6 19.2 33.5
Avista Conservation Potential – Industrial
From 2016 to 2025,
cumulative achievable
potential savings are 102
GWh, or 11.6 aMW.

Achievable potential in
2025 is about 86% of
economic potential.

Washington and Idaho combined
2015 Electric IRP Appendix A
433
25
Energy savings by end use
Avista Industrial Savings Potential – WA & ID
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017
Cumulative
Energy Savings
(MWh)
% of
Total
Fan System - Optimization and Improvements 4,524 28.3%
Motors - Variable Frequency Drive (Pumps) 3,020 18.9%
Motors - Variable Frequency Drive (Fans & Blowers) 1,505 9.4%
Compressed Air - Air Usage Reduction 1,247 7.8%
Pumping System - Optimization and Improvements 893 5.6%
Interior Lighting - Occupancy Sensors 703 4.4%
Interior Lighting - High-Bay Fixtures 420 2.6%
Fan System - Maintenance 414 2.6%
Interior Lighting - Screw-in/Hard-wire LED 403 2.5%
Motors - Variable Frequency Drive (Compressed Air) 399 2.5%
Total Top 10 Measures 13,528 84.5%
2015 Electric IRP Appendix A
434
26
Avista Industrial Savings Potential – WA & ID
Cumulative achievable energy savings potential over time
% of Cumulative Achievable Potential Cumulative Achievable Potential (GWh)
2015 Electric IRP Appendix A
435
27
AEG Consistency with Council Methodology
• End-use model — bottom-up
•Building characteristics, fuel and equipment saturations
•Stock accounting based on measure life
•Codes and standards that have been enacted are included in baseline
•Lost- and non-lost opportunities treated differently
• Measures – comprehensive list
•RTF measure workbooks
•AEG databases, which draw upon same sources used by RTF
• Economic potential, total resource cost (TRC) test
•Considers HVAC interactions, non-energy benefits
•Avoided costs include 10% credit based on Conservation Act
• Achievable potential – ramp rates
•Based on Sixth Plan ramps rates, but modified to reflect Avista’s program history

2015 Electric IRP Appendix A
436
Summary of Conservation Potential
Across All Sectors – Sensitivity Case
2015 Electric IRP Appendix A
437
29
Sensitivity Case
• Ran another version of the model to see which measures were on the edge of
passing the TRC
•Set the TRC threshold to 0.7
• The biggest impact was in the commercial sector
• The measures that pass at the 0.7 level, but not the 1.0 level include:
•ENERGY STAR Homes
•Weatherization in more segments
•Commercial faucet aerators and low flow nozzles
•LED light bulbs pass in more segments
•Industrial compressed air replacements

2015 Electric IRP Appendix A
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30
Avista Conservation Potential – All Sectors
The case with TRC=0.7 provides more savings since more measures pass
the economic screen. With the lower TRC, there is an additional 0.5 aMW
in 2016 and an additional 10.7 aMW in 2025.
•The biggest increase in savings is in the commercial sector with the
addition of linear LED light bulbs, faucet aerators and additional screw-
in LED light bulbs.

Washington and Idaho combined
2015 Electric IRP Appendix A
439
Bridget Kester
[e-mail]

Fuong Nguyen
[e-mail]

Sharon Yoshida
[e-mail]

Ingrid Rohmund
[e-mail]

Thank You!
2015 Electric IRP Appendix A
440
Supplemental Slides:
Base-year market profiles,
baseline projection and
sector-level peak-demand savings
2015 Electric IRP Appendix A
441
33
WA Residential Market Profile, 2013

Annual Intensity for Average Household
Segment % of Sales
Single Family 129,893 1,783 70% 13,726
Multi Family 11,964 99 4% 8,236
Mobile Home 7,691 95 4% 12,354
Low Income 64,092 570 22% 8,892
213,640 2,546 100% 11,919
% of Use by End Use, All Homes
2015 Electric IRP Appendix A
442
34
ID Residential Market Profile, 2013

Annual Intensity for Average Household
Segment % of Sales
Single Family 65,329 843 70% 12,902
Multi Family 5,265 41 3% 7,733
Mobile Home 4,835 56 5% 11,599
Low Income 32,020 267 22% 8,349
107,449 1,207 100% 11,233
% of Use by End Use, All Homes
2015 Electric IRP Appendix A
443
35
WA Residential Market Profile, 2013
The technology detail behind the end-use profiles


e
eeUECSatNEnergy )(
Market profiles characterize how
customers use electricity in the base
year (2013)

Basic Equation:

where
Energy = annual energy use
e = equipment technology
N = number of homes
Sate = saturation of homes with the equipment
UECe = unit energy consumption in homes with the
equipment
Average Market Profiles - Electricity
End Use Technology Saturation UEC Intensity Usage
(kWh) (kWh/HH) (GWh)
Cooling Central AC 36.9% 1,249 461 98
Cooling Room AC 26.4% 402 106 23
Cooling Air-Source Heat Pump 6.5% 1,268 82 17
Cooling Geothermal Heat Pump 0.2% 1,326 2 0
Cooling Evaporative AC 1.2% 809 10 2
Space Heating Electric Room Heat 24.3% 5,302 1,288 275
Space Heating Electric Furnace 13.4% 9,021 1,213 259
Space Heating Air-Source Heat Pump 6.5% 10,487 677 145
Space Heating Geothermal Heat Pump 0.2% 5,564 10 2
Water Heating Water Heater (<= 55 Gal) 50.9% 3,025 1,539 329
Water Heating Water Heater (55 to 75 Gal) 6.5% 3,145 203 43
Water Heating Water Heater (> 75 Gal) 0.3% 4,209 12 3
Interior Lighting Screw-in/Hard-wire 100.0% 955 955 204
Interior Lighting Linear Fluorescent 100.0% 114 114 24
Interior Lighting Specialty Lighting 100.0% 286 286 61
Exterior Lighting Screw-in/Hard-wire 100.0% 289 289 62
Appliances Clothes Washer 91.8% 104 95 20
Appliances Clothes Dryer 49.9% 738 368 79
Appliances Dishwasher 77.1% 447 345 74
Appliances Refrigerator 100.0% 829 829 177
Appliances Freezer 55.3% 669 370 79
Appliances Second Refrigerator 20.7% 1,010 209 45
Appliances Stove 70.3% 453 318 68
Appliances Microwave 94.8% 139 132 28
Electronics Personal Computers 64.3% 214 138 29
Electronics Monitor 78.6% 91 71 15
Electronics Laptops 76.3% 57 43 9
Electronics TVs 177.4% 255 452 97
Electronics Printer/Fax/Copier 72.6% 65 47 10
Electronics Set top Boxes/DVRs 143.9% 128 184 39
Electronics Devices and Gadgets 100.0% 54 54 11
Miscellaneous Pool Pump 1.9% 2,514 49 10
Miscellaneous Pool Heater 0.5% 4,025 19 4
Miscellaneous Furnace Fan 58.7% 249 146 31
Miscellaneous Well pump 9.3% 642 60 13
Miscellaneous Miscellaneous 100.0% 744 744 159
Total 11,919 2,546
2015 Electric IRP Appendix A
444
36
ID Residential Market Profile, 2013
The technology detail behind the end-use profiles


e
eeUECSatNEnergy )(
Market profiles characterize how
customers use electricity in the base
year (2013)

Basic Equation:

where
Energy = annual energy use
e = equipment technology
N = number of homes
Sate = saturation of homes with the equipment
UECe = unit energy consumption in homes with the
equipment
Average Market Profiles - Electricity
End Use Technology Saturation UEC Intensity Usage
(kWh) (kWh/HH) (GWh)
Cooling Central AC 33.4% 1,134 379 41
Cooling Room AC 18.6% 416 77 8
Cooling Air-Source Heat Pump 5.3% 1,282 68 7
Cooling Geothermal Heat Pump 0.0% 0 0 0
Cooling Evaporative AC 1.5% 777 12 1
Space Heating Electric Room Heat 24.2% 6,354 1,540 165
Space Heating Electric Furnace 13.1% 8,904 1,168 126
Space Heating Air-Source Heat Pump 5.3% 10,465 557 60
Space Heating Geothermal Heat Pump 0.0% 0 0 0
Water Heating Water Heater (<= 55 Gal) 49.2% 2,904 1,429 154
Water Heating Water Heater (55 to 75 Gal) 6.2% 3,025 189 20
Water Heating Water Heater (> 75 Gal) 0.3% 3,847 11 1
Interior Lighting Screw-in/Hard-wire 100.0% 1,041 1,041 112
Interior Lighting Linear Fluorescent 100.0% 129 129 14
Interior Lighting Specialty Lighting 100.0% 243 243 26
Exterior Lighting Screw-in/Hard-wire 100.0% 323 323 35
Appliances Clothes Washer 85.1% 99 84 9
Appliances Clothes Dryer 60.3% 754 454 49
Appliances Dishwasher 77.6% 424 329 35
Appliances Refrigerator 100.0% 789 789 85
Appliances Freezer 52.3% 643 337 36
Appliances Second Refrigerator 21.1% 945 199 21
Appliances Stove 63.6% 433 275 30
Appliances Microwave 91.2% 132 120 13
Electronics Personal Computers 56.9% 200 114 12
Electronics Monitor 69.6% 85 59 6
Electronics Laptops 79.3% 53 42 5
Electronics TVs 174.6% 248 434 47
Electronics Printer/Fax/Copier 66.7% 61 41 4
Electronics Set top Boxes/DVRs 92.5% 120 111 12
Electronics Devices and Gadgets 100.0% 51 51 5
Miscellaneous Pool Pump 1.6% 2,342 38 4
Miscellaneous Pool Heater 0.4% 3,750 15 2
Miscellaneous Furnace Fan 59.7% 239 142 15
Miscellaneous Well pump 12.5% 598 75 8
Miscellaneous Miscellaneous 100.0% 356 356 38
Total 11,233 1,207
2015 Electric IRP Appendix A
445
37
WA Commercial Market Characterization, 2013

Segment Electricity Sales
(GWh)
% of Total
Usage
Floor Space
(Million Sq. Ft.)
Intensity
(Annual
kWh/SqFt)
Peak Demand
(MW)
Small Office 280 13% 18.1 15.4 71
Large Office 106 5% 6.0 17.5 16
Restaurant 70 3% 1.7 42.4 11
Retail 285 14% 20.7 13.8 59
Grocery 209 10% 4.4 47.3 33
College 78 4% 5.6 13.9 13
School 117 6% 11.9 9.9 5
Hospital 271 13% 9.3 29.1 41
Lodging 112 5% 7.0 16.1 14
Warehouse 103 5% 13.7 7.5 12
Miscellaneous 455 22% 33.1 13.8 93
Total 2,086 100% 132 15.9 368
2015 Electric IRP Appendix A
446
38
ID Commercial Market Characterization, 2013

Segment Electricity Sales
(GWh)
% of Total
Usage
Floor Space
(Million Sq. Ft.)
Intensity
(Annual
kWh/SqFt)
Peak Demand
(MW)
Small Office 134 14% 8.7 15.4 35
Large Office 17 2% 1.0 17.5 3
Restaurant 12 1% 0.3 42.4 2
Retail 168 17% 12.1 13.8 35
Grocery 92 9% 1.9 47.3 14
College 73 7% 5.2 13.9 12
School 109 11% 11.1 9.9 4
Hospital 106 11% 3.6 29.1 16
Lodging 49 5% 3.0 16.1 6
Warehouse 47 5% 6.3 7.5 5
Miscellaneous 168 17% 12.2 13.8 34
Total 976 100% 66 14.9 167
2015 Electric IRP Appendix A
447
39
WA Commercial Market Profile, 2013
The technology detail behind the end-use profiles


e
eeUECSatNEnergy )(
Electric Market Profiles
End Use Technology Saturation EUI Intensity Usage
(kWh) (kWh/Sqft) (GWh)
Cooling Air-Cooled Chiller 10.3% 3.38 0.35 46.0
Cooling Water-Cooled Chiller 12.3% 5.11 0.63 83.0
Cooling RTU 37.5% 3.27 1.22 161.1
Cooling Room AC 4.6% 2.93 0.13 17.5
Cooling Air-Source Heat Pump 5.6% 3.01 0.17 22.1
Cooling Geothermal Heat Pump 1.8% 1.85 0.03 4.4
Heating Electric Furnace 12.7% 6.72 0.86 112.5
Heating Electric Room Heat 7.6% 7.69 0.58 76.9
Heating Air-Source Heat Pump 5.6% 5.87 0.33 43.1
Heating Geothermal Heat Pump 1.8% 4.30 0.08 10.1
Ventilation Ventilation 100.0% 1.59 1.59 209.2
Water Heating Water Heater 53.1% 1.69 0.90 118.2
Interior Lighting Screw-in/Hard-wire 100.0% 0.92 0.92 121.3
Interior Lighting High-Bay Fixtures 100.0% 0.51 0.51 67.3
Interior Lighting Linear Fluorescent 100.0% 2.17 2.17 285.8
Exterior Lighting Screw-in/Hard-wire 100.0% 0.23 0.23 30.0
Exterior Lighting HID 100.0% 0.64 0.64 83.8
Exterior Lighting Linear Fluorescent 100.0% 0.35 0.35 46.4
Refrigeration Walk-in Refrigerator/Freezer 8.8% 1.81 0.16 21.1
Refrigeration Reach-in Refrigerator/Freezer 12.1% 0.29 0.04 4.6
Refrigeration Glass Door Display 15.6% 0.98 0.15 20.1
Refrigeration Open Display Case 7.7% 9.75 0.76 99.3
Refrigeration Icemaker 29.6% 0.54 0.16 21.2
Refrigeration Vending Machine 20.2% 0.33 0.07 8.9
Food Preparation Oven 15.5% 0.92 0.14 18.8
Food Preparation Fryer 3.3% 2.63 0.09 11.4
Food Preparation Dishwasher 16.8% 1.68 0.28 37.2
Food Preparation Steamer 3.3% 2.23 0.07 9.6
Food Preparation Hot Food Container 6.4% 0.32 0.02 2.7
Office Equipment Desktop Computer 100.0% 0.62 0.62 82.2
Office Equipment Laptop 98.8% 0.08 0.08 10.9
Office Equipment Server 86.8% 0.20 0.17 22.9
Office Equipment Monitor 100.0% 0.11 0.11 14.5
Office Equipment Printer/Copier/Fax 100.0% 0.08 0.08 9.9
Office Equipment POS Terminal 57.7% 0.05 0.03 4.0
Miscellaneous Non-HVAC Motors 53.0% 0.19 0.10 13.2
Miscellaneous Pool Pump 5.8% 0.02 0.00 0.2
Miscellaneous Pool Heater 1.8% 0.03 0.00 0.1
Miscellaneous Other Miscellaneous 100.0% 1.03 1.03 135.1
Total 15.86 2,086.3
Market profiles characterize how
customers use electricity in the base
year (2013)

Basic Equation:

where
Energy = annual energy use
e = equipment technology
N = total floor space in sq. ft.
Sate = saturation of sq. ft. with the equipment
UECe = unit energy consumption for square footage
with the equipment
2015 Electric IRP Appendix A
448
40
ID Commercial Market Profile, 2013
The technology detail behind the end-use profiles


e
eeUECSatNEnergy )(
Market profiles characterize how
customers use electricity in the base
year (2013)

Basic Equation:

where
Energy = annual energy use
e = equipment technology
N = total floor space in sq. ft.
Sate = saturation of sq. ft. with the equipment
UECe = unit energy consumption for square footage
with the equipment
Electric Market Profiles
End Use Technology Saturation EUI Intensity Usage
(kWh) (kWh/Sqft) (GWh)
Cooling Air-Cooled Chiller 12.4% 3.24 0.40 26.4
Cooling Water-Cooled Chiller 10.2% 5.15 0.53 34.6
Cooling RTU 35.6% 3.17 1.13 74.0
Cooling Room AC 4.6% 2.77 0.13 8.4
Cooling Air-Source Heat Pump 5.6% 2.81 0.16 10.2
Cooling Geothermal Heat Pump 1.8% 1.68 0.03 2.0
Heating Electric Furnace 11.5% 6.74 0.77 50.7
Heating Electric Room Heat 7.6% 7.76 0.59 38.9
Heating Air-Source Heat Pump 5.6% 5.91 0.33 21.5
Heating Geothermal Heat Pump 1.8% 4.41 0.08 5.2
Ventilation Ventilation 100.0% 1.46 1.46 95.5
Water Heating Water Heater 51.4% 1.58 0.81 53.2
Interior Lighting Screw-in/Hard-wire 100.0% 0.88 0.88 57.5
Interior Lighting High-Bay Fixtures 100.0% 0.51 0.51 33.3
Interior Lighting Linear Fluorescent 100.0% 2.11 2.11 138.8
Exterior Lighting Screw-in/Hard-wire 100.0% 0.20 0.20 13.1
Exterior Lighting HID 100.0% 0.60 0.60 39.1
Exterior Lighting Linear Fluorescent 100.0% 0.47 0.47 30.7
Refrigeration Walk-in Refrigerator/Freezer 8.8% 1.30 0.11 7.5
Refrigeration Reach-in Refrigerator/Freezer 13.4% 0.26 0.04 2.3
Refrigeration Glass Door Display 15.4% 0.85 0.13 8.6
Refrigeration Open Display Case 8.4% 7.98 0.67 44.1
Refrigeration Icemaker 31.6% 0.48 0.15 10.0
Refrigeration Vending Machine 20.0% 0.32 0.06 4.1
Food Preparation Oven 16.2% 0.86 0.14 9.1
Food Preparation Fryer 3.1% 2.15 0.07 4.3
Food Preparation Dishwasher 16.1% 1.49 0.24 15.7
Food Preparation Steamer 3.1% 1.99 0.06 4.0
Food Preparation Hot Food Container 7.4% 0.25 0.02 1.2
Office Equipment Desktop Computer 100.0% 0.58 0.58 37.7
Office Equipment Laptop 98.9% 0.07 0.07 4.7
Office Equipment Server 89.1% 0.18 0.16 10.7
Office Equipment Monitor 100.0% 0.10 0.10 6.7
Office Equipment Printer/Copier/Fax 100.0% 0.07 0.07 4.7
Office Equipment POS Terminal 57.6% 0.05 0.03 1.8
Miscellaneous Non-HVAC Motors 51.6% 0.17 0.09 5.8
Miscellaneous Pool Pump 5.7% 0.02 0.00 0.1
Miscellaneous Pool Heater 1.7% 0.03 0.00 0.0
Miscellaneous Other Miscellaneous 100.0% 0.91 0.91 59.5
Total 14.87 975.5
2015 Electric IRP Appendix A
449
41
WA Commercial Market Profile, 2013

Annual Intensity by Building Type and End Use
Base Year Sales by End Use
2015 Electric IRP Appendix A
450
42
ID Commercial Market Profile, 2013

Annual Intensity by Building Type and End Use
Base Year Sales by End Use
2015 Electric IRP Appendix A
451
43
WA Industrial Market Profile, 2013
The technology detail behind the end-use profiles

Average Market Profiles
End Use Technology Usage Intensity
(GWh) (kWh/Employee)
Cooling Air-Cooled Chiller 17.4 1,072
Cooling Water-Cooled Chiller 2.2 137
Cooling RTU 22.4 1,383
Cooling Room AC 1.5 94
Cooling Air-Source Heat Pump 2.1 130
Cooling Geothermal Heat Pump 0.0 0
Heating Electric Furnace 12.5 769
Heating Electric Room Heat 4.2 258
Heating Air-Source Heat Pump 3.1 189
Heating Geothermal Heat Pump 0.0 0
Ventilation Ventilation 19.3 1,190
Interior Lighting Screw-in/Hard-wire 4.9 302
Interior Lighting High-Bay Fixtures 20.4 1,256
Interior Lighting Linear Fluorescent 23.8 1,466
Exterior Lighting Screw-in/Hard-wire 3.9 238
Exterior Lighting HID 3.2 196
Exterior Lighting Linear Fluorescent 3.2 198
Motors Pumps 86.8 5,352
Motors Fans & Blowers 68.0 4,189
Motors Compressed Air 54.3 3,345
Motors Conveyors 245.0 15,101
Motors Other Motors 38.0 2,341
Process Process Heating 99.2 6,115
Process Process Cooling 32.5 2,005
Process Process Refrigeration 32.5 2,005
Process Process Electro-Chemical 64.5 3,972
Process Process Other 21.8 1,345
Miscellaneous Miscellaneous 35.6 2,197
Total 922.3 56,846
2015 Electric IRP Appendix A
452
44
ID Industrial Market Profile, 2013
The technology detail behind the end-use profiles

Average Market Profiles
End Use Technology Usage Intensity
(GWh) (kWh/Employee)
Cooling Air-Cooled Chiller 6.5 734
Cooling Water-Cooled Chiller 0.8 94
Cooling RTU 8.4 947
Cooling Room AC 0.6 64
Cooling Air-Source Heat Pump 0.8 89
Cooling Geothermal Heat Pump 0.0 0
Heating Electric Furnace 4.6 516
Heating Electric Room Heat 1.5 173
Heating Air-Source Heat Pump 1.1 127
Heating Geothermal Heat Pump 0.0 0
Ventilation Ventilation 7.2 807
Interior Lighting Screw-in/Hard-wire 1.8 205
Interior Lighting High-Bay Fixtures 7.6 854
Interior Lighting Linear Fluorescent 8.8 997
Exterior Lighting Screw-in/Hard-wire 1.4 162
Exterior Lighting HID 1.2 134
Exterior Lighting Linear Fluorescent 1.2 134
Motors Pumps 32.3 3,640
Motors Fans & Blowers 25.3 2,850
Motors Compressed Air 20.2 2,275
Motors Conveyors 91.1 10,272
Motors Other Motors 14.1 1,593
Process Process Heating 36.9 4,159
Process Process Cooling 12.1 1,364
Process Process Refrigeration 12.1 1,364
Process Process Electro-Chemical 24.0 2,702
Process Process Other 8.1 915
Miscellaneous Miscellaneous 13.3 1,494
Total 343.0 38,668
2015 Electric IRP Appendix A
453
Sector-level Potential Savings -
Washington
2015 Electric IRP Appendix A
454
46
2016 2017 2020 2025 2035
Cumulative WA Savings (GWh)
Achievable Potential 8.5 19.3 56.2 110.7 181.1
Economic Potential 18.9 38.7 88.4 144.7 221.1
Technical Potential 55.2 110.0 261.0 469.4 721.3
Cumulative Savings (aMW)
Achievable Potential 1.0 2.2 6.4 12.6 20.7
Economic Potential 2.2 4.4 10.1 16.5 25.2
Technical Potential 6.3 12.6 29.8 53.6 82.3
Avista Conservation Potential – Residential
From 2015 to 2025,
cumulative achievable
potential savings are 111
GWh, or 12.6 aMW.

Achievable potential in
2025 is about 76% of
economic potential.

Washington
2015 Electric IRP Appendix A
455
47
Energy savings by end use
Avista Residential Savings Potential - Washington
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017
Cumulative
Energy Savings
(MWh)
% of
Total
Interior Lighting - Screw-in/Hard-wire LED and CFL 8,479 44.1%
Ducting - Repair and Sealing 3,483 18.1%
Exterior Lighting - Screw-in/Hard-wire CFL and LED 2,564 13.3%
Water Heater - Pipe Insulation 1,535 8.0%
Water Heater - Faucet Aerators 699 3.6%
Behavioral Programs 464 2.4%
Thermostat - Clock/Programmable 443 2.3%
Insulation - Ducting 429 2.2%
Water Heater - Low-Flow Showerheads 284 1.5%
Appliances – Freezer ENERGY STAR 177 0.9%
Total Top 10 Measures 18,578 96.4%
2015 Electric IRP Appendix A
456
48
2016 2017 2020 2025 2035
Cumulative WA Savings (GWh)
Achievable Potential 9.0 19.3 71.3 206.7 418.9
Economic Potential 19.9 40.6 116.4 268.4 493.8
Technical Potential 48.5 96.6 240.5 473.0 746.4
Cumulative Savings (aMW)
Achievable Potential 1.0 2.2 8.1 23.6 47.8
Economic Potential 2.3 4.6 13.3 30.6 56.4
Technical Potential 5.5 11.0 27.5 54.0 85.2
Avista Conservation Potential – Commercial
From 2015 to 2025,
cumulative achievable
potential savings are 207
GWh, or 23.6 aMW.

Achievable potential in
2025 is about 77% of
economic potential.

Washington
2015 Electric IRP Appendix A
457
49
Energy savings by end use
Avista Commercial Savings Potential - Washington
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017
Cumulativ
e Savings
(MWh)
% of Total
Interior Lighting - Linear LED 4,470 23.1%
Interior Lighting - Screw-in/Hard-wire CFL and LED 2,652 13.7%
Chiller - Chilled Water Reset 924 4.8%
HVAC - Duct Repair and Sealing 793 4.1%
Interior Lighting - High-Bay Fixtures T5 and LED 764 4.0%
Exterior Lighting - Linear LED 688 3.6%
Interior Lighting - Occupancy Sensors 678 3.5%
Interior Lighting - Skylights 561 2.9%
Exterior Lighting - Screw-in/Hard-wire CFL and LED 478 2.5%
Grocery - Open Display Case - Night Covers 459 2.4%
Total Top 10 Measures 12,467 64.5%
2015 Electric IRP Appendix A
458
50
2016 2017 2020 2025 2035
Cumulative WA Savings (GWh)
Achievable Potential 5.4 11.2 31.3 73.3 146.0
Economic Potential 6.3 13.1 36.8 85.5 169.3
Technical Potential 12.4 24.7 61.1 122.8 213.8
Cumulative Savings (aMW)
Achievable Potential 0.6 1.3 3.6 8.4 16.7
Economic Potential 0.7 1.5 4.2 9.8 19.3
Technical Potential 1.4 2.8 7.0 14.0 24.4
Avista Conservation Potential – Industrial
From 2016 to 2025,
cumulative achievable
potential savings are 73
GWh, or 8.4 aMW.

Achievable potential in
2025 is about 86% of
economic potential.

Washington
2015 Electric IRP Appendix A
459
51
Energy savings by end use
Avista Industrial Savings Potential - Washington
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017
Cumulative
Savings (MWh)
% of
Total
Fan System - Optimization and Improvements 3,298 29.5%
Motors - Variable Frequency Drive (Pumps) 2,206 19.8%
Motors - Variable Frequency Drive (Fans & Blowers) 1,098 9.8%
Compressed Air - Air Usage Reduction 911 8.2%
Pumping System - Optimization and Improvements 663 5.9%
Interior Lighting - Occupancy Sensors 520 4.7%
Motors - Variable Frequency Drive (Compressed Air) 377 3.4%
Interior Lighting - High-Bay Fixtures LED 306 2.7%
Interior Lighting - Screw-in/Hard-wire CFL and LED 294 2.6%
HVAC - Duct Repair and Sealing 264 2.4%
Total Top 10 Measures 9,938 89.0%
2015 Electric IRP Appendix A
460
Sector-level Potential Savings - Idaho
2015 Electric IRP Appendix A
461
53
2016 2017 2020 2025 2035
Cumulative ID Savings (GWh)
Achievable Potential 4.6 10.6 30.9 58.0 93.0
Economic Potential 10.4 21.4 48.3 74.7 112.8
Technical Potential 29.2 58.7 139.0 249.5 395.3
Cumulative Savings (aMW)
Achievable Potential 0.5 1.2 3.5 6.6 10.6
Economic Potential 1.2 2.4 5.5 8.5 12.9
Technical Potential 3.3 6.7 15.9 28.5 45.1
Avista Conservation Potential – Residential
From 2016 to 2025,
cumulative achievable
potential savings are 58
GWh, or 6.6 aMW.

Achievable potential in
2025 is about 76% of
economic potential.

Idaho
2015 Electric IRP Appendix A
462
54
Energy savings by end use
Avista Residential Savings Potential - Idaho
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017
Cumulative
Energy
Savings
(MWh)
% of
Total
Interior Lighting - Screw-in/Hard-wire LED and CFL 5,137 48.5%
Exterior Lighting - Screw-in/Hard-wire LED and CFL 1,588 15.0%
Ducting - Repair and Sealing 1,574 14.9%
Water Heater - Pipe Insulation 729 6.9%
Water Heater - Faucet Aerators 337 3.2%
Thermostat - Clock/Programmable 231 2.2%
Behavioral Programs 225 2.1%
Insulation - Ducting 193 1.8%
Water Heater - Low-Flow Showerheads 135 1.3%
Appliances – Freezer ENERGY STAR 95 0.9%
Total Top 10 Measures 10,243 96.8%
2015 Electric IRP Appendix A
463
55
2016 2017 2020 2025 2035
Cumulative ID Savings (GWh)
Achievable Potential 4.2 9.0 33.4 97.7 198.4
Economic Potential 9.3 19.1 54.6 126.9 233.9
Technical Potential 22.7 45.1 112.3 221.2 349.5
Cumulative Savings (aMW)
Achievable Potential 0.5 1.0 3.8 11.2 22.6
Economic Potential 1.1 2.2 6.2 14.5 26.7
Technical Potential 2.6 5.2 12.8 25.3 39.9
Avista Conservation Potential – Commercial
From 2015 to 2025,
cumulative achievable
potential savings are 98
GWh, or 11.2 aMW.

Achievable potential in
2025 is about 77% of
economic potential.

Idaho
2015 Electric IRP Appendix A
464
56
Energy savings by end use
Avista Commercial Savings Potential - Idaho
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017
Cumulative
Savings
(MWh)
% of Total
Interior Lighting - Linear LED 2,134 23.9%
Interior Lighting - Screw-in/Hard-wire LED and T5 1,237 13.8%
Exterior Lighting - Linear LED 448 5.0%
Chiller - Chilled Water Reset 437 4.9%
Interior Lighting - High-Bay Fixtures LED 366 4.1%
Interior Lighting - Occupancy Sensors 297 3.3%
HVAC - Duct Repair and Sealing 275 3.1%
Interior Lighting - Skylights 270 3.0%
Exterior Lighting - Screw-in/Hard-wire CFL and LED 224 2.5%
Exterior Lighting – HID T5 and LED 217 2.4%
Total Top 10 Measures 5,905 65.4%
2015 Electric IRP Appendix A
465
57
2016 2017 2020 2025 2035
Cumulative ID Savings (GWh)
Achievable Potential 2.4 4.8 13.0 28.2 53.0
Economic Potential 2.8 5.7 15.3 32.9 61.5
Technical Potential 4.6 9.2 22.7 45.6 79.4
Cumulative Savings (aMW)
Achievable Potential 0.3 0.6 1.5 3.2 6.0
Economic Potential 0.3 0.6 1.7 3.8 7.0
Technical Potential 0.5 1.0 2.6 5.2 9.1
Avista Conservation Potential – Industrial
From 2015 to 2025,
cumulative achievable
potential savings are 28
GWh, or 3.2 aMW.

Achievable potential in
2025 is about 85% of
economic potential.

Idaho
2015 Electric IRP Appendix A
466
58
Energy savings by end use
Avista Industrial Savings Potential - Idaho
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017
Cumulative
Savings (MWh)
% of
Total
Fan System - Optimization and Improvements 1,226 25.4%
Motors - Variable Frequency Drive (Pumps) 814 16.8%
Fan System - Maintenance 414 8.6%
Motors - Variable Frequency Drive (Fans & Blowers) 407 8.4%
Compressed Air - Air Usage Reduction 336 7.0%
Compressed Air - System Optimization and
Improvements 271 5.6%
Pumping System - Optimization and Improvements 230 4.8%
Interior Lighting - Occupancy Sensors 183 3.8%
Interior Lighting - High-Bay Fixtures LED 114 2.4%
Motors - Variable Frequency Drive (Other) 110 2.3%
Total Top 10 Measures 4,104 84.9%
2015 Electric IRP Appendix A
467
Summary of Conservation Potential
– Sensitivity Case
2015 Electric IRP Appendix A
468
60
2016 2017 2020 2025 2035
Cumulative WA and ID Savings (GWh)
Achievable Potential 13.6 31.0 97.5 201.5 368.8
Economic Potential 30.7 63.5 171.4 311.2 517.2
Technical Potential 84.5 168.7 400.1 718.9 1,116.7
Cumulative Savings (aMW)
Achievable Potential 1.5 3.5 11.1 23.0 42.1
Economic Potential 3.5 7.2 19.6 35.5 59.0
Technical Potential 9.6 19.3 45.7 82.1 127.5
Avista Conservation Potential – Residential
From 2016 to 2025,
cumulative achievable
potential savings are 201
GWh, or 23.0 aMW.

An additional 3.7 aMW is
possible by 2025, compared
to the TRC=1.0 case.

Washington and Idaho combined
2015 Electric IRP Appendix A
469
61
2016 2017 2020 2025 2035
Cumulative WA and ID Savings (GWh)
Achievable Potential 15.3 35.5 128.8 356.1 708.8
Economic Potential 32.7 72.0 208.5 470.5 839.8
Technical Potential 71.2 141.7 352.8 694.2 1,095.9
Cumulative Savings (aMW)
Achievable Potential 1.7 4.1 14.7 40.7 80.9
Economic Potential 3.7 8.2 23.8 53.7 95.9
Technical Potential 8.1 16.2 40.3 79.2 125.1
Avista Conservation Potential – Commercial
From 2016 to 2025,
cumulative achievable
potential savings are 356
GWh, or 40.7 aMW.

An additional 6.0 aMW is
possible by 2025, compared
to the TRC=1.0 case.

Washington and Idaho combined
2015 Electric IRP Appendix A
470
62
2016 2017 2020 2025 2035
Cumulative WA and ID Savings (GWh)
Achievable Potential 9.9 19.9 53.0 110.9 209.5
Economic Potential 11.6 23.4 62.3 129.4 242.9
Technical Potential 17.1 33.9 83.7 168.4 293.2
Cumulative Savings (aMW)
Achievable Potential 1.1 2.3 6.0 12.7 23.9
Economic Potential 1.3 2.7 7.1 14.8 27.7
Technical Potential 1.9 3.9 9.6 19.2 33.5
Avista Conservation Potential – Industrial
From 2016 to 2025,
cumulative achievable
potential savings are 111
GWh, or 12.7 aMW.

An additional 1.1 aMW is
possible by 2025, compared
to the TRC=1.0 case.

Washington and Idaho combined
2015 Electric IRP Appendix A
471
63
Avista Residential Savings Potential – WA & ID
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017 Cumulative
Energy Savings
(MWh)
% of
Total
Interior Lighting - Screw-in/Hard-wire (LED) 13,616 43.9%
Ducting - Repair and Sealing 5,057 16.3%
Exterior Lighting - Screw-in/Hard-wire 4,152 13.4%
Water Heater - Pipe Insulation 2,264 7.3%
Water Heater - Faucet Aerators 1,037 3.3%
Thermostat - Clock/Programmable 726 2.3%
Behavioral Programs 689 2.2%
Insulation - Ducting 630 2.0%
ENERGY STAR Homes 606 2.0%
Total 28,777 92.7%
• Programmable
thermostats passed in the
multi-family segments,
moving it up in the
rankings
• Insulation – ducting
passed in the multi-family
segment, increasing the
savings
• ENERGY STAR Homes
did not pass the TRC at
the 1.0 level in any
segment

2015 Electric IRP Appendix A
472
64
Avista Commercial Savings Potential – WA & ID
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017
Cumulative
Energy Savings
(MWh)
% of
Total
Interior Lighting - Linear LED 6,604 18.6%
Interior Lighting - Screw-in/Hard-wire LED and CFL 3,923 11.0%
Interior Lighting - Occupancy Sensors 3,211 9.0%
Chiller - Chilled Water Reset 1,360 3.8%
Interior Lighting - High-Bay Fixtures T5 and LED 1,205 3.4%
Exterior Lighting - Linear LED 1,135 3.2%
HVAC - Duct Repair and Sealing 1,068 3.0%
Water Heater - Faucet Aerators/Low Flow Nozzles 917 2.6%
Interior Lighting - Skylights 831 2.3%
Exterior Lighting – HID T5 and LED 820 2.3%
Total Top 10 Measures 21,075 59.3%
• Interior lighting – screw-in
includes more LED in
more segments
• Occupancy sensors pass
in more segments
• High Bay fixtures pass in
more segments
• Faucet aerators and Low
flow nozzles did not pass
when the TRC threshold
was 1.0
• Exterior lighting includes
more LED

2015 Electric IRP Appendix A
473
65
Avista Industrial Savings Potential – WA & ID
Cumulative achievable potential in 2017
Top measures by energy savings
Measure / Technology
2017
Cumulative
Energy Savings
(MWh)
% of
Total
Fan System - Optimization and Improvements 4,524 22.8%
Motors - Variable Frequency Drive (Pumps) 3,020 15.2%
Fan System - Maintenance 1,635 8.2%
Motors - Variable Frequency Drive (Fans & Blowers) 1,505 7.6%
Compressed Air - Air Usage Reduction 1,247 6.3%
Compressed Air - Air Compressor Replacement 1,217 6.1%
Motors - Variable Frequency Drive (Compressed Air) 936 4.7%
Pumping System - Optimization and Improvements 891 4.5%
Interior Lighting - Occupancy Sensors 713 3.6%
Interior Lighting - High-Bay Fixtures 420 2.1%
Total Top 10 Measures 16,108 81%
• Fan system maintenance
savings increased
• Compressed air –
compressor replacement
did not pass when the
TRC threshold was 1.0
• Motors – Variable
Frequency Drives savings
increased

2015 Electric IRP Appendix A
474
Bridget Kester
[e-mail]

Fuong Nguyen
[e-mail]

Sharon Yoshida
[e-mail]

Ingrid Rohmund
[e-mail]

Thank You!
2015 Electric IRP Appendix A
475
2015 Preferred Resource Strategy &
Portfolio Analysis
James Gall
Fifth Technical Advisory Committee Meeting
May 19, 2015
DRAFT
2015 Electric IRP Appendix A
476
Introduction
• Discuss how Avista plans to meet resource
deficits (PRS)
• Review methodology and decision making logic
• Discuss alternative resource strategies
• Discuss the impact to resource strategies with a
different future than the Expected Case’s future
2 2015 Electric IRP Appendix A
477
2013 IRP Preferred Resource Strategy
Resource By the End
of Year
Nameplate
(MW)
Simple Cycle CT 2019 83
Simple Cycle CT 2023 83
Combined Cycle CT 2026 270
Simple Cycle CT 2027 83
Rathdrum CT Upgrade 2028 6
Simple Cycle CT 2032 50
Total 575
Energy Efficiency 2014-2033 164 aMW
Demand Response 2022-2027 19 MW
Distribution Efficiencies 2014-2017 <1 MW
3
Lancaster PPA
Wells/WNP-3
2015 Electric IRP Appendix A
478
Resource Requirements
• Since the last TAC meeting, the peak capacity need has
been pushed from 2020 to 2021.
• Avista signed a five year contract for five percent share
of the Chelan County PUD’s Rocky Reach and Rock
Island projects

0
500
1,000
1,500
2,000
2,500
3,000
20
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3
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3
5
Me
g
a
w
a
t
t
s
Loads & Resources-Winter Peak
Existing Resources Load w/ Conservation + Cont.
4 2015 Electric IRP Appendix A
479
Developing Resource Portfolios
• “1990 Methodology” Least Cost
– “Experts” package plausible resource portfolios
• Mixes of resource start dates, resource types
– Lowest cost is the goal
– No quantitative risk measurement
– Likely misses best portfolio and its timing
5
Portfolio Gas
Peaking
Gas
CCCT
Wind Solar Coal Market
1 Market Reliance 0 0 0 0 0 100
2 All Gas Peaking 100 0 0 0 0 0
3 All Gas 50 50 0 0 0 0
4 Gas & Wind 50 0 50 0 0 0
5 Balanced 20 2 20 0 20 20
6 High Renewables 25 0 50 25 0 0
7 All Renewables 0 0 75 25 0 0 2015 Electric IRP Appendix A
480
Developing Resource Portfolios, Cont.
• Hybrid Approach
– Continue arbitrary portfolio development
– Add stochastic analysis to measure risk
• Benefits
– Allows risk measurement
– Disqualifies portfolio outliers
– May show benefits of additional spending for risk reduction
• Costs
– May not select lowest cost portfolio for the level of risk
– Many best portfolios are missed
6 2015 Electric IRP Appendix A
481
Avista’s Portfolio Approach
• Best Practice- Efficient Frontier developed using a Mixed
Integer Program (MIP)
• Each portfolio is the least cost “best” portfolio for each
level of risk
• No need to build arbitrary portfolios
• Ensures the best portfolios are developed
• Allows for explicit and comprehensive measure of risk
vs. cost
• Still does not pick the “ideal” portfolio

Efficient Frontier Video
http://www.investopedia.com/terms/e/efficientfrontier.asp

7 2015 Electric IRP Appendix A
482
Avista’s Portfolio Approach, Cont.
• Mixed Integer Program (MIP)
– Lindo System’s What’s Best software using Gurobi solver
•Superior speed improvement allowing more complex modeling
– Solves for least cost mix to meet Avista’s resource shortfall
•NPV of power supply for next 25 years along with a small weighting of costs
beyond 25 years
– New generating resources, resource upgrades, conservation,
demand response all compete to meet the resource shortfall
•Options are treated as integers, therefore no partial units (including
conservation)
– Model can solve to reduce power supply risk by selecting
different resource strategies, while adhering to resource sizes
– Can still test “arbitrary” portfolios to illustrate concepts

8 2015 Electric IRP Appendix A
483
2015 IRP Efficient Frontier
9
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$350 $400 $450 $500
20
2
7

S
t
a
n
d
a
r
d

D
e
v
i
a
t
i
o
n

(
m
i
l
l
i
o
n
s
)
Levelized Power Supply Costs (Millions)
Efficient Frontier PRS
2015 Electric IRP Appendix A
484
Efficient Frontier as Percent Change from
Least Cost
10
-70%
-60%
-50%
-40%
-30%
-20%
-10%
0%
0%5%10%15%20%25%30%
20
2
7

S
t
a
n
d
a
r
d

D
e
v
i
a
t
i
o
n

(
%

C
h
a
g
n
e
)
Levelized Power Supply Costs (% Change)
Efficient Frontier PRS
2015 Electric IRP Appendix A
485
Selecting the “Best” Portfolio
• Using Avista’s methodology, all portfolios are
best for the assigned level of risk
• Academic research uses indifference curves
“risk tolerance” to help select the “best” portfolio
• Other metrics to help select the portfolio
– Risk adjusted PVRRs
– Point to point derivatives

11 2015 Electric IRP Appendix A
486
Risk Adjusted PVRR
• This metric adds to each year’s revenue requirement, five
percent of the added cost of the 95th percentile
– If expected cost was $100, the 95th percentile is $200, the cost
would be $105.
– Method simulates the added cost of a 1 in 20 bad outcome
• Methodology is useful in “hybrid” portfolio development as
it can distinguish between un-optimized portfolios
– A less useful measure in MIP-derived portfolios as model minimizes
this cost for each level of risk

12 2015 Electric IRP Appendix A
487
$0
$1,000
$2,000
$3,000
$4,000
$5,000
$6,000
Le
a
s
t

C
o
s
t
2 3
PR
S
4 5 6 7 8 9 10 11 12 13 14 15
Le
a
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R
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20

y
e
a
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r
i
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k

a
d
j
u
s
t
e
d

P
V
R
R

(
M
i
l
l
i
o
n
s
)
Efficient Frontier Porfolios
Risk Adjusted PVRR Results
Is the ~$40 million (0.9%) premium worth it?
13 2015 Electric IRP Appendix A
488
Point to Point Derivatives
• Distinguishes the relationship between added cost and
risk reduction
• Typically want good trade off, but each portfolio
manager’s judgment of the trade off is different
• Avista selects a portfolio where there is a good trade off
between cost and risk
• The measure used by Avista since 2005, when adopting
present method, to select a preferred resource portfolio
14 2015 Electric IRP Appendix A
489
-
1.00
2.00
3.00
4.00
5.00
6.00
Le
a
s
t

C
o
s
t
2 3 4 5 6 7 8 9 10 11 12 13 14 15
Le
a
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R
i
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k
Ef
f
i
c
i
e
n
t

F
r
o
n
t
i
e
r

S
l
o
p
e
Efficient Frontier Portfolios
Efficient Frontier Porfolio's Point to Point Slope
PR
S
Point to Point Derivatives
• Portfolio’s between
#3 and #4 vary the
size of the 2027
CCCT
15
An inflection point does not
necessarily mean it is the best
place to land, as the benefit
could be greatly outweighed by
the cost—this could be the
case in the 2015 IRP
-
2
4
6
8
10
12
14
16
Le
a
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t

C
o
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2 3 4 5 6 7 8 9 10 11 12 13 14 15
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m
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a
t
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v
e

E
f
f
i
c
i
e
n
t

F
r
o
n
t
i
e
r

S
l
o
p
e
Efficient Frontier Portfolios
Cumulative Efficient Frontier Porfolio's Point to Point Slope
PR
S
2015 Electric IRP Appendix A
490
2015 IRP: Preferred Resource Strategy
Resource By End of
Year
ISO
Conditions
(MW)
Winter
Capacity
(MW)
Energy
(aMW)
Natural Gas Peaker 2020 96 102 89
Thermal Upgrades 2021-2025 38 38 35
Combined Cycle CT 2026 286 306 265
Natural Gas Peaker 2027 96 102 89
Thermal Upgrades 2033 3 3 3
Natural Gas Peaker 2034 47 47 43
Total 565 597 524
Conservation (w/ T&D losses) 2016-2035 192 132
16 2015 Electric IRP Appendix A
491
Loads & Resources- Winter Peak
17
0
500
1,000
1,500
2,000
2,500
3,000
20
1
6
20
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20
1
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3
5
Me
g
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a
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t
s
Existing Resources Conservation
Combined Cycle Peaker
Wind Solar
Market Storage
Plant Upgrade Demand Response
Load w/o Conservation + Cont.
2015 Electric IRP Appendix A
492
Conservation Modeling
• Load forecast adjusted higher to evaluate portfolio without
conservation, grossed up using AEG’s CPA conservation level
• Conservation measures are considered as resource options
– ~2,500 programs below 130% of the avoided cost are included in
PRiSM
– Additional programs above 130% threshold are excluded
• PRiSM may chose conservation program or generation resource to
fill resource deficits
– PRiSM looks at the added energy, winter, and summer capacity for each
program compared to its cost and energy savings
– When valuing the energy savings, the Power Act 10% premium is
included
• Programs are either on/off. A program cannot start and end unless
its life cycle is complete
18 2015 Electric IRP Appendix A
493
Conservation Avoided Cost
• Energy: $38.38/ MWh (flat delivery) PLUS
• Capacity & Risk: $94.84/ kW-year (winter peak)
PLUS
• T&D Capacity: $12.30/ kW-year (winter peak)
PLUS
• T&D Losses: 6.1% PLUS
• Power Act Adder: 10% added to energy & loss
values
19 2015 Electric IRP Appendix A
494
Conservation Selection vs. CPA
with Losses
aMW 2016-2017 2016-2035
CPA 8.99 132.06
PRiSM 8.96 132.48 20
0
1
2
3
4
5
6
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8
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e
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M
e
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s
AEG Annual (aMW)
Annual Energy Savings (aMW)
2015 Electric IRP Appendix A
495
Utility Cost of Conservation
21
0
10
20
30
40
50
60
70
80
19
9
9
20
0
1
20
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3
20
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2
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1
20
3
3
20
3
5
Energy Savings (aMW)
Spending (millions $)
Levelized Cost ($/MWh)
2015 Electric IRP Appendix A
496
Integer vs. Linear Programing
• Linear programming allows all resource options to be
chosen in any increment subject to min and max
constraints
– For example, a Combined Cycle CT can be selected with a
capacity of 158.45 MW rather then the full 286 MW plant
• Integer programing holds resource options to specific
sizes. Integer programming models resources lumpy
rather then precise additions.
– Lumpy resource additions adds costs compared to perfect
resource acquisition
22 2015 Electric IRP Appendix A
497
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$350 $370 $390 $410 $430 $450 $470 $490 $510
20
2
7

S
t
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(
M
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s
)
Annual Levelized Portfolio Cost (Millions)
Expected Case- Efficient Frontier Integer
Expected Case- Efficient Frontier Linear
PRS- Linear
PRS- Integer
Mix Integer vs. Linear Programing
Acquiring “lumpy”
resources increases costs
23 2015 Electric IRP Appendix A
498
Other Resource Portfolios Along the
Frontier (Nameplate MW)
24
Portfolio NG Peaker NG CCCT Wind Solar
Demand
Response
Thermal
Upgrade
Hydro
Upgrade Conservation
Least Cost 527 - - - - 38 - 128
2 524 - - - - 41 - 135
3 239 286 - - - 38 - 128
PRS 239 286 - - - 41 - 132
4 143 341 - - - 38 - 138
5 189 341 50 10 - 41 - 139
6 140 341 100 20 - 41 - 143
7 189 341 200 - - 38 - 141
8 140 341 250 20 - 41 - 142
9 186 341 300 70 - 38 - 141
10 186 341 400 30 - 38 - 141
11 140 341 450 80 - 38 - 144
12 140 341 500 150 - 41 - 142
13 186 341 500 290 - 38 - 143
14 93 627 500 270 - 38 - 140
15 93 627 500 480 - 38 - 141
Least Risk 186 683 500 600 - 23 - 144
2015 Electric IRP Appendix A
499
$0
$100
$200
$300
$400
$500
$600
$700
-
500
1,000
1,500
2,000
2,500
20
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-40

L
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C
o
s
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Me
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a
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a
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t
s
Efficient Frontier Portfolios (Integer vs.
Linear)
25
$0
$100
$200
$300
$400
$500
$600
$700
-
500
1,000
1,500
2,000
2,500
Le
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Portfolio
Hydro Upgrade Thermal Upgrade
Demand Response Solar
Wind NG Peaker
NG CCCT Conservation
2016-40 Levelized Cost
Linear shows
CCCT earlier
and
smoothed
resource
changes
Integer has
delayed
CCCT and
lumpy
resource
changes
2015 Electric IRP Appendix A
500
Portfolio Scenarios
• Load forecast
– Low, high, increases DG solar penetration
• Colstrip retires end of 2026
• High cost Colstrip Retention
– Colstrip retires end of 2022
• Market & Conservation
• 2013 PRS
• Renewables Meet All Load Growth
• Hydro Upgrades & Peakers
• Peakers & Hydro Total Portfolio

26 2015 Electric IRP Appendix A
501
Load Sensitivities
•Purpose: Describe changes in PRS with
alternative future load conditions
• Low Load
– Assumes lower GDP* growth (2.0%)
• High Load
– Assumes higher GDP* growth (3.2%)
• DG Solar Penetration
– Expected case forecast with DG solar penetration
growing exponentially to 10% of residential customers
with an 6 kW average system size by 2040
* Expected Case GDP forecast is ~2.6%
27 2015 Electric IRP Appendix A
502
Load Sensitivities (continued)
28 950
1,000
1,050
1,100
1,150
1,200
1,250
1,300
20
1
6
20
1
7
20
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Expected Case High Growth
Low Growth Rapid Rooftop Solar
1,500
1,600
1,700
1,800
1,900
2,000
2,100
20
1
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20
1
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20
1
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1
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s
Expected Case High Growth
Low Growth Rapid Rooftop Solar
1,500
1,600
1,700
1,800
1,900
2,000
2,100
20
1
6
20
1
7
20
1
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20
1
9
20
2
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20
2
1
20
2
2
20
2
3
20
2
4
20
2
5
20
2
6
20
2
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20
2
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20
2
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20
3
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20
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3
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20
3
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20
3
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20
3
5
Su
m
m
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P
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a
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M
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a
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s
Expected Case High Growth
Low Growth Rapid Rooftop Solar
2015 Electric IRP Appendix A
503
Load Sensitivity Resource Strategies
Resource Expected
Case PRS
Low Loads High Loads High DG Solar
Penetration
NG Peaker 239 192 335 239
NG Combined Cycle CT 286 286 286 286
Wind 0 0 0 0
Solar 0 0 0 0
Demand Response 0 0 0 0
Thermal Upgrades 41 41 41 41
Hydro Upgrades 0 0 0 0
Total 565 519 662 565
29 2015 Electric IRP Appendix A
504
SCENARIO: Colstrip Analysis
• Assumes Colstrip retires at the end of 2026
• No Selective Catalytic Reduction (SCR) investment
• Plant is fully depreciated by end of 2031
• Pond closure costs begin in 2027
• Replacement resources similar to Expected Case PRS

30 2015 Electric IRP Appendix A
505
$0
$20
$40
$60
$80
$100
$120
$350 $400 $450 $500 $550
20
2
7

S
t
d
e
v
Annual Levelized Portfolio Cost
Expected Case- Efficient Frontier Integer
PRS- Integer
Colstrip Retires 2026 Efficient Frontier
PRS- No Colstrip
SCENARIO: Colstrip Retires in 2026
31
25-year levelized cost increase of
$13.4 million (+ 4%) per year, risk
increase $12 million (+ 17%), the 2027
increase is $58 million
Resource By End
of Year
ISO
Conditions
(MW)
Natural Gas Peaker 2020 96
Thermal Upgrades 2021-2025 38
Combined Cycle
CTs 2026 627
Total 761
Conservation (w/
T&D losses)
2016-
2035 130.7
2015 Electric IRP Appendix A
506
Annual Power Supply Cost Impact After
Colstrip Closure in 2026
32
-$50
-$25
$0
$25
$50
$75
$100
$0
$100
$200
$300
$400
$500
$600
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
An
n
u
a
l

C
o
s
t

C
h
a
n
g
e

(
M
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l
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)
An
n
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a
l

P
o
w
e
r

S
u
p
p
l
y

C
o
s
t
s

(
M
i
l
l
i
o
n
s
)
Delta
PRS
PRS w/ Colstrip Retires 2026
Shorter Amortization
CAPEX shifted to O&M
SCR Savings
Replacement Capacity/ Pond Closure
2015 Electric IRP Appendix A
507
SCENARIO: High-Cost Colstrip Retention
• Higher-cost Colstrip compliance assumptions provided by TAC members
– Assumptions include:
•SO2 Scrubbers: $700 million (2022) w/ $45 million annual O&M
• Dry Ash Handling Conversion: $60 million (2022) w/ $3 million annual O&M
• Replacement Landfill: $9 million (2022) w/ $0.33 million annual O&M
• New SCR: $268 million (2022) w/ $35 million annual O&M
• Colstrip 1 & 2 retire in 2017, w/ common costs shifted to 3 & 4 owners
• Assumptions have not been vetted by Avista
• Two scenarios studied
– PRS with higher compliance costs
– Colstrip retirement at the end of 2022

33 2015 Electric IRP Appendix A
508
SCENARIO: Colstrip Retires 2022
Resource By End
of Year
ISO
Conditions
(MW)
Natural Gas Peaker 2020 56
Thermal Upgrades 2021-2035 41
Combined Cycle CTs 2023-2026 627
Natural Gas Peaker 2035 47
Total 770
Conservation (w/
T&D losses)
2016-
2035 131.0
• Early Colstrip retirement
scenario adds CCCT earlier in
the plan
• Peaker still required in 2020
– More detailed economics
could support bigger CCCT
in 2020 rather than splitting
between CCCT and a
peaker
34 2015 Electric IRP Appendix A
509
$0
$20
$40
$60
$80
$100
$120
$350 $400 $450 $500 $550
20
2
7

S
t
d
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v

(
M
i
l
l
i
o
n
s
)
Annual Levelized Portfolio Cost (Millions)
Colstrip Scenario Efficient Frontier Analysis
35
Expected
Case/
PRS
Higher Colstrip
Costs- Colstrip
Retires 2022
Higher
Colstrip
Cost/ PRS
2015 Electric IRP Appendix A
510
Colstrip Scenarios (Continued)
36
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
PRS 252 276 288 298 313 331 341 348 366 382 399 454 484 487 488 504 523 523 545 564
PRS High Colstrip Costs 252 276 290 301 320 347 373 389 404 414 425 477 507 510 511 528 547 546 568 588
PRS Colstrip Retires 2022 260 284 299 325 333 336 351 408 425 432 444 490 498 500 501 514 534 536 551 572
$0
$100
$200
$300
$400
$500
$600
An
n
u
a
l

P
o
w
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r

S
u
p
p
l
y

C
o
s
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s

(
M
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l
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s
)
20-yr Levelized
$374
$391
$395
2015 Electric IRP Appendix A
511
Colstrip Scenarios’ Greenhouse Gas
Emissions
37
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
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
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3
3
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3
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Me
t
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T
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PRS
Scenario: Colstrip Retires 2026
Scenario: Colstrip Retires 2022
2015 Electric IRP Appendix A
512
Other Resource Scenarios
•Market & Conservation
– All future needs are met by conservation and market purchases
•2013 PRS
– Build similar resources as the 2013 preferred resource strategy
•Renewables Meet All Load Growth
– All load growth is met by renewable energy (wind)
•Hydro Upgrades & Peakers
– Assumes Monroe Street & Long Lake upgrades in 2027
– Peaking resources meet remaining capacity needs
•Peakers & Hydro Total Portfolio
– By 2027 Avista retains only gas-fired peakers and hydro in its portfolio

38 2015 Electric IRP Appendix A
513
Other Portfolio Scenarios Efficient Frontier
Market &
Conservation
2013 PRS
Renewables Meet All Load Growth
Peakers & Hydro Total Portfolio
Colstrip Retires
2027
PRS
Hydro Upgrades & Peakers
$0
$20
$40
$60
$80
$100
$120
$350 $400 $450 $500 $550
20
2
7

S
t
d
e
v
Annual Levelized Portfolio Cost
39 2015 Electric IRP Appendix A
514
Other Portfolio Scenario Greenhouse
Emissions
40
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
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
Me
t
r
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T
o
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s

(
M
i
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)
PRS
Scenario: Colstrip Retires 2026
Scenario: Colstrip Retires 2022
Scenario: Market & Conservation Only
Scenario: 2013 IRP
Scenario: Peakers & Hydro Total Portfolio
Scenario: Renewables Meet All Load Growth
Scenario: Hydro Upgrades & Peakers
2015 Electric IRP Appendix A
515
$0
$20
$40
$60
$80
$100
$120
$350 $400 $450 $500 $550 $600
20
2
7

S
t
d
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v

(
m
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s
)
Annual Levelized Porfolio Cost (Millions)
Expected Case- Efficient Frontier
PRS (Expected Case)
Social Cost of Carbon Case- Efficient Frontier
PRS (Social Cost of Carbon)
Efficient Frontier w/ Social Carbon Cost
17% higher cost ($67 million/yr)
Risk up ~6% ($4 million)
41 2015 Electric IRP Appendix A
516
$0
$20
$40
$60
$80
$100
$120
$350 $400 $450 $500 $550 $600
20
2
7

S
t
d
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v

(
m
i
l
l
i
o
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s
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Annual Levelized Porfolio Cost (Millions)
Social Cost of Carbon Case- Efficient Frontier
PRS (Social Cost of Carbon)
Social Cost of Carbon Case- Efficient Frontier- Colstrip Retires 2026
Colstrip Retires PRS (Social Cost of Carbon)
Efficient Frontier w/ Social Carbon Cost
(Colstrip Retires 2026)
$6 million added each year
Risk up $12 million annually
42 2015 Electric IRP Appendix A
517
Avista Emissions with Social Cost of
Carbon Market Future
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
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
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3
3
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20
3
5
Me
t
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T
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s

(
M
i
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s
)
Expected Case (PRS)
Social Cost of Carbon (PRS)
Social Cost of Carbon (Colstrip Retires 2026)
43 2015 Electric IRP Appendix A
518
Social Cost of Carbon Summary
• Annual Power Supply Costs will increase approximately
$67 million per year (17%)
• Avista’s greenhouse gas emissions fall 17%
• Colstrip still remains lower cost option
• Retiring Colstrip in 2026 increases levelized costs by $6
million compared to $13 million per year in the Expected
Case
• Retiring Colstrip and a Social Cost of Carbon Market
Future reduces Avista’s greenhouse gas emissions 48%
44 2015 Electric IRP Appendix A
519

2015 Electric Integrated Resource Plan
Technical Advisory Committee Meeting No. 6 Agenda
Wednesday, June 24, 2015
Conference Room 130
Topic Time Staff
1. Introduction & TAC 5 Recap 8:30 Lyons

2. Avista Community Solar 8:35 Magalsky

3. 2015 Action Plan 9:15 Lyons

4. Final 2015 PRS 10:00 Gall

5. 2015 IRP Document Introduction 10:30 Staff

6. Lunch and Adjourn 11:30

2015 Electric IRP Appendix A
520
2015 Electric IRP
TAC Meeting Expectations and Schedule
John Lyons, Ph.D.
Sixth Technical Advisory Committee Meeting
June 24, 2015
2015 Electric IRP Appendix A
521
Technical Advisory Committee
• The public process of the IRP – input on what to study, how to study, and
review assumptions and results

• Technical forum with a range of participants with different areas of input
and expertise

• Open forum, but we need to stay on topic to get through the agenda and
allow all participants to ask questions and make comments

• Welcome requests for studies or different assumptions.
– Time or resources may limit the amount of studies
– The earlier study requests are made, the more accommodating we can be
– January 15, 2015 was the final date to receive study requests

• Action Items – areas for more research in the next IRP
2 2015 Electric IRP Appendix A
522
Technical Advisory Committee
• Technical forum on inputs and assumptions, not an advocacy forum
• Focus is on developing a resource strategy based on sound assumptions
and inputs, instead of a forum on a particular resource or resource type
• We request that everyone maintain a high level of respect and
professional demeanor to encourage an ongoing conversation about the
IRP process
• Supports rate recovery, but not a preapproval process
• Planning team is available by email or phone for questions or comments
between the TAC meetings
• Today is the final TAC meeting for the 2015 IRP.
• The TAC meetings for the 2017 IRP will start in the second quarter of
2016.

3 2015 Electric IRP Appendix A
523
TAC #5 Recap
• Introduction & TAC 4 Recap – Lyons
• Review of Market Futures – Gall
• Ancillary Services Valuation – Shane
• Conservation Potential Assessment – Kester (AEG)
• Draft 2015 PRS & Portfolio Analysis – Planning Staff

4 2015 Electric IRP Appendix A
524
Today’s Agenda
• Introduction & TAC 5 Recap (8:30) – Lyons
• Avista Community Solar (8:35) – Magalsky
• 2015 Action Plan (9:15) – Lyons
• Final 2015 PRS (10:00) – Gall
• 2015 IRP Document Introduction – Planning Group
• Lunch and Adjourn (11:30)
5 2015 Electric IRP Appendix A
525
Solar Overview

Kelly Magalsky
Sixth Technical Advisory Committee Meeting
June 24, 2015

2015 Electric IRP Appendix A
526
Concierge Model

Should I
install
solar?
www.avistautilities.com/solarestimator
2 2015 Electric IRP Appendix A
527
Solar Estimator
3 2015 Electric IRP Appendix A
528
Avista Community Solar Project
4 2015 Electric IRP Appendix A
529
Avista Community Solar Program
• Utility Owned 423 kW array (1,512 panels)
• Lottery to select customer/participants
• Expect 500 - 800 participants

• Site: Spokane Valley, WA
• Customer Enrollment: Now – July 17th

www.avistacommunitysolar.com or 1-800-923-9551 5 2015 Electric IRP Appendix A
530
2015 Electric IRP
Action Items
John Lyons, Ph.D.
Sixth Technical Advisory Committee Meeting
June 24, 2015
2015 Electric IRP Appendix A
531
Generation Resource Related Analysis
• Analysis of the continued feasibility of the Northeast Combustion Turbine
due to its age.
• Continue to review existing facilities for opportunities to upgrade capacity
and efficiency.
• Increase the number of manufacturers and sizes of natural gas-fired
turbines modeled for the PRS analysis.
• Evaluate the need for, and perform if needed, updated wind and solar
integration studies.
• Participate and evaluate the potential to join a Northwest Energy
Imbalance Market.
• Monitor regional winter and summer resource adequacy.
• Participate in state-level development of the Clean Power Plan.
2 2015 Electric IRP Appendix A
532
Energy Efficiency
• Continue to study and quantify transmission and
distribution efficiency projects as they apply to EIA
goals.
• Complete the assessment of energy efficiency
potential on Avista’s generation facilities.

3 2015 Electric IRP Appendix A
533
Transmission and Distribution Planning
• Work to maintain Avista’s existing transmission rights,
under applicable FERC policies.
• 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 facilitate long-term economic expansion of the
regional transmission system.

4 2015 Electric IRP Appendix A
534
Other 2015 Action Items
• Any areas of concern or suggestions?
• Please call or email the planning team with any suggestions
or added Action Items.
• Can also make edits to the draft IRP when it is released.
5 2015 Electric IRP Appendix A
535
2015 Electric IRP
Preferred Resource Strategy
James Gall
Sixth Technical Advisory Committee Meeting
June 24, 2015
2015 Electric IRP Appendix A
536
Introduction
• Discuss how Avista plans to meet resource
deficits (PRS)
• No Changes to Preferred Resource Strategy
since last TAC meeting
• Review tipping point analysis for resource
options not selected in IRP

2 2015 Electric IRP Appendix A
537
Tipping Point Analysis
• Lower resource costs to point PRiSM picks a different
the resource in question, all capital costs are in 2014
dollars
• Utility Scale Solar:
–$1,300/kW would have to decline to $671/kW to be selected in
2022 (-48%)
• Utility Scale Energy Storage:
–$2,736/kW, would have to decline to $770/kW in 2021 (-72%)
• Demand Response:
–$217/kW-yr (levelized nominal) would have to decline to
$117/kW-yr (-46%)
3 2015 Electric IRP Appendix A
538
2015 IRP Load and Resource Additions
4 2015 Electric IRP Appendix A
539
2015 IRP: Preferred Resource Strategy
5
Resource By the End of
Year
ISO Conditions
(MW)
Winter Peak
(MW)
Energy
(aMW)
Natural Gas Peaker 2020 96 102 89
Thermal Upgrades 2021-2025 38 38 35
Combined Cycle CT 2026 286 306 265
Natural Gas Peaker 2027 96 102 89
Thermal Upgrades 2033 3 3 3
Natural Gas Peaker 2034 47 47 43
Total 565 597 524
Efficiency
Improvements
Acquisition
Range
Winter Peak
Reduction
(MW)
Energy
(aMW)
Energy Efficiency 2016-2035 193 132
Distribution Efficiencies <1 <1
Total 193 132

2015 Electric IRP Appendix A
540
Conservation Forecast
6 2015 Electric IRP Appendix A
541
Greenhouse Gas Emissions Forecast
7 2015 Electric IRP Appendix A
542
2015 Electric IRP
Document Introduction
Planning Staff
Sixth Technical Advisory Committee Meeting
June 24, 2015
2015 Electric IRP Appendix A
543
2015 Electric IRP Chapters
1.Executive Summary
2.Introduction and Stakeholder Involvement
3.Economic and Load Forecast
4.Existing Resources
5.Energy Efficiency and Demand Response
6. Long-Term Position
7.Policy Considerations
8.Transmission and Distribution Planning
9.Generation Resource Options
10.Market Analysis
11.Preferred Resource Strategy
12.Portfolio Scenarios
13.Action Plan
2 2015 Electric IRP Appendix A
544
1. Executive Summary
2. Introduction and Stakeholder Involvement

3 2015 Electric IRP Appendix A
545
3. Economic and Load Forecast
• Population and employment growth is starting to recover from
the end of the Great Recession in 2009.
•The 2015 Expected Case’s energy forecast grows 0.6 percent
per year, replacing the 1.0 percent annual growth rate in the
2013 IRP.
• The retail sales forecast, residential use per customer
continues to decline.
• Peak load growth is higher than energy growth, at 0.72
percent in the winter and 0.85 percent in the summer.
• Testing performed for this IRP shows that historical extreme
weather events contain temperature extremes that are still
valid for peak load modeling.
4 2015 Electric IRP Appendix A
546
4. Existing Resources
• Hydroelectric represents about half of Avista’s winter
generating capability.
• Natural gas-fired plants represent the largest portion of
generation potential.
• Seven percent of Avista’s generating capability is
biomass and wind.
• Nine Mile Falls rehabilitation and upgrade will be
completed in 2016.
• 280 of Avista’s customers net meter 1.8 megawatts of
their own generation.
5 2015 Electric IRP Appendix A
547
5. Energy Efficiency and Demand Response
• Current Avista-sponsored conservation reduces retail
loads by nearly 11 percent, or 127 aMW.
• 2015 IRP evaluates over 3,000 equipment options, and
over 2,300 measure options covering all major end use
equipment, as well as devices and actions to reduce
energy consumption.
• This IRP co-optimizes conservation and demand
response selection with generation resource options
using our PRiSM model.
6 2015 Electric IRP Appendix A
548
6. Long-Term Position
• Avista’s first long-term capacity deficit net of energy
efficiency is in 2021; the first energy deficit is in 2026.
• Avista uses a 14 percent winter planning margin in
addition to meeting operating reserves for a 22.6 percent
planning margin.
• The 2015 IRP meets all EIA mandates over the next 20
years with a combination of RECs, qualifying
hydroelectric upgrades, Palouse Wind, and Kettle Falls.

7 2015 Electric IRP Appendix A
549
7. Policy Considerations
• The 2015 IRP uses
– existing carbon costs;
– the goals of the Clean Power Plan proposal;
– and a 10 percent probability of a carbon price to reduce
greenhouse gas emissions.
• Scenario analyses address the impacts of the Clean
Power Plan proposal by state and regionally, as well as
various issues for Avista’s Colstrip ownership interest.
• Avista’s Climate Policy Council monitors greenhouse gas
legislation and environmental regulation issues.

8 2015 Electric IRP Appendix A
550
8. Transmission and Distribution Planning
• Avista actively participates in regional transmission
planning forums.
• Avista System Planning transitioned from a biannual to
an annual study process.
• Projects completed since the last IRP include new
sections of transmission lines, and rebuilds and
upgrades through the grid modernization project.
• Planned projects include reconductoring, and station
rebuilds and reinforcements.
• Significant generation interconnection study work around
Lind substation continues.

9 2015 Electric IRP Appendix A
551
9. Generation Resource Options
• Only resources with well-defined costs and operating
histories are options to meet future resource needs.
• Wind, solar and hydroelectric upgrades represent
renewable options available to Avista.
• Upgrades to Avista’s Spokane and Clark Fork River
facilities are included as resource options.
• Future requests for proposals might identify different
technologies.
• Renewable resource costs assume no extensions of
current state and federal incentives.

10 2015 Electric IRP Appendix A
552
10. Market Analysis
• Natural gas, solar, and wind resources dominate new
generation additions in the Western Interconnect.
• Clean Power Plan regulation could cause large price and
costs swings, but without a final rule, the impacts are
unknown.
• The Expected Case forecasts a continuing reduction of
Western Interconnect greenhouse gas emissions due to
coal plant shut downs brought on by federal and state
regulations and low natural gas prices.
11 2015 Electric IRP Appendix A
553
11. Preferred Resource Strategy
• Avista’s first anticipated resource acquisition is a natural
gas-fired peaker by the end of 2020 to replace expiring
contracts and serve growing loads.
• A combined cycle combustion turbine replaces the
Lancaster Facility when its contract ends in 2026.
• Upgrades to existing facilities help meet resource deficits.
• Energy efficiency offsets 52 percent of projected load
growth through the 20-year IRP timeframe.
12 2015 Electric IRP Appendix A
554
12. Portfolio Scenarios
• Lower or higher future loads do not materially change the
resources strategy.
• Colstrip remains a cost-effective and reliable source of power to
meet future customer loads.
• In the Without Colstrip in 2027 scenario, customer bills increase
$68 million.
• A $19 per metric ton social cost of carbon market scenario
increases customer’s costs by $67 million per year levelized.
• Tipping point analysis suggests utility scale solar costs would
need to decline another 48 percent to be in the Preferred
Resource Strategy.
13 2015 Electric IRP Appendix A
555
13. Action Plan
• Covered in earlier presentation

• Generation resource related analysis
• Energy efficiency
• Transmission and distribution planning
14 2015 Electric IRP Appendix A
556
Remaining 2015 IRP Schedule
• July 10, 2015 – external draft released to TAC
• July 31, 2015 – external draft comments due
• August 28, 2015 – file final 2015 IRP with Commissions
• August 31, 2015 – 2015 IRP available to the public on
Avista’s web site
• Public comments period will be determined by the
Commissions
15 2015 Electric IRP Appendix A
557

2015 Electric Integrated
Resource Plan

Appendix B – 2015 Electric IRP
Work Plan

2015 Electric IRP Appendix B
558

Avista Corporation’s
2015 Electric Integrated Resource Plan (IRP)
Work Plan

For the
Washington Utilities and Transportation Commission

August 29, 2014

2015 Electric IRP Appendix B
559
P a g e | 2

2015 Electric 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). It outlines the
process Avista will follow to develop its 2015 IRP for filing with Washington and Idaho
Commissions by August 31, 2015. Avista uses a public process to solicit technical expertise and
feedback throughout the development of the IRP through a series of public Technical Advisory
Committee (TAC) meetings. Avista held the first TAC meeting for the 2015 IRP on May 29,
2014.

The 2015 IRP process will be similar to those used to produce the previous IRP. Avista will use
AURORAxmp for electric market price forecasting, resource valuation and for conducting Monte-
Carlo style risk analyses. AURORAxmp modeling results will be used to select the Preferred
Resource Strategy (PRS) using Avista’s proprietary PRiSM 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 laws and
regulations. Qualitative risk evaluations are in separate analyses. Exhibit 1 shows the process
timeline and the process to identify the PRS is in Exhibit 2.

Avista intends to use both detailed site-specific and generic resource assumptions in
development of the 2015 IRP. The assumptions combine Avista’s research of similar generating
technologies, engineering studies, and the development of the Northwest Power and
Conservation Council’s Seventh Power Plan. This IRP will study renewable portfolio standards,
environmental costs, sustained peaking requirements and resource adequacy, energy efficiency
programs and demand response. The 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 a range of scenarios and potential futures. The TAC
meetings will help to determine the underlying assumptions used in the scenarios and futures.
The IRP process is very technical and data intensive; public comments are welcome but timely
2015 Electric IRP Appendix B
560
P a g e | 3

input and participation will be necessary for inclusion into the process so the plan can be
submitted according to the tentative schedule in this Work Plan.

The following topics and meeting times may change depending on the availability of presenters
and requests for additional topics from the TAC members. The tentative timeline and agenda
items for TAC meetings follows:

 TAC 1 – May 29, 2014: Setting Expectations, review of 2013 IRP acknowledgement letters
and Action Plan, Energy Independence Act compliance, Pullman Energy Storage Project
update, demand response study discussion and review the 2015 IRP draft Work Plan.

 TAC 2 – September 23, 2014: Review conservation selection methodology, update on the
Company’s demand response study, load and economic forecasts, generation options and
Clean Power Plan proposal discussion.

 TAC 3 – November 2014: Planning margin, Colstrip discussion, cost of carbon, modeling
overview and conservation potential assessment methodology.

 TAC 4 – February 2015: Electric and natural gas price forecasts, transmission planning,
resource needs assessment, market and portfolio scenario development, energy storage and
ancillary service evaluation

 TAC 5 – March 2015: Completed conservation potential assessment, draft PRS, review of
scenarios and futures and portfolio analysis

 TAC 6 – June 2015: Review of final PRS and action items.

2015 Electric IRP Appendix B
561
P a g e | 4

2015 Electric IRP Draft Outline

The following is a draft outline of the major sections envisioned for the 2015 Electric IRP. This
outline may change with the input from the Company’s TAC, and as IRP studies are completed
and have been received:

1. Executive Summary
2. Introduction and Stakeholder Involvement
3. Economic and Load Forecast
a. Economic Conditions
b. Avista Energy & Peak Load Forecast
c. Load Forecast Scenarios
4. Existing Resources
a. Avista Resources
b. Contractual Resources and Obligations
5. Energy Efficiency and Demand Response
a. Conservation Potential Assessment
b. Demand Response Opportunities
6. Long-Term Position
a. Reliability Planning and Reserve Margins
b. Resource Requirements
c. Reserves and Flexibility Assessment
7. Policy Considerations
a. Environmental Concerns
b. State and Federal Policies
8. Transmission & Distribution Planning
a. Avista’s Transmission System
b. Future Upgrades and Interconnections
c. Transmission Construction Costs and Integration
d. Efficiencies
9. Generation Resource Options
a. New Resource Options
b. Avista Plant Upgrades
10. Market Analysis
a. Marketplace
b. Fuel Price Forecasts
c. Market Price Forecast
d. Scenario Analysis
11. Preferred Resource Strategy
a. Resource Selection Process
b. Preferred Resource Strategy
c. Efficient Frontier Analysis
d. Avoided Cost
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P a g e | 5

12. Portfolio Scenarios
a. Portfolio Scenarios
b. Tipping Point Analysis
13. Action Plan
a. 2013 Action Plan Summary
b. 2015 Action Plan
2015 Electric IRP Appendix B
563
P a g e | 6

Avista Corporation’s
2015 Electric Integrated Resource Plan (IRP)
Work Plan

Exhibit 1
2015 Electric IRP Timeline

2015 Electric IRP Appendix B
564
P a g e | 7

Exhibit 1: 2015 Electric IRP Timeline
Task Target Date
Preferred Resource Strategy (PRS)
Identify Avista’s supply & conservation
xmp
xmp

Simulation of risk studies “futures” completexmp
Writing Tasks

2015 Electric IRP Appendix B
565
P a g e | 8

Avista Corporation’s
2015 Electric Integrated Resource Plan (IRP)
Work Plan

Exhibit 2
2015 Electric IRP Modeling Process
2015 Electric IRP Appendix B
566
P a g e | 9

2015 Electric IRP Appendix B
567

2015 Electric Integrated
Resource Plan

Appendix C – AEG Studies
 Demand Response Study
 Conservation Potential
Assessment

2015 Electric IRP Appendix C
568

Avista Corporation
Commercial & Industrial Demand Response
Potential Study
Final Report

2015 Electric IRP Appendix C
569

This report was prepared by
Applied Energy Group, Inc.
500 Ygnacio Valley Road, Suite 450
Walnut Creek, CA 94596

Project Director: I. Rohmund
Project Manager: D. Costenaro
D. Ghosh
C. Carrera

Subcontractor:

The Brattle Group
A. Faruqui

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Contents
1 Introduction .............................................................................................................. 7
2 Analysis Approach ..................................................................................................... 8
Market Characterization ..................................................................................................... 8
Segmentation Basis ............................................................................................... 8
Key Market Data ................................................................................................... 8
DR Program Descriptions ................................................................................................... 9
Key Program Parameters ....................................................................................... 9
Potential and Cost Estimates ............................................................................................ 10
3 Market Characterization .........................................................................................11
4 DR Program Descriptions ........................................................................................14
Relevant DR Programs .................................................................................................... 14
Direct Load Control Program ............................................................................................ 15
Direct Load Control Program Assumptions ............................................................ 16
Firm Curtailment Program................................................................................................ 19
Firm Curtailment Program Assumptions ................................................................ 20
Critical Peak Pricing ......................................................................................................... 23
Critical Peak Pricing Assumptions ......................................................................... 24
Other Cross-cutting Assumptions ..................................................................................... 28
5 DR Potential and Cost Estimates ............................................................................29
Potential Results ............................................................................................................. 29
Cost Results.................................................................................................................... 32
Integrated Results .......................................................................................................... 32
A Literature Review .........................................................................................................34
Introduction.................................................................................................................... 34
Research Approach ......................................................................................................... 35
Proposed List of DR Options by Customer Class .................................................... 35
Approach for Selecting Representative Programs for Further Research ................... 36
Direct Load Control Programs .......................................................................................... 41
General Program Characteristics .......................................................................... 41
Specific Pilot and Program Examples .................................................................... 42
Firm Curtailment Programs .............................................................................................. 52
General Program Characteristics .......................................................................... 52
Specific Program Examples .................................................................................. 54
Non-Firm Curtailment Programs ....................................................................................... 56
General Program Characteristics .......................................................................... 56
Specific Program Examples .................................................................................. 57
Critical Peak Pricing Programs .......................................................................................... 59
General Program Characteristics .......................................................................... 59
Specific Program Examples .................................................................................. 60
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Real Time Pricing Programs ............................................................................................. 63
General Program Characteristics .......................................................................... 63
Specific Program Examples .................................................................................. 63
Ancillary Services / Load Following Pilots .......................................................................... 65
General Program Characteristics .......................................................................... 65
Specific Examples ............................................................................................... 67
Cost Effectiveness Assessment for Demand Response ....................................................... 68
DR Program Costs ............................................................................................... 68
DR Program Benefits ........................................................................................... 69
Cost-effectiveness Assessment Framework ........................................................... 70
Impact Estimation Methods for Demand Response ............................................................ 71
Types of Impact Estimation ................................................................................. 71
Baseline Calculation Methods ............................................................................... 71
Impact Estimation Methods ................................................................................. 72
B Time-of-Use Rates ........................................................................................................ 74
Program Description ........................................................................................................ 74
TOU Assumptions ............................................................................................... 75

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List of Figures
Figure 5-1 Summary Potential Analysis Results for Avista (MW @Generator) ............................. 30

List of Tables
Table 3-1 Market Segmentation ............................................................................................. 11
Table 3-2 Baseline C&I Customer Forecast by State and Customer Class .................................. 12
Table 3-3 Baseline System Peak Forecast (MW @Generator) ................................................... 12
Table 3-4 Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter) ........ 13
Table 3-5 Electric Space Heating and Water Heating Saturation by State and Customer Class ... 13
Table 4-1 Relevant DR Programs for Avista ............................................................................ 14
Table 4-2 Direct Load Control Program Features ..................................................................... 15
Table 4-3 DLC Participation Rates (% of eligible customers) .................................................... 16
Table 4-4 Basis for Direct Load Control Program Participation Assumptions .............................. 16
Table 4-5 Per Participant Impact Assumptions for Direct Load Control Program ........................ 16
Table 4-6 DLC Program Cost Assumptions .............................................................................. 18
Table 4-7 Direct Load Control Program Lifetime and Capacity Derating Factor .......................... 19
Table 4-8 Firm Curtailment Program Features ......................................................................... 20
Table 4-9 Firm Curtailment Program Participation Rates (% of eligible customers) .................... 21
Table 4-10 Basis for Firm Curtailment Program Participation Assumptions .................................. 21
Table 4-11 Per Participant Load Reduction Assumption for the Firm Curtailment Program ........... 21
Table 4-12 Firm Curtailment Program Cost Assumptions ........................................................... 22
Table 4-13 Firm Curtailment Program Lifetime and Capacity Derating Factor .............................. 22
Table 4-14 Critical Peak Pricing Program Features .................................................................... 24
Table 4-15 Opt-in CPP Participation Rates (% of eligible customers) .......................................... 25
Table 4-16 Percentage of CPP Participants with Enabling Technology (% of total participants) .... 25
Table 4-17 Per-Participant Load Reduction in CPP Rates by Customer Class ............................... 26
Table 4-18 CPP Program Cost Assumptions for Opt-in and Opt-out Offers .................................. 27
Table 4-19 Program Lifetime and Capacity Derating Factor for Pricing Options ........................... 27
Table 5-1 Achievable DR Potential by Option for Avista (MW @Generator) ............................... 30
Table 5-2 Achievable DR Potential by Option for Washington (MW @Generator) ....................... 31
Table 5-3 Achievable DR Potential by Option for Idaho (MW @Generator)................................ 31
Table 5-4 DR Program Costs and Potential ............................................................................. 32
Table 5-5 DR Program Costs and Potential - Interactive .......................................................... 33

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Applied Energy Group, Inc. 7
SECTION 1
Introduction
Avista Corporation commissioned Applied Energy Group (AEG), with subcontractor the Brattle Group,
to provide an assessment of demand response potential within its commercial and industrial (C&I)
sectors in Washington and Idaho. The purpose of this study was to help Avista gain a better
understanding of implementing demand response programs in the commercial and industrial sectors,
and the corresponding cost and benefits.
This study provides demand response potential and cost estimates, including supply curves, for
the 20-year planning horizon of 2016–2035 to inform the development of Avista’s 2015
Integrated Resource Plan (IRP). It primarily seeks to develop reliable estimates of the
magnitude, timing, and costs of DR resources likely available to Avista over the 20-year planning
horizon. The study focuses on resources assumed achievable during the planning horizon,
recognizing known market dynamics that may hinder resource acquisition. Study results will be
incorporated into Avista’s 2015 IRP and subsequent DR planning and program development
efforts.
This study focused on developing DR potential and cost estimates for C&I customers only. Avista had
recently offered two residential demand response pilot programs that have helped gain a good
understanding of residential demand response programs and their costs and benefits in Avista’s
service territory. Additional assessment of demand response potential for residential customers was
outside the scope of the current study. However, as part of this study, Avista was interested in
obtaining information from a national review of DR programs offered to residential customers.
This document is organized as follows:
 Section 2 describes the analysis approach and the data sources used to develop potential
and cost estimates.
 Section 3 presents market characterization data used for our analysis.
 Section 4 identifies and describes relevant DR programs and presents assumptions on key
program parameters.
 Section 5 presents potential and cost results from our analysis.

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SECTION 2
Analysis Approach
This section describes our analysis approach and the data sources used to develop potential and cost
estimates.
The following three steps broadly outline our analysis approach:
1. Segment C&I customers for DR analysis and develop market characteristics (customer count
and coincident peak demand values) by segment for the base year and planning period.
2. Identify and describe relevant DR programs and develop assumptions on key program
parameters for potential and cost analysis.
3. Assess achievable potential by DR program for the 2016-2035 planning period and estimate
program budgets and levelized costs.
We describe these analysis steps throughout the remainder of this chapter.
Market Characterization
The first step in the DR analysis was to segment C&I customers and develop characteristics for
each segment.1 The two relevant characteristics for DR potential analysis are the number of
eligible customers in each market segment and their coincident peak demand values.
Segmentation Basis
We used Avista’s rate schedules as the basis for C&I customer segmentation. We segmented C&I
customers into General Service, Large General Service, and Extra Large General Service classes.2
Customers in rate schedule no. 11 belong to the “General Service” class, customers in rate
schedule no. 21 belong to the “Large General Service” class and customers in rate schedule no.
25 belong to the “Extra Large General Service” class.
We selected 2013 to be the base year for the study since it the latest year for which complete
customer count and electricity sales data are available.
Key Market Data
Once the customer segments were defined and the base year was selected, we developed
customer count and coincident peak demand values for the three C&I segments. We developed
these estimates separately for Washington and Idaho.
We obtained the 2013 customer count and electricity sales data by rate schedule from Avista. We
used the electricity sales data to derive coincident peak demand estimates by segment. We did
this by calculating load factors for each segment. In order to calculate these load factors, we
relied on electricity sales and coincident peak demand values provided in the 2010 load research
study conducted by Avista. The study provided electricity sales and coincident peak demand
values for General Service, Large General Service, and Extra Large General Service customers for
Washington and Idaho, for the year 2010. We used this data to calculate load factors by
segment and by state and applied this to the 2013 electricity sales to derive coincident peak
demand estimates.

1 This study estimates DR potential for C&I customers only. Residential DR potential estimates are outside the scope of this study. 2 We excluded two largest industrial customers from our analysis. Avista may wish to engage with these two customers directly to
gauge their interest in participating in a DR program.
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Baseline Projection
Once the base year market characteristics were defined, we developed customer count and
coincident peak demand projections by state and segment for the period 2014-2035.
Avista provided customer count and electricity sales projections by rate schedules for
Washington and Idaho over the 2014-2019 timeframe. We used this data to calculate the
average annual growth in customer count and sales. We then applied these same average annual
growth rates to develop customer count and sales projections over the 2020-2035 timeframe. For
General Service customers, however, this method produced an inaccurate growth rate due to
near-term changes in the customer mix. We therefore developed a more reasonable growth rate
in collaboration with Avista to project the trends for 2020-2035.
Once the electricity sales projections were developed, we applied the calculated load factors
from the earlier step to develop coincident peak demand projections by segment and by state.
We assumed that load factor for a particular customer segment in a state remains unchanged
from the 2010 value for the 2016-2035 planning period.
End Use Saturation
Another key component of market characterization for DR analysis is electric space heating and
water heating saturation data. This is required to further segment the market and identify
eligible customers for direct control of electric space heating and water heating equipment. We
obtained saturation data from the Conservation Potential Assessment study conducted by Avista
in 2013. We assumed water heating and electric space heating saturation values remain constant
over the analysis timeframe.
Section 3 of the report presents customer count, coincident peak demand and saturation data by
customer segment.
DR Program Descriptions
Once we completed the market characterization, we focused on identification of relevant DR
programs for Avista’s commercial and industrial customers.
In order to conduct this task, we initially prepared a universal list of DR programs that could be
considered relevant for Avista. This initial list was based on a national review of different DR
program types currently offered in the industry. We used the 2012 national DR program survey
database, published by FERC, to conduct this task.
We selected representative program examples within each type of program and further
researched these programs. We presented the universal list of relevant DR programs in a memo
to Avista and followed it up with a research report that summarized key findings from our
research.
Subsequently, our team (AEG and Brattle) participated in a workshop with Avista to discuss these
options and obtain Avista’s feedback. Based on guidance received from Avista, we modified our
programs list and proceeded to develop detailed descriptions of programs included in that list.
Key Program Parameters
We developed assumptions on key program parameters used to estimate DR programs savings
and costs. These parameters include program participation rates, per participant load reductions,
and program costs.
We relied on secondary data sources and the AEG-Brattle team’s collective experience to develop
these assumptions. The primary data source for DR programs was the 2012 FERC national DR
program survey database. We combined the FERC survey data with other relevant data source
from EIA Form 861 and FERC Form 1 to develop data on key program parameters.
We also used individual program evaluation reports, wherever available. For pricing programs,
we relied on Brattle’s extensive database that includes information compiled from a very large
number of national and international pricing programs and pilots.
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We developed detailed itemized assumptions on various fixed and variable cost components
including program development costs, annual program administration costs, marketing and
recruitment costs, costs for purchase and installation of enabling technology, annual O&M costs,
and participant incentives. These cost assumptions are informed by our team’s consultation with
industry experts involved in actual program implementation. We also relied heavily on inputs
provided by Avista to develop these assumptions.
Appendix A summarizes the key findings from our review of DR programs. Section 4 provides
detailed descriptions of key program features and presents assumptions on key program
parameters that are used to develop potential and cost estimates.
Participation Rates
The steady-state participation assumptions are based on an extensive database of existing
program information and insights from market research results, and represent “best-practices”
estimates for participation in these programs. This approach is commonly followed in the
industry for arriving at achievable potential estimates. However, practical implementation
experience suggests that uncertainties in factors such as market conditions, regulatory climate,
and economic environment are likely to influence customer participation in DR.
Once initiated, DR options require a time period to ramp up and reach a steady state because
customers need time for education, marketing, and recruitment, in addition to the physical
implementation and installation of any hardware, software, telemetry, or other equipment. You
cannot merely flip a switch on human behavior, so the customer engagement aspect of these
options must be carefully considered.
In this analysis, we model programs as ramping up generally in a three-year to five-year
timeframe to their steady state, which is typical of industry experience. For direct load control
and pricing options, participation is assumed to ramp up following an “S-shaped” diffusion curve
over a five-year timeframe. The rate of participation growth accelerates over the first half of the
five-year period, and then slows over the second half. For the Firm Curtailment option, which is
typically third-party delivered over shorter contract periods of three to five years, participation is
assumed to ramp up linearly within a three-year timeframe. An annual attrition rate of 1% is
uniformly applied to participants across all options to account for customers dropping out of the
programs.
Potential and Cost Estimates
The last step in our analysis was to calculate savings from DR programs and estimate costs for
achieving these savings. We conducted our analysis in two stages. We developed savings and
cost estimates for individual DR programs considered on a standalone basis. This does not take
into consideration any participation overlap that may occur if Avista were to implement multiple
programs simultaneously. Therefore, the potential and cost estimates for individual DR options
are not additive as there would be some amount of overlap among the target market of
participating customers. We expect this effect to be relatively small among customers.
We then used itemized cost assumptions to estimate total and annual program budgets, calculate
levelized costs for DR programs, and develop resource supply curves.
Section 5 presents potential and cost analysis results.

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Applied Energy Group, Inc. 11
SECTION 3
Market Characterization
The first step in the DR analysis was to segment C&I customers and develop customer count and
peak demand values for the base year and the 2016-2035 planning period. This section presents
the C&I segments selected for our analysis and shows the customer count and coincident peak
demand values for these segments. We have also included electric space heating and water
heating saturation values that are relevant for the DR analysis.
Market Segmentation
We segmented C&I customers into two dimensions: by state and customer class. Table 3-1
summarizes the market segmentation we developed for this study.
Table 3-1 Market Segmentation
Market
Dimension
Segmentation
Variable Description
1 State Idaho, Washington
2 Customer Class
By rate schedule:
General Service: Rate Schedule 11
Large General Service: Rate Schedule 21
Extra Large General Service: Rate Schedule 25 3

We excluded Avista’s two largest industrial customers from our analysis. To accurately estimate
demand reduction potential for these customers, we would need to develop a detailed
understanding of their industrial processes and associated possibilities for load reduction and
develop specific DR potential estimates for each customer. The common approach followed to
estimate potential for other customers does not apply to these extremely large customers, and
therefore we did not include them in the analysis. However, Avista may wish to engage with
these two customers directly to gauge their interest in participating in a DR program.
Customer Count by Segment
Once we segmented the market, we developed customer counts for the base year and forecast
years included in the analysis. We considered 2013 as the base year for the study, since this is
the most recent year with 12 months of available customer data, and 2016 to 2035 as the
forecast years.
Avista provided us with actual customer counts by rate schedule for 2013 and forecasts for 2014
to 2019. We calculated the average annual growth rate for each customer class over that period
and used the average to project the number of customers in 2020-2035.
Table 3-2 below shows customer count data by state for the base year and selected future years.

3 Excluding the two largest Schedule 25 and Schedule 25P customers.
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Table 3-2 Baseline C&I Customer Forecast by State and Customer Class
Customer Class 2013 2016 2020 2025 2030 2035
Washington
General Service 20,983 22,309 23,517 25,515 27,683 30,035
Large General Service 1,983 1,954 1,949 1,925 1,901 1,877
Extra Large General Service 20 20 20 20 20 19
Total C&I 22,987 24,283 25,486 27,459 29,603 31,931
Idaho
General Service 15,532 15,991 16,946 18,158 19,457 20,849
Large General Service 1,127 1,127 1,126 1,117 1,109 1,101
Extra Large General Service 9 9 9 9 9 9
Total C&I 16,531 16,893 18,081 19,285 20,575 21,959
System and Coincident Peak Demand by Segment
The next step in market characterization was to define peak forecasts for each customer
segment. Avista provided us with 2013 system peak demand value and peak forecasts for 2015
through 2035. Table 3-3 shows the system peak demand for the base year and selected future
years. The overall system peak demand values in the table represent the total demand on
Avista’s system. The “weather sensitive” peak represents the overall system peak demand minus
the demand for Avista’s two largest industrial customers.
Table 3-3 Baseline System Peak Forecast (MW @Generator) 4
Peak Demand 2013 2016 2020 2025 2030 2035
Overall System Peak 1,669 1,718 1,768 1,828 1,891 1,995
Weather-sensitive Peak 1,569 1,590 1,640 1,700 1,763 1,827

To develop the coincident peak forecast for each segment, we started with electricity sales by
customer class. Avista provided electricity sales by rate schedule for the 2013 through 2019. For
General Service customers, Avista provided projected average annual sales growth for
Washington and Idaho.5 For Large General Service and Extra Large General Service customers,
we projected electricity sales for 2019 through 2035 using the average annual growth rate over
the 2014-2019 timeframe.
Next, we applied load factors by customer class and state to the electricity sales forecast to
calculate coincident peak demand. To estimate the load factors, we used data from Avista’s 2010
load research study which provided coincident peak demand and electricity sales by state and
customer class. Table 3-4 below shows the load factors and coincident peak values for the base
year and selected future years.

4 The system peak forecast shown here is the net native load forecast from data provided by Avista, excluding the two largest industrial
loads. 5 Based on information from Avista, we directly used an average of 0.8% sales growth for GS customers in Washington and an average
1.4% sales growth for GS customers in Idaho for the 2019-2035 period
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Table 3-4 Load Factors and Baseline Coincident Peak Forecast by Segment (MW @Meter)
Segment Level Coincident
Peaks
Load
Factor 2013 2016 2020 2025 2030 2035
Washington
General Service 0.64 75 76 78 81 85 88
Large General Service 0.75 193 193 193 188 184 179
Extra Large General Service 0.79 86 89 93 92 90 89
Total C&I n/a 354 359 364 361 358 356
Idaho
General Service 0.80 60 60 64 69 74 79
Large General Service 0.82 105 103 103 102 101 100
Extra Large General Service 0.79 43 48 51 57 64 72
Total C&I n/a 207 211 218 227 238 251
Saturation Assumptions for Relevant End-Uses
Another important factor in Avista market characterization is the saturation level of relevant end
uses included in the DR analysis: electric space heating and water heating. The two relevant
space heating equipment for DR analysis are central furnaces and heat pumps. The saturations
are relevant for estimating savings from direct-load control programs which are applicable to
General Service and Large General Service customers (see Section 4). Table 3-5 below shows
saturation estimates by state and customer class. We obtained all saturation values from the
Conservation Potential Assessment study conducted by Avista in 2013.
Table 3-5 Electric Space Heating and Water Heating Saturation by State and Customer Class
End-use Saturation by Equipment Type General Service Large General Service
Space Heating Saturation for Washington
Heat Pump 3.6% 9.1%
Central Furnace 17.7% 12.7%
Total (Applicable for DR Analysis) 21.3% 21.8%
Space Heating Saturation for Idaho
Heat Pump 3.6% 9.1%
Central Furnace 17.7% 12.7%
Total (Applicable for DR Analysis) 21.3% 21.8%
Water Heating Saturation for Washington
All equipment 63.0% 54.2%
Water Heating Saturation for Idaho
All equipment 54.2% 54.2%

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Applied Energy Group, Inc. 14
SECTION 4
DR Program Descriptions
This section identifies and describes the relevant Demand Response programs for Avista. It
highlights the key features for each program and presents assumptions on program parameters
that are required for potential and cost calculations. Program features describe characteristics
such as targeted customer segment, typical end-uses controlled, available hours, event
notification and duration, type of response, incentive levels to participants, metering
requirements and mechanisms for program delivery. These characteristics will help support
future DR program design by Avista. In addition to these characteristics, this section presents
participation, impact, and cost assumptions for individual DR programs and provides detailed
documentation for these assumptions. These assumptions serve as a foundation for potential and
cost analysis results presented in Section 5.
Relevant DR Programs
Table 4-1 presents the DR programs included in our analysis, which we developed in consultation
with Avista staff. There were other options we considered but the final set is shown below. The
different types of DR programs can be broadly classified into two types: non-pricing programs
and pricing programs
 Non-pricing programs represent firm, dispatchable resources that Avista could count on to
fulfill system resource requirements when needed. The two types of non-pricing programs
included in our analysis are Direct Load Control (DLC) and Firm Curtailment (FC) program.
DLC programs target space heating and water heating, as described below.
 Dynamic pricing options, on the other hand, represent non-firm resources that may not be
available for dispatch when needed. The pricing option considered to be relevant for Avista is
Critical Peak Pricing (CPP).
Table 4-1 Relevant DR Programs for Avista
Category Program Applicable Customer Class
Non-pricing
Direct Load Control General Service (GS)
Large General Service (LGS)
Firm Curtailment Large General Service (LGS)
Extra Large General Service (XLGS)
Pricing Critical Peak Pricing
General Service (GS)
Large General Service (LGS)
Extra Large General Service (XLGS)

In addition to the above options included in the study, we considered three additional options
that were qualitatively screened out of the potentials analysis. A listing of these options and the
rationale for ultimately not including each is below.
 Thermal Energy Storage (TES). Thermal energy storage technologies are a relatively
mature technology that is worthwhile in some niche applications and climates. Otter Tail
Power has a successful TES program. However, this option is not well-suite to Avista’s
relatively mild climate.
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 Conservation Voltage Reduction (CVR). We screened CVR out of the analysis here
because Avista is already doing this.
 DR providing ancillary services (Fast DR). DR resources for providing ancillary services
such as frequency regulation or spinning reserves need to be Auto-DR enabled and possess
very fast response times. They need to be available 24x7 with a high degree of reliability.
Fast DR is well suited to a number of industries, such as mechanical digesters at paper-pulp
mills and rock crushers. The potential for this program option would likely be captured by
customers who would enroll in the Firm Curtailment program.
Additional information about TES and Fast DR is provided in Appendix A.
Direct Load Control Program
A DLC program would target Avista’s General Service and Large General Service customers in
Washington and Idaho. This program would directly control electric space heating load in winter
and water heating load throughout the year for these customers through a load control switch or
a programmable thermostat for space heating. The two types of space heating equipment that
could be controlled are central electric furnaces and heat pumps, which would be cycled on and
off during the events. Water heaters would be completely turned off during the DR event period.
Water heaters of all sizes are eligible for control. Avista could offer this program beginning in
2016. Typically a DLC program takes five years to ramp up to maximum participation levels.
Therefore, it is likely that by 2020 the full potential of this program would be realized. Table 4-2
below describes key DLC program attributes.
Table 4-2 Direct Load Control Program Features
Program
Attributes Description Comments
Targeted
Segment
General Service and Large General Service
customers in WA and ID with eligible electric
space heating and water heating equipment.
Only heat pumps and central furnaces are
eligible for DLC. The combined saturation is
the same for Washington and Idaho at
21.3%.
Electric water heating saturation is 63% in
Washington and 54% in Idaho.
Resource
Availability
Space heating is controlled during the winter
months (October-April). Most events are
likely to be called during the months of
December-February when demand is high.
Water heating is controlled throughout the
year.
October through April are the winter months
for Avista. System peak usually occurs in
December and demand is significantly high
during January and February. Therefore most
events are likely to be called during
December to February.
Event
Notification
Day ahead event notification via email,
phone, or SMS.
Avista peaks happen during the early
morning hours so participants need to be
provided with day-ahead notification.
Maximum
Annual Event
Hours
60 hours Based on Duke Energy Carolinas DLC
program.
Event
Duration Event duration can range from 4 to 6 hours. Based on Duke Energy Carolinas and Florida
Power and Light's DLC program information.
Type of
Response
Space heaters can be cycled or completed
turned off during the event period or the
temperature can be set using a
Programmable Communicating Thermostat.
Water heaters are completely shut off during
the event period.

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Delivery
Mechanism
Avista is responsible for delivering the
program.
Most DLC programs in the industry are
delivered directly by the utility.
Participant
Incentive
$60 annual payment for space heating
control during the winter; $50 annual
payment for water heating control
throughout the year.
Incentive payments to DLC customers are
typically in the $20-$100 range. Our
assumption is at the midpoint of this range
for space heating control. For water heating
control, we assumed $4/month incentive for
control all year round.
Metering
Requirements
Customers can participate with existing
meters.
Interval meters are not required to
participate.

Direct Load Control Program Assumptions
The key parameters required to estimate potential for a DLC program are participation rate, per
participant load reduction and program costs. We have described below our assumptions of
these parameters.
Participation Rate
Avista could offer this program from 2016 to General Service and Large General Service
customers with eligible space heating and water heating equipment. We used information from
the most successful programs identified in the FERC survey to develop these assumptions. Based
on industry experience, we estimated that the program would follow an S-shaped ramp and
reach steady-state participation level by 2020. Table 4-3 below shows participation rates
assumptions.
Table 4-3 DLC Participation Rates (% of eligible customers)
Assumption Unit 2016 2017 2018 2019 2020-35
Participation Rates % of eligible
customers 1.5% 4.5% 9.0% 13.5% 15.0%

Table 4-4 below describes the basis for the steady-state participation rate and program ramp up
period assumptions.
Table 4-4 Basis for Direct Load Control Program Participation Assumptions
Assumption Unit Value Basis for Assumptions
Steady-state
Participation Rate % of eligible customers 15%
Assumed to be slightly larger than the weighted
average participation rate of 23 C&I DLC programs
reported in the FERC survey database.6
Ramp Rate
No. of years required to
attain steady-state
participation level
5 Interviews with utility program managers; FERC
National Assessment of DR Potential database.

DLC Load Reduction
Table 4-5 presents per-participant load reduction for space heating and water heating control
and explains the basis for these assumptions.

Table 4-5 Per Participant Impact Assumptions for Direct Load Control Program

6 http://www.ferc.gov/industries/electric/indus-act/demand-response/2012/survey.asp
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End use and
Customer Class
Value
(kW) Basis for Assumptions
Space Heating Control
General Service 1.50 Values are assumed to be 25% higher than residential impacts from
Puget Sound Energy (PSE) residential DLC pilot.
Large General Service 15.0 Assumed to be 15% of the class average coincident demand of 100 kW.
Water Heating Control
General Service 0.47 Values are assumed to be 25% higher than residential impacts from
Puget Sound Energy (PSE) residential DLC pilot.
Large General Service 10.0 Assumed to be 10% of the class average coincident demand of 100 kW.
Program Costs
Table 4-6 presents itemized cost assumptions for the DLC program and the basis for the
assumptions.

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Table 4-6 DLC Program Cost Assumptions
Assumption Unit Value Basis for Assumption
Program Development
Cost $/program $150,000
We assumed that 1 FTE (@$150,000 annual cost) is required
to develop the DLC program for both WA and ID and the cost
is equally split between the two customer classes for each
state.
Program Administration
Cost $/year $150,000
We assumed 1 FTE annual cost for DLC program
administration for WA and ID, split equally between the two
customer classes.
Annual Marketing and
Recruitment Costs
(GS)
$/new
participant $100
Standard assumption for residential customers is $50. For
small commercial customers, we assumed costs to be 25%
higher than the costs for residential.
Annual Marketing and
Recruitment Costs
(Large GS)
$/new
participant $133
We assumed 33% higher costs for Large General Service
customers than comparable costs for General Service
customers.
Cost of Equip + Install for
Space Heating Control
(GS)
$/new
participant $375
Load control switch capital cost = $100.
Average of 1.25 control units per customer.
Implies capital cost per participant = $125.
Switch installation cost = $125.
License and permit-related costs = $125 per participant (25%
higher than equivalent cost for residential customers at $100).
Cost of Equip + Install for
Space Heating Control
(Large GS)
$/new
participant $550 Control switch capital and installation cost = $200.
License and permit related costs = $150 per participant.
Cost of Equip + Install for
Water Heating Control
(GS)
$/new
participant $350
Load control switch capital cost= $100.
Switch installation cost = $125.
One water heating control unit per participant.
Implies cost per participant is $225.
License and permit related costs = $125 per participant (25%
higher than equivalent cost for residential customers at $100).
Cost of Equip + Install for
Water Heating Control
(Large GS)
$/new
participant $450
Load control switch capital and installation cost = $150 each.
License and permit related costs = $150 per participant (50%
higher than equivalent cost for residential customers at $100).
Annual O&M cost
(GS)
$/participant
per year $15 Annual O&M cost = 10% of the control equipment cost.
Annual O&M cost
(Large GS)
$/participant
per year $20 Annual O&M cost = 10% of the control equipment cost.
Per participant annual
incentive for Space
Heating (GS)
$/participant
per year $60 Incentive payments to DLC customers are typically in the $20-
$100 range. Assumed values are at the midpoint of this range.
Per participant annual
incentive for Space
Heating control (Large
GS)
$/participant
per year $160
$1.5/kW monthly incentive payment. For an average 15 kW of
reduction per participant, this translates into $160 total
incentive payment over seven winter months.
Per participant annual
incentive for Water
Heating control
$/participant
per year $50 $4/month incentive payment to participants. Water heaters
are controlled throughout the year.
Other Assumptions
The other key parameters needed for potential and cost analysis are program life and capacity
derating factor. Table 4-7 below describes these assumptions for DLC.
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Table 4-7 Direct Load Control Program Lifetime and Capacity Derating Factor
Assumption Unit Value Basis for Assumption
Program Life Years 8 The DLC program life is tied to the life of the switch. We
assumed the control switch life to be 8 years.
Capacity derating factor Factor 0.8
Capacity derating values generally range from 0.6 to 1.0. We
assumed the de-rating factor to be at the midpoint of this
range, with a value of 0.8.

Firm Curtailment Program
A Firm Curtailment program would target Large General Service and Extra Large General Service
customers in Avista’s service territory. Under this program, participating customers agree to
reduce demand by a specific amount or curtail their consumption to a pre-specified level. In
return, they receive a fixed incentive payment in the form of capacity credits or reservation
payments (typically expressed as $/kW-month or $/kW-year). Customers are paid to be on-call
even though actual load curtailments may not occur. The amount of capacity payment typically
varies with the firm reliability-commitment level. In addition to the fixed capacity payment,
participants receive a payment for energy reduction. Because the program includes a contractual
agreement for a specific level of load reduction, enrolled loads represent a firm resource and can
be counted toward installed capacity (ICAP) requirements. Penalties may be are assessed for
under-performance or non-performance.
Industry experiences shows that typically customers with greater than 200 kW demand
participate in this type of program. However, there are a few programs where customers with
100 kW maximum demand participate. In Avista’s case, we have lowered the demand threshold
level to include Large General Service customers with an average demand of 100 kW.
Avista could offer this program from 2016 to eligible customers in Washington and Idaho.
Customers with flexibility in their operations are attractive candidates for participation. Examples
of customer segments with high participation possibilities include large retail establishments,
grocery chains, large offices, refrigerated warehouses, water- and wastewater-treatment plants,
and industries with process storage (e.g. pulp and paper, cement manufacturing). Customers
with 24x7 operations/continuous processes or with obligations to continue providing service
(such as schools and hospitals) are not often good candidates for this option.
Typically Firm Curtailment programs in the industry are delivered through third parties who are
responsible for all aspects of program implementation including program marketing and
outreach, customer recruitment, technology installation, and incentive payments to participants.
Avista would enter into a contract with a third party to deliver a fixed amount of capacity
reduction over a certain specified timeframe. The payment to the third party would be based on
the contracted capacity reduction and the actual energy reduction during DR events.
Table 4-8 below describes the key attributes for a Firm Curtailment program that could help
guide future program design by Avista.

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Table 4-8 Firm Curtailment Program Features
Program
Attributes Description Comments
Targeted
Segment
Large General Service and Extra Large General
Service customers.
C&I customers with a minimum load of 100
kW are suitable for participation.
Resource
Availability
Program is available year round. Firm curtailment programs are available all
year round.
During the winter months of October to April,
events can be called anytime between 6 AM
to 10 AM and 4 PM to 8 PM on weekdays.
Events can be called to address dual peak
during the winter season.
During the summer months of May to
September, events can be called anytime
between 12 noon to 7 PM on weekdays.
Events can be called to address the late
afternoon and early evening peak during
summer.
Event Notification Day ahead notification via email, phone or
SMS.
Typically, events are called either a day in
advance or 30 minutes prior to the event.
Participants prefer day-ahead notification.
Maximum Annual
Event Hours 60 hours Typical specification in the industry.
Event Duration Events can range from 1-8 hours. Typical specification in the industry.
Type of Response
Non-essential load is curtailed; participants
can also shift their usage to backup
generators.
Participants can either respond manually or
have automated response strategies.
Program implementation experience.
Delivery
Mechanism
The program is delivered through a third
party.
Most utilities deliver Firm Curtailment
programs through third parties.
Delivery Cost
Delivery cost consists of two components:
1) $/kW-year capacity payment to the third-
party at $70/kW-year
2)Energy payment to the third-party at
$110/MWh;
Internal program administration cost for
Avista is assumed to be approximately 10% of
the capacity delivery cost. This increases the
overall per-kW delivery cost to $77/kW-year.
Based on third-party program
implementation experience, capacity delivery
cost is in the $60-80/kW range and energy
delivery cost is in the $75-150/MWh range.
We are using the midpoint of the ranges. We
also assume additional utility administrative
costs to account program management,
regulatory filings, internal book keeping, etc.
These costs are estimated to be 10% of the
capacity delivery cost.
Participant
Incentive
The third party is responsible for payment of
incentives to participants, so incentive cost is
part of the delivery cost.
Metering and
Communication
Requirements
Preferable to have 5-minute interval data but
15-minute or hourly data are sufficient.
Participants should be able to receive and
confirm curtailment requests in real time.
Typical specification for this type of program.

Firm Curtailment Program Assumptions
The key parameters required to estimate potential for a Firm Curtailment program are
participation rate, per participant load reduction and program costs.
Program Participation Rate
Table 4-9 below shows Form Curtailment program participation assumptions. Based on industry
experience, we estimate the program will ramp up to a steady-state participation level over three
years, which is the typical contract duration for third-party delivered programs.
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As noted in the table above, customers may use back-up generation to achieve load reduction
under this program. We estimate that roughly one fourth of the load reduction achieved through
this option would be provided by customers with backup generation.
To gain a better understanding of customer generation capabilities, Avista is conducting a
separate analysis to estimate the amount of back-up generation in the service area. The results
of this analysis may be useful to better understanding the overlap between programs targeted at
customers with backup-generation and response to a Firm Curtailment program, should Avista
offer these in the future.
Table 4-9 Firm Curtailment Program Participation Rates (% of eligible customers)
Customer Segment 2016 2017 2018 2019 2020-35
Large General Service and
Extra Large General Service 7.4% 14.9% 22.3% 22.3% 22.3%

Table 4-10 below describes the basis for the steady-state participation rate and program ramp
up assumptions.
Table 4-10 Basis for Firm Curtailment Program Participation Assumptions
Assumption Unit Value Basis for Assumptions
Steady-state
participation % of eligible customers 22.3%
Steady-state participation is the average of 50th and
75th percentile values from a dataset of 7 programs
listed in the FERC 2012 DR Program Survey database.7
We applied a 5% de-rating factor to the average
participation level to account for the fact that some
facilities with backup generators may not be eligible
for participation due to RICE/NESHAP regulations.
Program Ramp
Rate
No. of years required to
attain steady-state
participation level
3
Program implementation experience. This is based on
the typical contract duration for a third-party
delivered program.

Per Participant Load Reduction
Table 4-11 below presents the assumed per-participant load reduction for a Firm Curtailment
program and explains the basis for this assumption. Customer respond by curtailing a variety of
end uses customized for their circumstances. Some customers also use back-up generators to
achieve the load shed. Therefore, the estimates we present here may overlap with peak-load
reduction estimates Avista is developing in a separate study.
Table 4-11 Per Participant Load Reduction Assumption for the Firm Curtailment Program
Assumption Unit Value Basis for Assumption

7 http://www.ferc.gov/industries/electric/indus-act/demand-response/2012/survey.asp.
Note that Firm Curtailment programs, primarily delivered by load aggregators, are relatively new and fewer in number
than legacy DLC programs. Therefore, the dataset size for these programs is relatively small. Also, participation data is not
available for all programs listed in the survey database, which further restricted our choice set for developing participation
estimates.
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Per-participant load
reduction for Large
General Service &
Extra Large General
Service
% of
enrolled
load
21%
Weighted average impact estimates from aggregator DR programs
administered by CA utilities (Ref: 2012 Statewide Load Impact
Evaluation of California Aggregator Demand Response Programs
Volume 1: Ex post and Ex ante Load Impacts; Christensen
Associates Energy Consulting; April 1, 2013). We combined these
estimates with data from the 2012 FERC National Survey database
of DR programs.
Program Costs
Table 4-12 presents cost assumptions for the Firm Curtailment program. We developed these
cost assumptions in consultation with industry experts. The delivery cost shown in the table
represents Avista’s all-in payment to the contracted third party for delivering a fixed amount of
load reduction. It consists of two components: a capacity component and an energy component.
The third party is responsible for all program costs including incentive payments to participants.
Typically, 50 percent of the delivery cost is passed through as incentive payment to participants.
Other than the third-party delivery costs, we assumed that Avista would incur additional internal
administration costs for deploying this program.
Table 4-12 Firm Curtailment Program Cost Assumptions
Assumption Unit Value Basis for Assumption
Program
Delivery Cost
(administered
by third party)
$/kW-
year $77
Based on third-party program implementation experience,
delivery cost is expected to be in the range of $60-80/kW and we
assumed the midpoint This is inclusive of all costs to run the
program, including equipment purchase and installation costs,
maintenance costs, network communications costs, sales and
marketing costs, and payments to the customer.
Avista would also incur administrative costs for program
management, regulatory filings, internal book keeping, etc.
These costs were estimated to be 10% of the capacity delivery
costs.
Payment for
energy delivery $/kWh $0.11
Based on third-party program implementation experience,
energy dispatch prices typically fall in the $75-150/MWh range.
Our assumed price level is at the midpoint of this range.
Other Assumptions
The other key parameters needed for potential and cost analysis are program life and capacity
derating factor. Table 4-13 below describes these assumptions for the Firm Curtailment program.
Table 4-13 Firm Curtailment Program Lifetime and Capacity Derating Factor
Assumption Unit Value Basis for Assumption
Program Life Years 3 Typical contract duration for third-party delivered Firm
Curtailment programs.
Capacity derating factor Factor 0.8
Capacity derating values generally range from 0.6 to 1.0. We
assumed the de-rating factor to be at the midpoint of this
range, with a value of 0.8.

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Critical Peak Pricing
We considered Critical Peal Pricing (CPP) in our analysis. The CPP option involves significantly
higher prices during relatively short critical peak periods on event days only to encourage customers
to reduce their usage. CPP is usually offered in conjunction with a time-of-use rate, which implies at
least three time periods: critical peak, on peak and off peak. The customer incentive is a more
heavily discounted rate during off-peak hours throughout the year (relative to a standard TOU rate).
Event days are dispatched on relatively short notice (day ahead or day-of) typically for a limited
number of days during the year. Over time, event-trigger criteria become well-established so that
customers can expect events based on hot weather or other factors. Events can also be called during
times of system contingencies or emergencies. The CPP rate included here is based on a 6:1 peak
to off-peak price ratio assumption. We assumed that this rate is offered to all three C&I classes.
We considered two types of offers for CPP. With an opt-in rate, participants voluntarily enroll in
the rate. With an opt-out rate, all customers are placed on the time-varying rate but they may
oft-out and select another rate if they so desire.
Participation in CPP rates requires AMI. At this time, Avista’s Extra Large General Service
customers have sophisticated telemetry and communications infrastructure in place and may be
offered CPP rates beginning in 2016. For the other two customer classes, CPP is not available
until the AMI rollout is completed in 2020. Therefore, we assumed that CPP rates can be offered
to General Service and Large General Service customers starting in 2021.
Studies have shown that impacts from dynamic pricing program vary according to whether
customers have enabling technology to automate their response. For General Service and Large
General Service customers, the enabling technology is a programmable communicating
thermostat (PCT). For Extra Large General Service customers, the enabling technology is
Automated Demand Response (Auto-DR), implemented through energy management and control
systems.
Table 4-14 describes the features of a CPP rate. If Avista were to offer these rates, it would need
to undertake a formal rate design analysis using customer billing data to specify peak and off-
peak price levels and define the periods during which these rate would be available. Design of
these rates is outside the scope of the current study.

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Table 4-14 Critical Peak Pricing Program Features
Program
Attributes Description Comments
Targeted
Segment
General Service, Large General Service and
Extra Large General Service customers.
Customers of all sizes are eligible to
participate in a CPP program.
Type of Offer
Two types of offers are possible:
1. CPP is offered as a voluntary rate to all
customer classes with opt-in provision.
2. CPP is offered as a default rate to all
customer classes with opt-out provision.
Resource
Availability
CPP events can be called any time during the
year, based on system requirements.
Event
Notification
Day ahead event notification via email, phone,
or SMS.
Participants can be notified on either a
day-ahead or day-of basis, but day-
ahead is preferred.
Maximum
Number of CPP
Events in a Year
10 to 15
Avista can choose to call more events
during winter and fewer or none during
summer, as needed.
Maximum
Annual Event
Hours
60 hours Industry experience.
Event Duration Typical event duration is 4 hours.
Type of
Response
Load curtailment and shifting to backup
generators.
Enabling technology can enhance response. For
GS and LGS, enabling technology is assumed to
PCT.
For Extra Large General Service, enabling
technology is assumed to be Auto-DR.

Delivery
Mechanism
Avista is responsible for delivering the
program.
Participant
Incentive
The critical peak to off-peak price differential
induces participant to reduce usage during
critical peak periods. The off-peak rate is lower
than the participant's standard rate.

Metering
Requirements AMI is required for metering and settlement.

Critical Peak Pricing Assumptions
The key parameters required to estimate potential for CPP are participation rate, per participant
load reduction and costs for deploying these rates. We have described below our assumptions for
these parameters.
Program Participation Rate
We have defined participation rates for two pricing options, assuming independent offers of CPP
rates: voluntary, opt-in CPP rates to all customers and default CPP rates with opt-out.
All participation assumptions are based on Brattle’s extensive database on pricing program and
pilot experiences.
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Table 4-15 presents assumed participation rates for C&I customers in independent CPP rate
offers. Table 4-15 presents assumed participation rates in independent default rate offers for
these two options. We assumed that participation ramps up over a five-year timeframe to reach
a steady-state level. For the opt-in offer, ramp up to steady-state participation follows an “S-
shaped” diffusion curve, in which the participation growth rate accelerates over the first half of
the five year period and then slows over the second half. A similar but inverse S-shaped diffusion
curve is used to account for the rate at which customers opt-out of the default rate. CPP rates
could be offered to Extra Large General service customers in 2016. For the other two classes,
these rate are offered after AMI has been fully deployed by 2021.
Table 4-15 Opt-in CPP Participation Rates (% of eligible customers)
Option Start Yr. Yr. 1 Yr. 2 Yr. 3 Yr. 4 Yrs. 5-19 Comments
Opt-in
Standalone
participation estimates
represent average
enrollment rates in
independent rate
offerings across full
scale deployments and
market research
studies.
(Source: Brattle's
Pricing Program
Database)
General Service &
Large General Service 2021 1.8% 5.4% 10.8% 16.2% 18.0%
Extra Large General
Service 2016 1.8% 5.4% 10.8% 16.2% 18.0%
Opt-out
General Service &
Large General Service 2021 100% 96.0% 85.7% 65.8% 63.0%
Extra Large General
Service 2016 100% 96.0% 85.7% 65.8% 63.0%
Percentage of Customers with Enabling Technology in CPP Rates8
Earlier we mentioned that the load reductions from CPP participants could be enhanced through
the use of enabling technology. Table 4-16 shows the percentage of total CPP participants
equipped with enabling technology for the opt-in and opt-out cases. Enabling technology is
defined as Programmable Communicating Thermostat (PCT) for General Service and Large
General Service customers, and Auto-DR for Extra Large General Service customers.
Table 4-16 Percentage of CPP Participants with Enabling Technology (% of total
participants)
Option Yr. 1 Yr. 2 Yr. 3 Yr. 4 Yrs. 5-19
Opt-in CPP 25% 25% 25% 25% 25%
Opt-out CPP 2% 4% 6% 8% 10%
Per Participant Load Reduction
Table 4-17 below presents assumed per participant load reduction in CPP rates by customer
class. The assumed impact values are based on a 6:1 critical peak to off-peak price ratio.
Estimated load reductions with enabling technology are significantly higher than those achieved
without enabling technology use.

8 Enabling technology is not included with TOU because the peak period price signal is non-dispatchable.
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Table 4-17 Per-Participant Load Reduction in CPP Rates by Customer Class
Customer Class Value Comments
GS without enabling technology 0.6%
These impacts assume 6:1 critical
peak to off-peak price ratio.
Source: Brattle's Database on
Pricing Programs.
GS with enabling technology 12.5%
Large GS without enabling technology 7.3%
Large GS with enabling technology 11.7%
Extra Large GS without enabling technology 8.4%
Extra Large GS with enabling technology 15.6%
Program Costs
The major cost components for implementation of time varying rates are the fixed annual costs
for administering the rates and providing billing analysis. For an opt-out offer, additional call
center staff may be required during the initial program years to handle the relatively large
volume of calls from customers defaulted to these rates.
Table 4-18 below shows cost assumptions for deployment of opt-in and opt-out CPP rates. The
cost items for CPP are similar to those for TOU rates. A major portion of CPP program costs is
enabling technology purchase and installation for a fraction of the total participants.

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Table 4-18 CPP Program Cost Assumptions for Opt-in and Opt-out Offers
Item Unit Value Comments
Costs Applicable to Opt-in and Opt-out:
Program Development
Cost $/program $170,000 One FTE at $170,000 annual cost for program
development.
Annual Program
Administration Cost $/year $170,000 One FTE at $170,000 annual cost to administer the
CPP rates
Billing Analyst Cost $/year $105,000 One billing analyst at $105,000 in the call center to
provide customer service.
Enabling Technology
Cost
$/GS
participant $375 We assumed per participant PCT capital and
installation cost is the same as DLC.
$/LGS
participant $550 We assumed per participant PCT capital and
installation cost is the same as DLC.
$/kW load
reduction for
XLGS
$200 Based on Auto-DR enablement costs from a CA
utility.
Billing system upgrade $ $7.5
million Avista provided this estimate
Additional costs applicable to Opt-in:
Per Customer Annual
Marketing/Recruitment
Cost
$/new GS
participant $100 Same as DLC Program marketing cost.
$/new LGS
participant $133 For LGS customers, costs are assumed to be a third
higher than costs for GS customers.
$/new XLGS
participant $250 For XLGS customers, costs are assumed to be
approximately double the costs for LGS customers.
Additional costs applicable to Opt-out:
Additional call center
staff
$/yr. for first
two program
years
$255,000
We assumed that 3 additional call center staff at
$85,000 each annual cost to handle customer calls
for an opt-out rate.
Per Customer Annual
Marketing/Recruitment
Cost
$/new GS
participant $10
For opt-out CPP rates, these costs are assumed to be
one-tenth of the costs for opt-in CPP rates.
$/new LGS
participant $15
$/new XLGS
participant $25
Other Assumptions
The other key parameters needed for potential and cost analysis are program life and capacity
derating factor. Table 4-19 below describes these assumptions for the pricing options.
Table 4-19 Program Lifetime and Capacity Derating Factor for Pricing Options
Item Unit Value Basis for Assumption
Program Life Years 20 Program life is tied to the life of the interval meter.
Capacity derating factor Factor 0.5
Load reductions from pricing options are less firm than load
reductions from non-pricing options. Therefore we
assumed capacity derating factor to be lower at 0.5.

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Other Cross-cutting Assumptions
In addition to the above program-specific assumptions, there are three that affect all programs:
 Discount rate. We used a nominal discount rate of 7% to calculate the net present value
(NPV) of costs over the useful life of each DR program. All cost results are shown in nominal
dollars. We assumed 1.86% inflation rate for escalating costs.
 Line losses. Avista provided a line loss factor of 6.5% to convert estimated demand savings
at the customer meter level to demand savings at the generator level. In the next section,
we report our analysis results at the generator level.
 Snapback. In this context, snapback refers to the amount of energy savings that result from
DR programs. We have assumed in this analysis that the amount of kWh savings from DR
programs is negligible since most of the reduction during events is typically shifted to other
times of day, either before or after the event.

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SECTION 5
DR Potential and Cost Estimates
This section presents analysis results on demand savings and cost estimates for DR programs.
We conducted an independent assessment of DR options which considered each option as a
standalone offering. As such, this approach does not account for participation overlaps among
DR options targeted at the same customer segment and therefore savings and cost results for
individual DR options are not additive. The standalone analysis results help provide a
comparative assessment of individual DR options and costs and are useful for selection of DR
options in a program portfolio.
At the very end of this section, we present high-level results in 2035 after considering integrated
effects that occur if more than on DR option is offered to Avista customers.
All potential results presented in this section represent capacity savings in terms of equivalent
generation capacity after derating factors have been applied.
Potential Results
Figure 5-1 and Table 5-1 show demand savings from individual DR options for selected years of
the analysis. These savings represent combined savings from DR options in Avista’s Washington
and Idaho service territories.
Key findings include:
 The firm curtailment option has highest savings potential at approximately 2.7-2.8% of
estimated C&I peak demand from 2020 onward. We assumed that Avista offers this option to
Large General Service and Extra Large General Service customers in 2016 and participation
ramps up to a steady state by 2019. Therefore potential remains almost steady from that
time onward.
 An opt-out CPP offer has second highest savings potential at approximately 2% of C&I peak
demand from 2025 onward. We assumed that Avista could offer this as a default rate to all
customer classes after AMI deployment is completed in 2020. Participation ramps up over a
five-year time frame and reaches a steady state by 2025. Only Extra Large General Service
customers are assumed to have the necessary metering infrastructure in place and could be
offered a CPP rate from 2016.
 DLC for General Service and Large General Service customers provides third highest savings
potential at approximately 1% of C&I peak demand from 2020 onward. This is offered in
2016 and ramps up to steady-state participation levels by 2020.
 Savings potential from opt-in CPP are approximately 0.7% of the system peak from 2025.

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Figure 5-1 Summary Potential Analysis Results for Avista (MW @Generator)

Table 5-1 Achievable DR Potential by Option for Avista (MW @Generator)
2016 2020 2025 2030 2035
Total System Peak (MW) 1,718 1,768 1,828 1,891 1,995
Weather Sensitive Peak (MW) 1,590 1,640 1,700 1,763 1,827
Estimated C&I Peak (MW) 610 622 630 638 649
Achievable Potential (MW)
Direct Load Control 0.64 6.48 6.68 6.91 7.16
Firm Curtailment 5.80 17.46 17.42 17.42 17.46
Opt-in Critical Peak Pricing 0.13 1.40 4.30 4.33 4.38
Opt-out Critical Peak Pricing 6.27 4.38 12.93 13.01 13.12
Achievable Potential (% of C&I Peak)
Direct Load Control 0.10% 1.04% 1.06% 1.08% 1.10%
Firm Curtailment 0.95% 2.81% 2.77% 2.73% 2.69%
Opt-in Critical Peak Pricing 0.02% 0.23% 0.68% 0.68% 0.68%
Opt-out Critical Peak Pricing 1.03% 0.70% 2.05% 2.04% 2.02%

0
5
10
15
20
25
2016 2020 2025 2030 2035
Potential
(MW)
Direct Load Control Firm Curtailment Opt-in Critical Peak Pricing Opt-out Critical Peak Pricing
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Table 5-2 and Table 5-3 show demand savings by individual DR option for Washington and
Idaho.
Table 5-2 Achievable DR Potential by Option for Washington (MW @Generator)
2016 2020 2025 2030 2035
Total System Peak (MW) 1,718 1,768 1,828 1,891 1,995
Weather Sensitive Peak (MW) 1,590 1,640 1,700 1,763 1,827
Estimated C&I Peak (MW) 610 622 630 638 649
Achievable Potential (MW)
Direct Load Control 0.39 4.00 4.12 4.26 4.42
Firm Curtailment 3.78 11.36 11.11 10.87 10.63
Opt-in Critical Peak Pricing 0.09 0.91 2.69 2.65 2.61
Opt-out Critical Peak Pricing 4.08 2.83 8.15 8.01 7.87
Achievable Potential (% of C&I Peak)
Direct Load Control 0.06% 0.64% 0.65% 0.67% 0.68%
Firm Curtailment 0.62% 1.83% 1.76% 1.70% 1.64%
Opt-in Critical Peak Pricing 0.01% 0.15% 0.43% 0.41% 0.40%
Opt-out Critical Peak Pricing 0.67% 0.46% 1.29% 1.26% 1.21%

Table 5-3 Achievable DR Potential by Option for Idaho (MW @Generator)
2016 2020 2025 2030 2035
Total System Peak (MW) 1,718 1,768 1,828 1,891 1,995
Weather Sensitive Peak (MW) 1,590 1,640 1,700 1,763 1,827
Estimated C&I Peak (MW) 610 622 630 638 649
Achievable Potential (MW)
Direct Load Control 0.24 2.48 2.56 2.64 2.74
Firm Curtailment 2.02 6.10 6.31 6.55 6.82
Opt-in Critical Peak Pricing 0.05 0.49 1.61 1.69 1.78
Opt-out Critical Peak Pricing 2.19 1.54 4.78 5.00 5.25
Achievable Potential (% of C&I Peak)
Direct Load Control 0.04% 0.40% 0.41% 0.41% 0.42%
Firm Curtailment 0.33% 0.98% 1.00% 1.03% 1.05%
Opt-in Critical Peak Pricing 0.01% 0.08% 0.26% 0.26% 0.27%
Opt-out Critical Peak Pricing 0.36% 0.25% 0.76% 0.78% 0.81%

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Cost Results
Table 5-4 presents total utility costs for deployment of individual DR options over the 2016-2035
timeframe. It also shows the average annual cost and the levelized costs per kW of equivalent
generation capacity over 2016-2035. We show 2035 savings potential from DR options for
reference purposes.
Table 5-4 DR Program Costs and Potential
DR Option 2035 MW
Potential
2016 – 2035
Cumulative
Utility Spend
(Million $)
2016 – 2035 2016 – 2035
Average Spend
per Year Levelized Cost
($/kW-year)
(Million $)
Direct Load Control 7.16 $16.07 $0.80 $143.82
Firm Curtailment 17.46 $40.68 $2.03 $118.59
Opt-in Critical Peak Pricing 4.38 $25.61 $1.28 $432.65
Opt-out Critical Peak Pricing 13.12 $26.69 $1.33 $109.86

Key findings include:
 The Firm Curtailment option could deliver highest savings at approximately $118/kW-year
cost. The cumulative costs to Avista over a 20 year planning periods for realizing 17 MW of
savings in 2035 is around $40 million. Capacity-based and energy-based payments to the
third party constitutes the major cost component for this option. In addition, Avista would
incur a relatively small amount of internal administrative costs for managing the third party.
 Opt-out CPP has lowest levelized cost among all DR options. It could deliver 13 MW in 2035
at $109/kW-yr. We estimate that Avista would need to spend approximately $26 million over
2016-2035 to deploy a default CPP rate to all customer classes. Enabling technology
purchase and installation costs for enhancing customer response is a large part of CPP
deployment costs.
 Opt-in CPP has a cost of $432/kW-year and is significantly higher than opt-out CPP. The
major cost component for an opt-in CPP offer cost is the annual fixed program administration
cost for administering the rate. This cost is spread over the smaller number of customers
who choose to participate in this rate.
 Direct load control provides the third highest savings, 7 MW in 2035, at a relatively high cost
of $144/kW-year. The significant cost components for DLC program implementation are
associated with purchase and installation of enabling technology and with program marketing
and outreach activities. There are also additional permitting and licensing fees that Avista
customers must incur.
Integrated Results
The above analysis assumes that the programs are offered on a stand-alone basis. That is, only
one program, and not the others, is offered to Avista customers. If Avista offered more than one
program, then the potential for double counting exists. To address this possibility, we created a
participation hierarchy to define the order in which the programs are taken by customers. Then
we computed the savings and costs under this scenario. We assumed the following hierarchy:
1. Direct load control
2. Firm curtailment
3. Opt-in CPP or Opt-out CPP
Table 5-5 shows the potential estimates in 2035, as well as the costs, if more than one program
is offered. The savings and costs for DLC remain unchanged, since it is first in the hierarchy.
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However, the savings for Firm Curtailment and CPP are slightly lower as are the cumulative and
average program costs. Levelized costs for Firm Curtailment are slightly lower as well, but the
levelized cost for CPP are higher because the program costs are spread across a smaller amount
of savings.
Table 5-5 DR Program Costs and Potential - Interactive
DR Option 2035 MW
Potential
2016 – 2035
Cumulative
Utility Spend
(Million $)
2016 – 2035 2016 – 2035
Average Spend
per Year Levelized Cost
($/kW-year) (Million $)
Direct Load Control 7.16 $16.07 $0.80 $143.82
Firm Curtailment 16.57 $38.65 $1.93 $118.52
Opt-in Critical Peak Pricing 3.35 $25.27 $1.26 $555.77
Opt-out Critical Peak Pricing 9.90 $26.32 $1.32 $141.03

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APPENDIX A
Literature Review
Before we performed the analysis of demand response (DR) for the Avista service territory, we
conducted a literature review to provide Avista with an overview of what is already being done in
the industry on DR. This review was originally provided to Avista under separate cover.
Introduction
Over the past decade, DR has evolved in many ways and a review and research of DR programs
will provide Avista with a good overview and basis for the remainder of the study.
We have reviewed information available from national surveys of DR programs, most notably the
FERC DR program survey database9. This national survey database is the most comprehensive
data source on DR programs available in the industry, with a list of more than 1,500 DR
programs and rate options offered to residential, commercial and industrial (C&I) and irrigation
customers. The database has information on type of DR program and rate option, the type of
entities offering the program, end-use equipment being controlled, participation requirements,
number of customers enrolled, and realized load reduction amounts. In our research, we have
covered all types of DR programs offered to residential and C&I customers.
We have combined the information from this data source with other relevant national data
sources to arrive at key program characteristics, including performance metrics such as program
participation rates and load reduction impacts. These data sources include: EIA Form 861
database10, FERC Form 1 filing data11, and the FERC National Assessment of Demand Response
Potential Study12. We have also reviewed program reports, evaluation studies, and other types of
industry publications to collect information about the different DR program types.
We have subdivided the relevant program information into two broad categories of program
types: non-pricing and pricing programs. Non-pricing programs include Direct Load Control
(DLC), Firm Curtailment programs, and Non-Firm Curtailment programs. Pricing options include
Critical Peak Pricing (CPP) and Real Time Pricing (RTP).
We have identified a list of DR programs that we consider relevant for Avista and from that list
we have selected a number of programs for in-depth research. For these programs, we describe
the key characteristics including targeted customer segments and loads, event trigger,
notification process, response requirements, timing and frequency of events, event duration,
type of enabling technology for response, incentive structure, metering and other infrastructure
requirements.
In addition to specific program information, we discuss items constituting benefits and costs for
DR programs and the overall approach used for assessing cost-effectiveness of programs. At the
end, we also include descriptions on commonly used methods for estimating program impacts.
This appendix consists of the following parts:
 A description of the approach we followed to identify relevant DR programs and to select a
list of programs for in-depth research.

9 2012 Survey on Demand Response and Advanced Metering, available at
http://www.ferc.gov/industries/electric/indus-act/demand-response/2012/survey.asp 10 http://www.eia.gov/electricity/data/eia861/ 11 http://www.ferc.gov/docs-filing/forms/form-1/data.asp 12 http://www.ferc.gov/legal/staff-reports/06-09-demand-response.pdf
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 Program descriptions for each selected program type
 Cost-effectiveness approaches for DR
 Impact estimation for DR
Research Approach
We first developed a list of proposed DR options by customer class. Then we identified and
described representative programs for each type of program.
Proposed List of DR Options by Customer Class
We developed a comprehensive list of DR options for Avista’s consideratio n in Table A-1 below.
The customer class definitions are based on Avista's rate schedule information taken from
Avista's System Load Research project, dated March, 2010. We have included two broad
categories of DR options: non-pricing options and pricing options. In addition, we have included
DR options for providing ancillary/load following services.
Table A-6 Proposed List of DR Options
Category Option Applicable Customer Class
Non-pricing
Direct Load Control
Residential
General Service (GS)
Large General Service (LGS)
Curtailment- Firm Large General Service (LGS)
Extra Large General Service (XLGS)
Curtailment- Non-firm Large General Service (LGS)
Extra Large General Service (XLGS)
Pricing
Time-of-Use Rates
Residential
General Service (GS)
Large General Service (LGS)
Extra Large General Service (XLGS)
Critical Peak Pricing
Residential
General Service (GS)
Large General Service (LGS)
Extra Large General Service (XLGS)
Real Time Pricing Extra Large General Service (XLGS)
Ancillary Services /
Load Following
Ancillary Services / Load
Following
Residential
General Service (GS)
Large General Service (LGS)
Extra Large General Service (XLGS)

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Approach for Selecting Representative Programs for Further Research
To develop the list of programs, we followed the steps listed below:
1. Identify the universe of relevant DR programs,
2. Develop criteria for selecting representative programs to research in depth, and
3. Apply selection criteria to develop the list of recommended programs for further research.
We describe each of these steps in detail below.
Identify a List of Relevant DR Programs
To identify relevant programs for Avista, we reviewed the DR program information available in
the 2012 FERC National DR program survey database.13 This is the most comprehensive national
database of DR programs in the industry.
We prioritized our review to select winter-peaking utilities to align with Avista’s demand
reduction objectives during the winter season. Because these are relatively few, we also included
summer-peaking utilities with significant winter demand. To help identify these utilities, we
calculated the winter peak as a percentage of the summer peak, and selected those utilities for
whom their winter peak was at least 65 percent of the summer peak.14 We present the universe
of relevant DR offerings in Table A-2 through Table A-7.

13 2012 Survey on Demand Response and Advanced Metering, available at
http://www.ferc.gov/industries/electric/indus-act/demand-response/2012/survey.asp 14 We obtained summer and winter peak demand data, by utility, from EIA Form 861 for 2012.

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Table A-2 Relevant Direct Load Control Programs
Offering Entity State Sector Winter Peak as %
of Summer Peak
Adams Electric Cooperative Inc. PA Residential 97.6%
BPA- City of Port Angeles WA Residential 120%
BPA- Emerald People's Utility District (EPUD) OR Residential 120%
BPA- Orcas Power and Light Coop WA Residential 120.3%
BPA-Central Electric Cooperative OR Residential 120.3%
Central Alabama Electric Coop AL Residential 105.5%
Connexus Energy MN Residential 65.3%
Crow Wing Cooperative Power & Light Comp MN Residential 68.1%
Duke Energy Carolinas, LLC NC Residential 90.4%
Florida Power & Light Co FL Residential 83.6%
Jackson Energy Coop Corp - (KY) KY Residential 120.6%
Kentucky Utilities Co KY Residential 97.0%
Lake Country Power MN Residential 185.8%
Minnesota Power Inc. MN Residential 99.8%
Northern Virginia Electric Coop VA Residential 70.6%
Otter Tail Power Co ND Residential 121.8%
Puget Sound Energy Inc. WA Residential 135.1%
Santee Electric Coop, Inc. SC Residential 101.9%
South Central Power Company OH Residential 89.3%
Southeastern Electric Coop Inc. - (SD) SD Residential 79.3%
United Electric Coop, Inc. - (PA) PA Residential 100.5%
Otter Tail Power Co ND C&I 121.8%
Duke Energy Carolinas, LLC NC C&I 90.4%
Clay-Union Electric Corp SD C&I 77.3%
Duke Energy Progress- SC SC C&I -
Table A-3 Relevant Firm Curtailment Programs
Offering Entity State Sector Winter Peak as %
of Summer Peak
City of Burlington Electric - (VT) VT C&I 91.3%
Duke Energy-Carolinas NC C&I -
Duke Energy-Kentucky KY C&I -
Louisville Gas & Electric and Kentucky Utilities
Company KY C&I 97.0%
PJM Demand Response PA C&I -
PJM Demand Response OH C&I -
Tampa Electric Co FL C&I 90.2%
Tennessee Valley Authority AL C&I -
Tennessee Valley Authority TN C&I 90.1%
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Table A-4 Relevant Non-Firm Curtailment Programs
Offering Entity State Sector Winter Peak as %
of Summer Peak
Duke Energy-Carolinas NC C&I
Duke Energy-Kentucky KY C&I -
New York State Electric and Gas NY C&I 87%
PJM Demand Response PA C&I -
PJM Demand Response OH C&I -
Table A-5 Relevant Critical Peak Pricing Programs
Offering Entity State Sector Winter Peak as %
of Summer Peak
Gulf Power Co15 FL Residential 91%
Sioux Valley SW Electric Coop. ND Residential 94.5%
Southern California Edison Co. CA C&I 65.9%
Tampa Electric Co. FL R 90.2%

Table A-6 Relevant Real Time Pricing Programs
Offering Entity State Sector Winter Peak as %
of Summer Peak
Duke Energy Carolinas, LLC NC C&I 90.4%
Duke Energy Ohio, Inc. OH C&I 78.7%
Georgia Power Co GA C&I 85.8%
Gulf Power Co FL C&I 91.0%
Otter Tail Power Co ND C&I 121.8%
West Penn Power Company PA C&I 91.7%
Table A-7 Relevant Ancillary Services/Load Following Programs
Offering Entity State Sector Winter Peak as %
of Summer Peak
BPA- Mason County PUD No. 3 WA Res 120%
BPA- City of Port Angeles WA C&I 120%
BPA-Eugene Water and Electric Board OR C&I 120%

Table A-8 below shows the number of programs included by DR option type.

15 Gulf Power Company’s CPP program was not listed in the FERC survey database. Therefore we obtained program information from
outside sources.
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Table A-8 Number of Relevant DR Programs by Option
Category Option Number of Programs
Non-pricing
Direct Load Control 34
Curtailment- Firm 6
Curtailment- Non-firm 2
Pricing
Time-of-Use Rates TOU rate offerings by various
utilities16
Critical Peak Pricing 4
Real Time Pricing 6
Ancillary Services / Load Following Ancillary Services / Load Following 3

Develop Criteria for Selecting Representative Programs
Once we identified the list of relevant programs, we developed criteria to select representative
programs for detailed investigation. We considered the following criteria:
 Program size and maturity: We identified the size of the program in terms of number of
customers enrolled, based on FERC 2012 DR survey data. We present available enrollment
data in the “All Programs” worksheet. We considered only mature programs with a sizeable
number of customers enrolled.
 Average retail rate of the utility relative to Avista's rate: We compared each utility's average
retail rate with Avista's rate to screen out utilities with rates much higher than Avista's.
 Pacific Northwest region experience: We included all DR initiatives from the Pacific Northwest
region, even though these were mostly pilots.
Apply Selection Criteria to Develop a List of Programs for Further Research
As a last step in the process, we applied the selection criteria outlined above to the list of
relevant programs presented above. Table A-9 shows the selected programs by DR option type.

16 We found that a very large number of utilities across the states included in our list offered TOU tariffs. We did not explicitly record
the number of TOU rate offerings by these utilities.
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Table A-9 Selected Programs
Offering Entity State Sector Scale
Winter
Peak as %
of Summer
Peak
Retail Rate
Difference
with Avista
(%)
No. of
Customers
Enrolled
Direct Load Control Programs
BPA- City of Port Angeles WA Res Pilot 120% - 35
BPA- Emerald People's Utility
District (EPUD) OR Res Pilot 120% - 200
Puget Sound Energy Inc WA Res Pilot 135% 19.3% 528
Otter Tail Power Co ND Res Program 122% 0.4% 6,479
Duke Energy Carolinas, LLC NC Res Program 90.4% 17.7% 3,963
South Central Power Company OH Res Program 89.3% 32.6% 20,000
Florida Power & Light Co FL Res Program 83.6% 19.8% 799,812
Minnesota Power Inc. MN Res Program 99.8% 5.7% 7,217
Crow Wing Cooperative Power &
Light Company MN Res Program 68.1% 23% 8,625
Clay Union Electric SD C&I Program 77.3% - 591
Otter Tail Power Co ND C&I Program 121.8% -23.3% 1,579
Firm Curtailment Programs
Tampa Electric Co FL C&I Program 90.2% 15.6% 94
Tennessee Valley Authority TN C&I Program 90.1% - 13917
Louisville Gas & Electric/
Kentucky Utilities Company KY C&I Program 97% -22.7% -
Non-Firm Curtailment Programs
New York State Electric and Gas NY C&I Program 87% 0.4% 106
Critical Peak Pricing Programs
Gulf Power Co18 FL Res Program 91% 39% 10,000
Southern California Edison Co. CA C&I Program 65.9% 47.4% 3,255
Real Time Pricing Programs
Georgia Power Company GA C&I Program 85.8% -9.1% 2,033
Ancillary Services/Load Following Pilots
BPA-City of Port Angeles WA C&I Pilot 120% - -
BPA-Mason County PUD No. 3 WA Res Pilot 120% - -

Table A-10 shows the number of selected programs by DR option.

17 TVA offers this program to its member utilities. Enrollment data presented here is for Memphis Light, Gas, and Water Division
(MLGW), which has the highest enrollment level among all TVA members. 18 Gulf Power Company’s CPP program was not listed in the FERC survey database. Therefore we obtained program information from
outside sources.
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Table A-10 Number of Selected DR Programs by Option
Category Option Number of Programs
Non-pricing
Direct Load Control 11
Firm Curtailment 3
Non-firm Curtailment 1
Pricing Critical Peak Pricing 2
Real Time Pricing 1
Ancillary Services / Load Following Ancillary Services/Load Following 3

Direct Load Control Programs
With Direct Load Control (DLC) programs, the utility directly controls specific end-uses such as
electric space heating, cooling, water heating, and pool pumps. In exchange, the customer
receives an incentive payment or bill credit. Operation of DLC typically occurs during times of
high peak demand or supply-side constraints. During an event, participants’ equipment is
controlled either by a one-way remote load control switch or by a Programmable Communicating
Thermostat (PCT).
General Program Characteristics
Most of the legacy DLC programs offered by utilities nationwide target summer cooling load.
These programs target central air conditioning which has a fairly low saturation in the Avista
service area. Programs that target space heating load during winter and water heating load
throughout the year are much fewer in number than summer DLC programs. In our research, we
have specifically included programs that target space heating and/or water heating loads, since
Avista is primarily interested in DLC programs for addressing winter peak reduction.
We found a variety of DLC programs that control electric space heating and water heating, such
as:
 Programs that cycle and shut off equipment during event hours.
 Programs that target space heating and water heating equipment with thermal storage
capabilities that enable load shifting to off-peak hours.
 Programs that target specifically space heating and water heating systems with dual fuel
backup that enable these systems to use alternate fuels for providing service during control
periods.
Table A-11 below summarizes some of the characteristics of Direct Load Control programs that
are common across program offerings.

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Table A-11 Summary of Key Direct Load Control Program Characteristics
Program Attributes Description
Targeted segments
 Residential
 Small and medium sized C&I customers (typically customers with less than
100 kW maximum demand)
DR Strategies
 Cycling space heating equipment.
 Turning off equipment (water heating and space heating) during control
periods.
 Shifting usage to off-peak hours using end-use devices with thermal
storage features.
 Shifting usage from electricity to natural gas using dual fuel backup for
space heating and water heating
Enabling Technology Load control switch or programmable thermostat
Event Notification Event notification does not apply, since end-use equipment is directly
controlled by the utility.
Event Duration
 Varies widely by program: from 4 to 14 hours.
 Longer event duration found for programs that control equipment with
thermal storage or dual fuel backup.
Incentive structure
 Participants are often offered a fixed annual bill credit for each type of
equipment being controlled.
 In cases where the equipment has dual fuel backup, participants are
placed on a separate rider with discounted tariffs, as compared to their
normal rates.
 Participants sometimes receive a rebate for purchasing equipment with
thermal storage features.
Specific Pilot and Program Examples
Below are summaries of the specific characteristics of the DLC pilots and programs we
researched. We have included information from the Pacific Northwest pilot initiatives, since these
are likely to be relevant for Avista. For all other areas, we have included only program
experiences.
Puget Sound Energy’s Direct Load Control Pilot
Puget Sound Energy conducted a residential DLC pilot during 2010-2011. The pilot was
conducted on Bainbridge Island, located in the western portion of the utility’s service area. Table
A-12 below lists specific characteristics of the pilot program.

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Table A-12 Puget Sound Energy’s Residential DLC Pilot
Attributes Description
Targeted Segment Residential customers with electric space heating and cooling, and water
heating.
Controlled End-uses
 Electric water heating and space heating equipment were controlled
during winter. Space heating equipment included heat pumps, central
electric furnaces, and baseboard wall heaters.
 Electric water heating and heat pumps (in cooling mode) were controlled
during summer.
Enabling Technology for
Control
 Load control switches used for controlling water heaters.
 Load control switches with adaptive algorithm used for controlling electric
space heating.
 Programmable communicating thermostat used for controlling space
cooling.
Communication
Infrastructure Two way communication using broadband.
Incentive Payment Participants received an annual $50 incentive, as long as they participated in
more than 50% of curtailment events.
Impact Findings
Space heating
 Among the three electric space heating technologies, controlling heat
pumps provided the highest level of load reductions, especially during
winter mornings.
 Impacts per device for heat pumps ranged from 2.88 kW in the morning to
1.21 kW in the afternoon.
 Impacts per device for electric furnaces ranged from 1.88 kW in the
morning to 1.71 kW in the afternoon.
 Impacts per device for baseboards ranged from 0.18 kW in the morning to
0 kW in the afternoon.
Water heating
 Water heater control was found to be the most effective means for
achieving winter demand reduction, especially during winter mornings.
During afternoon control, snapback impact was observed to be greater
than DR impact.
 Water heater winter impacts per device ranged from 0.77 kW in the
morning to 0.49 kW in the afternoon.
Key Findings from the Pilot
 Overall Customer Satisfaction. Although overall customer satisfaction was reported to be
high for the pilot, an evaluation study points to a number of factors that affected customer
satisfaction. These factors include:
o Highest level of customer dissatisfaction was related to equipment technical issues, such
as:
 Network connectivity problems
 Difficulties in PCT operation and lack of “easy to use” features for the thermostat
 Safety concerns related to the specific PCT brand used in the pilot, which faced a product
recall
 Equipment installation problems, especially with the digital gateway.
 Technical difficulties related to operation of the load control device for space heaters.
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o Very few participants experienced discomfort when their devices were being controlled,
except heat pump participants. More than half of the heat pump participants experienced
discomfort and had to take alternative actions to stay warm during events. Snapback in
demand, after the event, was observed for these participants.
o Participants had low awareness of the opt-out feature and some expressed dissatisfaction
with loss of control over heating.
o Participants expressed dissatisfaction with aesthetic impacts resulting from the
installation of control and communication hardware inside their homes.
o Participants did not have sufficient instructions/guidance to operate the installed
equipment.
o Use of multiple control technologies complicated installation procedures and led to
technical problems.
 Program Marketing and Customer Communication. Pilot promotional letter and
newspaper articles were effective communication channels for informing participants about
the pilot. Strong support of the pilot by local community groups, extensive local media
promotion, and individual social networking contributed to a higher enrollment rate than
typically experienced with utility pilots.
 Motivation for Participation. The strongest motivation for participation was
environmental/altruistic reasons, rather than achieving monetary savings.
 Level of Incentive Payment. Participants perceived the annual incentive payment to be
sufficient.

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BPA- City of Port Angeles Voluntary Peak Power Project
The City of Port Angeles Voluntary Peak Power project in northern Washington constitutes one of
several pilots that BPA is currently implementing to test Direct Load Control with multiple end-
uses. The pilot incorporates a number of unique and innovative features and therefore, learning
from the pilot experience is likely to be of significance for Avista.
The pilot involves control of multiple end-uses along with water heating and space heating
equipment. The pilot is testing space heating equipment with thermal storage features. All pilot
participants have AMI installed and therefore, control and communications techniques leverage
the AMI backbone.
Table A-13 below lists specific characteristics of the pilot. Additional information on pilot
performance was not available.
Table A-13 BPA-City of Port Angeles Voluntary Peak Power Project
Attributes Description
Targeted Segment Residential customers with electric space heating and water heating.
Controlled End-uses
 Electric water heating
 Electric space heating along with multiple end-uses. Space heating
equipment includes room heaters and central electric furnaces with
thermal storage capability (ceramic bricks).
Enabling Technology for
Control
 A load control device wired into the water heater's electrical control
system is used for WH control.
 A smart thermostat is used for controlling electric space heating. It is
equipped with Home Area Network (HAN) connectivity and can be used to
control multiple end-uses, such as appliances.
 Control of electric space heating (room heaters or central electric
furnaces) with thermal storage involves drawing electricity during low
demand periods and storing it in ceramic bricks, which can heat over
1,500 degrees F and are sealed inside the unit. A variable speed fan
automatically circulates heat throughout the room. Participants control
the temperature using a programmable thermostat.
Metering and
Communication
Infrastructure
All pilot participants have AMI installed.
Incentive payment Participants receive $120 for participation, along with free control devices.
Impact findings NA

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BPA- Emerald People’s Utility District Direct Load Control Pilot
BPA is undertaking a DLC pilot with Emerald People’s Utility District to test control of space
heating and water heating technologies with thermal storage capabilities. The overall objective of
the pilot is to develop load control strategies that can be used for integration with renewable
resources. This is one of the few pilots that are being conducted to address renewable
integration challenges. Learning from these pilot experiences is likely to be useful for Avista,
since wind generation is a significant portion of its supply fleet.
Table A-14 below lists specific characteristics of the pilot program. Additional information on pilot
performance was not available.
Table A-14 BPA-Emerald People’s Utility District Direct Load Control Pilot
Attributes Description
Targeted Segment Residential customers with electric space heating and water heating.
Controlled End-uses  Electric water heating with thermal storage capabilities
 Electric space heating with thermal storage capabilities.
Enabling Technology
 Thermal storage systems store electrical energy in well insulated ceramic
brick cores.
 Built-in microprocessor-based control systems regulate the charging level
and rate.
 Storage occurs as utilities signal the unit to charge with available
renewable, off-peak energy, or in response to other needs of the grid.
Storage equipment has the ability to take on "extra" storage during
periods when excess energy is available (e.g., when the wind fleet ramps
up rapidly) or to turn off when the power supply is limited (e.g., when the
wind fleet ramps down).
Metering and
Communication
Infrastructure
NA
Incentive Payment NA
Impact Findings NA

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Otter Tail Power Company Direct Load Control Program
Otter Tail Power Company offers a direct control program for space heating and water heating
loads with dual fuel during the winter season. The program also offers an option to control
cooling loads on air-source heat pumps during summer. In addition, the utility controls water
heaters without dual fuel backup by turning off the water heater during event hours.
Table A-15 below lists specific characteristics of the program.
Table A-15 Otter Tail Power Company’s DLC Program
Attributes Description
Targeted Segment Residential and commercial customers with electric space heating and water
heating.
Controlled End-uses
 Space heating and water heating with alternate fuel backup controlled
during winter
 Space cooling controlled during summer: air-source heat pumps in cooling
mode. The units are cycled during summer with 50% control strategy (15
minutes on and 15 minutes off)
Enabling Technology Load control switch
Event Duration  Heating loads on dual fuel may be controlled up to 24 hours a day
 Water-heating loads may be controlled up to 14 hours a day
Metering and
Communication
Infrastructure
NA
Incentive Payment
There is no separate incentive payment for participating in the program.
Customers with dual fuel option are placed on a separate rider with the
following components:
 A fixed monthly charge of $7
 Summer electricity rate: 3.659 cents/kWh
 Winter electricity rate: 3.451 cents/kWh
 Penalties apply for not being able to shift load during control periods to
alternate fuels. These are:
o 38.61 c/kWh during summer months
o 12.92 c/kWh during winter months
Customers with water heater control only are placed on a separate rider with
the following components:
 A fixed monthly charge of $2
 Summer electricity rate: 5.773 cents/kWh
 Winter electricity rate: 5.638 cents/kWh
Impact Findings NA

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Minnesota Power Direct Load Control Program
This program is similar to Otter Tail Power Company’s Direct Load Control program with the dual
fuel component. In addition, the company also offers an option for controlling electric space
heating units with thermal storage. Table A-16lists specific characteristics of the program.
Table A-16 Minnesota Power’s DLC Program
Attributes Description
Targeted Segment Residential and commercial customers with electric space heating and water
heating.
Controlled End-uses
 Space heating and water heating with alternate fuel backup controlled
during winter.
 Space heating with thermal storage capability controlled during winter.
Space heating equipment includes heat pumps, central furnaces, and a
variety of room heating devices.
Enabling Technology Load control switch
Event Duration Not defined
Metering and
Communication
Infrastructure
NA
Incentive Payment There is no separate incentive payment for participating in the program.
Participants are placed on separate riders with differential rates.
Evaluation Findings NA

Duke Energy Carolinas Direct Load Control Program
This is a winter load control program targeting electric space heating and water heating end-
uses. Table A-17 lists specific characteristics of the program.
Table A-17 Duke Energy Carolinas’ DLC Program
Attributes Description
Targeted Segment Residential customers with electric space heating and water heating.
Controlled End-uses  Space heating - central electric heat pump units with strip heat
 Water heating – water heaters with at least 30 gallons capacity
Enabling Technology Load control switch
Event Duration
 Both space heating and water heating can be controlled up to 4 hours
during an event.
 Space heating can be controlled up to a maximum of 60 hours annually
Metering and
Communication
Infrastructure
NA
Incentive Payment Customers receive an annual bill credit of $25 each for space heating and WH
control, in addition to $25 for signing up (applied to each equipment).
Evaluation Findings NA
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Florida Power and Light’s Direct Load Control Program
Florida Power and Light’s “On Call” program is one of the largest DLC programs in the nation.
The program controls multiple end-uses and targets both summer and winter loads.
Table A-18 lists specific characteristics of the program.
Table A-18 Florida Power and Light’s DLC Program
Attributes Description
Targeted Segment Residential customers with electric space hating and water heating.
Controlled End-uses
 Central heating
 Electric water heating
 Central air conditioning
 Pool pumps
Enabling Technology Load control switch
Event Duration
There are two options under the program. One is the “Cycle Option”, and the
other is the “Extended Option.” The event duration differs for these two
options.
 Under the Cycle Option, the central heater is turned off for 15 minutes,
every half hour.
 Under the Extended Option, all controlled equipment can be turned off
for up to 4 hours.
Metering and
Communication
Infrastructure
Power line communication with two-way communications feature.
Incentive Payment
 Under the Cycle Option, participants receive a $10 annual bill credit for
controlling central heat.
 Under the Extended Option, participants receive a $20 annual bill credit
for controlling central heat, and an $18 annual credit for water heater
control.
Evaluation Findings NA

19 The Business On Call program targeting commercial customers controls cooling load only during the summer.
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Crow Wing Cooperative’s Direct Load Control Program
Crow Wing Electric Cooperative’s direct load control program utilizes dual fuel backup for
controlling electric heat during winter. The utility also controls water heaters and space heating
equipment with thermal storage capability. Table A-19 lists specific characteristics of the
program.
Table A-19 Crow Wing Power’s Direct Load Control Program
Attributes Description
Targeted Segment Residential customers with electric space heating and water heating
Controlled End-uses
 Electric space heating with dual fuel backup (alternate fuels include
natural gas, propane, or fuel oil)
 Water heating for water heaters with at least 100 gallons of storage.
 Electric heating system with thermal storage
Enabling technology for
control Load control switch
Event Duration
For electric space heating control with dual fuel, there is no limit on duration
of individual events. However, electric space heaters with dual fuel can be
controlled up to a maximum of 600 hours, per heating season.
Metering and
Communication
Infrastructure
NA
Incentive payment
Participants with dual fuel heating systems are offered the following
incentives:
 A discounted electricity rate of 5.3 cents/kWh.
 In addition, participants receive a rebate for the purchase of qualifying
control equipment. These are as follows:
$200 for plenum heaters and electric boilers.
$100/ton for a Ground Source Heat Pump (GSHP).
$330 - $630 for an Air Source Heat Pump (ASHP).
$100 for a whole house baseboard heating system.
Participants with space and water heating systems with thermal storage are
offered the following incentives:
 A discounted electricity rate of 4.3 cents/kWh.
 In addition, participants receive a rebate for purchase of qualifying control
equipment. These are as follows:
$25/kW of installed capacity for heating systems with storage.
$200-300 rebate for water heater with storage.
Evaluation findings NA

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South Central Power Company Water Heater Switch Program
The Water Heater Switch program offered by South Central Power Company is a legacy water
heater control program with a sizeable number of customers enrolled. Table A-20 below lists
specific characteristics of the program.
Table A-20 South Central Power Company Water Heater Switch Program
Attributes Description
Targeted Segment Residential customers with electric water heating.
Controlled End-uses Water Heaters with a capacity of 50 gallons or more.
Enabling technology for
control Radio controlled switch
Event Duration NA
Metering and
Communication
Infrastructure
NA
Incentive payment $15 annual payment, plus $1.25 off on monthly electricity bill.
Evaluation findings NA

Clay Union Electric’s Direct Load Control Program
The utility offers a direct load control program targeting water heaters for business customers.
Other than the program participation and impact data in the FERC survey, we did not find any
additional information for the program.

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Firm Curtailment Programs
Firm Curtailment programs that were selected for further investigation are listed in Table A-21
below. The table includes two additional program characteristics that relate to program
performance: participation rates and impact estimates. We will use these two characteristics
along with customer enrollment values when conducting the potential study in a subsequent
task. The data on these characteristics are taken from the FERC survey database, wherever
available. We indicate “NA” for cases where the data are not available.
Table A-21 Selected Firm Curtailment Programs
Offering entity State Scale
Winter
Peak as %
of
summer
peak
Retail
Rate
Difference
with
Avista (%)
No. of
customers
enrolled
Participation
Rate (% of
eligible
customers)
Unit
Impact (%
of
enrolled
load)
Tampa Electric Co FL Program 90.2% 15.60% 94 44% 100%20
Tennessee Valley
Authority TN Program 90.1% - 13921 NA NA
Louisville Gas &
Electric/Kentucky
Utilities Company
KY Program 97.0% -22.74% - NA NA

Below, we discuss some of the general program characteristics that are common across all
programs of this type followed by specific program examples and their characteristics.
General Program Characteristics
Under the Firm Curtailment type of program, participating customers agree to reduce demand by
a specific amount or curtail their consumption to a pre-specified level. In return, they receive a
fixed incentive payment in the form of capacity credits or reservation payments (typically
expressed as $/kW-month or $/kW-year). Customers are paid to be on call even though actual
load curtailments may not occur. The amount of capacity payment typically varies with the firm
reliability-commitment level. In addition to the fixed capacity payment, participants receive a
payment for energy reduction. Because the program includes a firm, contractual arrangement for
a specific level of load reduction, enrolled loads represent a firm resource and can be counted
toward installed capacity (ICAP) requirements. Penalties are assessed for under-performance or
non-performance. Demand-reduction events may be called on a day-of or day-ahead basis as
conditions warrant.
This program is typically third-party administered by load aggregators. It is most common in
areas with deregulated wholesale electricity markets such as in PJM, New York ISO, and ISO-
New England jurisdictions. However, increasingly utilities are directly offering this type of
program to their large commercial and industrial customers.
The targeted segment typically includes customers with electricity demand greater than 200 kW,
though individual program requirements may vary. Customers with flexibility in their operations
are attractive candidates for participation. Examples of customer segments with high
participation possibilities include large retail establishments, grocery chains, large offices,
refrigerated warehouses, water- and wastewater-treatment plants, and industries with process

20 100% load reduction implies that the load is shifted entirely to back up generators.
21 TVA offers this program to its member utilities. Enrollment data presented here is for Memphis Light, Gas, and Water Division
(MLGW), which has the highest enrollment level among all TVA members.

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storage (e.g. pulp and paper, cement manufacturing). Customers with 24x7
operations/continuous processes or with obligations to continue providing service (such as
schools and hospitals) are not often good candidates for this option.
Table A-22 below summarizes some of the characteristics of Firm Curtailment programs that are
common across program offerings.
Table A-22 Key Firm Curtailment Program Characteristics
Program Attributes Description
Type of Contract Participants have a firm capacity reduction commitment. Therefore
participation is mandatory.
Resource Reliability Capacity reductions can be counted toward Installed Capacity (ICAP), since
participants have a firm commitment for capacity reduction.
Targeted segment
Commercial and industrial customers, with maximum demand values typically
greater than 200 kW. In some cases a lower maximum demand threshold of
100 kW may be used.
DR Strategies Load reduction and shifting to backup generators.
Examples of Curtailable
Processes
Examples of commercial and light industrial curtailable processes include: air
handlers, anti-sweat heaters, chiller control, chilled water systems, defrost
elements, elevators, escalators, external lighting, external water features,
HAVC systems, internal lighting, irrigation pumps, motors, outside signage,
parking lot lighting, production equipment, processing lines, pool
pumps/heaters, refrigeration systems, and water heating.
Event Trigger Event trigger is typically emergency system conditions, such as actual or
forecasted operating reserves shortage.
Event Notification 30 minutes to day-ahead
Event Duration Varying duration: typically ranges from 1 to 8 hours
Program Hours Events are usually called during business hours on working days, therefore
loads need to be available during that time.
Incentive structure Participants are offered both capacity ($/kW-month) and energy ($/kWh)
payments.
Penalties for non-
performance
Participants are subjected to non-performance penalties for performance
below pre-determined threshold levels.
Metering and
Communication Systems
 These programs preferably require 5-minute interval data (although 15
minute or hourly interval data may be sufficient.)
 Communication systems need to receive and confirm system operator
requests, preferably in real-time.

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Specific Program Examples
Below are summaries of the specific characteristics of the programs we researched.
Tennessee Valley Authority’s Demand Response Program
This is a third-party administered program offered by TVA to its member utilities. The program
was launched in 2008 and is currently in operation. It is administered by EnerNOC. Table A-23
below lists specific characteristics of the program.
Table A-23 TVA’s Demand Response Program Characteristics
Program Attributes Description
Targeted Segment C&I customers with a minimum load reduction amount of 100 kW.
Resource Availability
 Program is available year round.
 During the summer months of April to October, program hours are from
12 noon to 8 PM on weekdays.
 During the winter months of November to March, program hours are from
5 AM to 1 PM on weekdays.
Event Notification 30 minutes. Notification is via email, phone, or SMS.
Maximum Annual Event
Hours 40 hours.
Event Duration Events can range from 2-8 hours; average event duration is 3.5 hours.
Maximum Number of Events No more than 6 events can be called in a month; events cannot be called on
more than 2 consecutive days.
Incentive Payment Capacity payment is $22/kW-year; energy payments are $40-50/MWh;
Participants are offered $225/MWh or more for emergency energy payments.
Type of Response Both manual and Auto-DR strategies
Metering Requirements All participating customers receive free, near real-time 5 minute interval
metering.

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Tampa Electric Company’s Networked Demand Response Program
This is a third-party administered program offered by Tampa Electric Company in Florida. The
program was launched in 2008, and the contract is active until 2016. It is administered by
EnerNOC. Table A-24 below lists specific characteristics of the program.
Table A-24 Tampa Electric Company’s Networked Demand Response Program Characteristics
Program Attributes Description
Targeted Segment
Targeted customer segments include city and county agencies,
telecommunication companies, big-box retailers, grocery stores, and others.
No information available on minimum load reduction amount.
Resource Availability  Program is available year round.
 Program hours are from 7 AM to 7 PM on weekdays.
Event Notification 30 minutes.
Maximum Annual Event
Hours NA
Event Duration Events can range from 1-8 hours.
Maximum number of events NA
Incentive payment NA
Type of Response Both manual and Auto-DR strategies
Metering requirements All participating customers receive free, near real-time 5 minute interval
metering.

Louisville Gas and Electric and Kentucky Utilities Demand Response Program
This is a third-party administered program offered by Louisville Gas and Electric and Kentucky
Utilities Company (LG&E and KU). The program was launched in 2012 and is currently
operational. It is administered by EnerNOC. The program has a bilateral contract for delivering
10 MW of load reduction. Information on specific program characteristics was not available.

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Non-Firm Curtailment Programs
The Non-Firm Curtailment program selected for further investigation is listed in Table A-25
below. The table includes two additional program characteristics that relate to program
performance: participation rates and impact estimates. The data on these characteristics are
taken from the FERC survey database, wherever available.
Table A-25 Selected Non-Firm Curtailment Programs
Offering entity State Scale
Winter
Peak as %
of summer
peak
Retail Rate
Difference
with Avista
(%)
No. of
customers
enrolled
Participation
Rate (% of
eligible
customers)
Unit
Impact (%
of enrolled
load)
New York State
Electric and Gas NY Program 87% 0.43% 106 9% 30%

General Program Characteristics
Under the Non-firm Curtailment type of program, participants voluntarily reduce load when an
emergency event is called. In contrast to the “Firm Curtailment” option, customers are not under
contract to deliver a specific quantity of load reduction. There is usually no penalty for not being
able to reduce load when events are called. Events may be called on a day-of or day-ahead
basis, as conditions warrant. Participants are paid a credit for each kWh they reduce during the
event. The $/kWh payment is typically based on Locational Marginal Prices (LMPs). There is no
capacity payment associated with this option since it does not represent a firm resource. This
option complements the firm capacity commitment contracts and offers a flexible option for
customers that may not be able to provide firm capacity reduction commitments.
Table A-26 below summarizes characteristics of the Non-firm Curtailment program.

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Table A-26 Key Non-Firm Curtailment Program Characteristics
Program Attributes Description
Type of Contract Participants do not have a firm capacity reduction commitment. Therefore,
participation is voluntary.
Resource Reliability
Load reductions cannot be counted toward Installed Capacity (ICAP)
requirements, since participants do not have a firm capacity reduction
commitment.
Targeted segment Commercial and industrial customers, with maximum demand values typically
greater than 200 kW.
DR Strategies Load reduction and shifting to backup generators.
Examples of Curtailable
Processes
Examples of commercial and light industrial curtailable processes are: air
handlers, anti-sweat heaters, chiller control, chilled water systems, defrost
elements, elevators, escalators, external lighting, external water features,
HAVC systems, internal lighting, irrigation pumps, motors, outside signage,
parking lot lighting, production equipment, processing lines, pool
pumps/heaters, refrigeration systems, and water heating.
Event Trigger Event trigger is high Locational Marginal Prices (LMPs), especially during times
of high system demand.
Event Notification Varies from 30 minutes to day-ahead
Event Duration Varies
Program Hours Events are usually called during business hours on working days, therefore
loads need to be available during that time.
Incentive structure Participants are offered energy ($/kWh) payments.
Penalties for non-
performance No penalties exist, since participation is voluntary.
Metering and
Communication Systems
 These programs preferably require 5-minute interval data (although 15
minute or hourly interval data may be sufficient).
 Communication systems need to receive and confirm system operator
requests, preferably in real-time.

Specific Program Examples
Below are summaries of the specific characteristics of the programs we researched.
New York ISO’s Emergency Demand Response Program
New York ISO operates the Emergency Demand Response Program (EDRP), which is one of the
largest and most successful non-firm curtailment type DR program. The program has been
operational since 2001. New York State Electric and Gas is one among other New York state
utilities that offer the ISO administered program to its retail customers. DR events are triggered
whenever there is a need to address system reliability in the NYISO service area.
Table A-27 below lists specific characteristics of the program.

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Table A-27 NYISO Emergency Demand Response Program Characteristics
Program Attributes Description
Targeted Segment C&I customers with a minimum load reduction amount of 100 kW.
Resource Availability Program can be called at any time. Therefore, resources need to be available
all year round.
Event Notification 2 hours
Event Duration 4 hours
Incentive Payment
Payment is based on real-time Locational Based Marginal Price (LBMP) and
measured energy reduction during an event, with a minimum rate of
$500/MWh.
DR Strategy Load reduction and shifting to backup generators. Most of the load reduction
achieved in the program has been through shifting to backup generators.
Metering Requirements Hourly meter required for participation

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Critical Peak Pricing Programs
Critical Peak Pricing programs that were selected for further are listed in Table A-28 below. The
table includes two additional program characteristics that relate to program performance:
participation rates and impact estimates. The data on these characteristics are taken from the
FERC survey database, wherever available. We indicate “NA” for cases where the data are not
available.
Table A-28 Selected Critical Peak Pricing Programs
Offering entity State Scale
Winter
Peak as
% of
summer
peak
Retail Rate
Difference
with Avista
(%)
No. of
customers
enrolled
Participation
Rate (% of
eligible
customers)
Unit
Impact (%
of enrolled
load)
Gulf Power
Company22 FL Program 91% 39% 10,000 2.6% NA
Southern California
Edison Co. CA Program 65.9% 47.4% 3,255 ~50% 6.3%23
General Program Characteristics
A CPP rate includes an extremely high peak price during specific critical demand periods of the
year. The rate specifies the number of times CPP events can be called and the maximum
duration of a single event. Participants enrolled on CPP have a lower off-peak rate than the class
average retail tariff. CPP events can be called on a day-ahead or day-of basis. They can be
offered either as a voluntary rate with opt-in or as a default rate with opt-out provision. The type
of offering varies by customer class and utility.
Table A-29 below summarizes some of the characteristics of the CPP program that are common
across program offerings.
Table A-29 Key Critical Peak Pricing Program Characteristics
Program Attributes Description
Resource Reliability Non-firm
Targeted segment All residential and C&I customers.
DR Strategies Load reduction and shifting to backup generators.
Event Trigger Events can be triggered under system emergency situations or under high
price conditions.
Event Notification 30 minutes to day-ahead
Event Duration Varies by program
Incentive structure No separate incentive payment.
CPP participants are offered a discounted rate during off-peak periods.
Penalties for non-
performance Not applicable.
Metering and
Communication Systems AMI is preferred for metering and settlement purposes.

22 Gulf Power Company’s CPP program was not listed in the FERC survey database. Therefore we obtained program information from
outside sources. 23 This is based on impact evaluation results from the “2012 California’s Statewide Non-residential Critical Peak Pricing Evaluation
Report”.
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Specific Program Examples
Below are summaries of the specific characteristics of the programs we researched.
Gulf Power Company’s Residential CPP Program
Energy Select, Gulf Power’s residential CPP program, is one of the oldest and most successful
CPP programs offered to residential customers. The program was launched in 2000. Before
launching the program, a two-year pilot was conducted to evaluate customer acceptance and
equipment performance. The program attained an industry landmark in 2012 with 10,000
participants voluntarily enrolled in the program. There are plans to extend program participation
to 16,000 participants by 2016. The program is administered by Comverge. Table A-30 below
lists specific characteristics of the program.
Table A-30 Gulf Power Company’s Residential CPP Program Characteristics
Program Attributes Description
Targeted Segment Residential customers.
Enabling Technology for
Load Control Programmable Communicating Thermostat (PCT)
CPP Rate Structure
The electricity price is four tiered:
 Low- 7 cents/kWh
 Medium- 8 cents/kWh
 High- 15 cents/kWh
 Critical- 58 cents/kWh
Standard electricity price is around 10 cents/kWh.
Number of times events can
be called annually -
Event Notification Day-ahead or day-of.
Event Duration 1-2 hours.
Metering Requirements
The program uses Broadband for communicating between the utility and the
home, and Zigbee RF communication for communicating to devices within the
home.

Since this is one of the leading examples of residential CPP programs in the country, learnings
from program design and implementation experience are likely to be useful for Avista. Below, we
summarize some of the key findings related to program deployment experience.
 Program Planning
o Before designing a program, a pilot is essential to evaluate customer acceptance of rates
and test equipment performance.
o Regulatory approval process takes a very long time and therefore, a utility needs to plan
ahead.
 Technology Deployment
o A utility needs to focus on how the technology affects the customer. Technology changes
rapidly and the utility needs to stay ahead of the game. This is one of the most important
lessons learned from this program.
 For example, switch to broadband communication from land line based communication
can open up participation to many more customers.
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 In Gulf Power’s example, initially communication was based on land-lines telephones. But
participation was affected as customers started dropping their land line phones.
Switching to broadband communication helped increase participation levels dramatically.
 Program Design and Development
o Education and training are key components of program development.
o Offering the program to all residential customers, instead of restricting it to single family
home customers, help increase enrollment levels.
o Two key program design features that can help increase participation levels are
shortening the event duration and avoiding monthly participation charges.
 In Gulf Power’s case, shortening the high price period from nine to five hours in the
summer and avoiding a monthly participation charge of $5 per month helped increase
participation levels.
 Marketing and Outreach
o During early stages of the program, cost effective channels for program marketing are
direct mail, internet, TV, and outdoor advertising. Channels such as newspaper and radio
are less effective.
o After the program matures, internet can serve as the primary channel for program
promotion.
 In Gulf Power’s case, program enrollment is completely done online.
 Program Participation
o Primary drivers for customer satisfaction are the following:
 Simple rate design that participants can easily understand.
 Perceived energy savings and control over energy use and savings opportunities.
 Ability to program and control devices online.

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Southern California Edison Company’s C&I CPP Program
Southern California Edison, along with other utilities in California, has implemented critical peak
pricing rates for non-residential customers. Table A-31 below lists specific characteristics of the
program.
Table A-31 Southern California Edison’s C&I CPP Program Characteristics
Program Attributes Description
Targeted Segment
 Large C&I customers with maximum demand greater than 200 kW are
defaulted to CPP rate.
 Small C&I (with less than 20 kW demand), and medium C&I customers
(with 20-200 kW demand) are offered CPP rates on a voluntary basis.
Enabling Technology for
Load Control Manual and Auto-DR strategies.
CPP Rate Structure24
1. TOU component during summer:
Energy charges per kWh:
On-peak: $0.124
Semi-peak: $0.091
Off-peak: $0.065
Demand charges per kW:
On-peak: $12.96
Semi-peak: $3.08
Maximum: $13.3
2. CPP component during summer:
CPP event adder (energy charges and credits per kWh): $1.362
Demand credit per kW: $11.62
Number of Times Events can
be Called Annually 9 to 15 times. Maximum total CPP events per year is 60.
Event Notification Day-ahead
Event Duration 4 hours
Metering Requirements AMI is required

Key findings from impact evaluation studies of the 2012 SCE CPP program include:
 Overall Demand Reductions. In aggregate, participants reduced demand by 6.9% across
the 2 to 6 PM event window for the average event day, delivering 32.9 MW of demand
reduction.
 Demand reductions are highly concentrated in specific industry segments.
Manufacturing and Wholesale, Transport and Other Utilities, and Agriculture accounted for
the bulk of demand reductions. These customers made up 45% of program enrollment and
44% of program load at SCE, but accounted for 87% of overall demand reductions.
Manufacturing and Wholesale, and Transport customers reduced a larger share of their
demand than the average CPP customer, at 13.8% and 9.4% of enrolled load, respectively.

24 Based on 2012 Impact Evaluation Study
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Real Time Pricing Programs
The Real Time Pricing programs that were selected for further investigation is listed in Table A-
32 below. The table includes two additional program characteristics that relate to program
performance: participation rates and impact estimates. The data on these characteristics are
taken from the FERC survey database, wherever available. We indicate “NA” for cases where the
data are not available.
Table A-32 Selected Real Time Pricing Programs
Offering entity State Scale
Winter
Peak as %
of summer
peak
Retail Rate
Difference
with Avista
(%)
No. of
customers
enrolled
Participation
Rate (% of
eligible
customers)
Unit
Impact (%
of enrolled
load)
Georgia Power
Company GA Program 85.8% -9.1% 2,033 ~40% NA
General Program Characteristics
A Real Time Pricing (RTP) rate, with prices varying by hour, is offered to large C&I customers.
Hourly prices are often indexed to wholesale market prices. AMI is required for metering and
settlement purposes.
Table A-33 below summarizes some of the characteristics of a RTP rate.
Table A-33 Summary of Program Characteristics
Program Attributes Description
Resource Reliability Non-firm.
Targeted segment C&I customers.
DR Strategies Load reduction and shifting to backup generators.
Event Trigger No specific trigger, prices vary by the hour.
Event Notification Day-ahead or hour-ahead.
Event Duration Not applicable.
Incentive structure Not applicable.
Penalties for non-
performance Not applicable.
Metering and
Communication Systems AMI for metering and settlement purposes.
Specific Program Examples
Below are summaries of the specific characteristics of the programs we researched.
Georgia Power Company’s C&I RTP Program
Georgia Power has one of the largest Real Time Pricing (RTP) programs in the nation. The
program offers two provisions for RTP rates: a day-ahead provision and an hour-ahead provision.
The utility engages in a high level of customer education and outreach regarding the rate. This
has been one of the most successful RTP program.
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Table A-34 below lists specific characteristics of the program.
Table A-34 Georgia Power Company’s C&I RTP Program Characteristics
Program Attributes Description
Targeted Segment
Day-ahead provision: Large sized C&I customers with maximum demand
greater than 250 kW.
Hour-ahead provision: Large sized C&I customers with maximum demand
greater than 5,000 kW.
Enabling Technology for
Load Control Manual and Auto-DR strategies.
Tariff structure
It has two parts:
 Customer is billed for normal “baseline” usage at standard prices.
 Any usage at the margin, above or below the baseline, is billed at the real
time price.
Basis for Hourly Rates
Hourly prices are determined each day based on projections of the hourly
running cost of incremental generation (including approved environmental
costs), provisions for losses, projections of hourly transmission costs, reliability
capacity costs for each day (when applicable), and a 3 mill/kWh recovery
factor.
Number of times events can
be called annually Not applicable.
Event Notification Day-ahead or hour ahead.
Event Duration Not applicable.
Metering Requirements AMI is required.

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Ancillary Services / Load Following Pilots
Ancillary Services/Load Following pilots that were selected for further investigation are listed in
Table A-35 below.
Table A-35 Selected Ancillary Services/Load Following Pilots
Offering entity State Scale
Winter
Peak as %
of
summer
peak
Retail Rate
Difference
with Avista
(%)
No. of
customers
enrolled
Participation
Rate (% of
eligible
customers)
Unit
Impact
BPA-City of Port
Angeles WA Pilot 120% - - - -
BPA-Mason County
PUD No. 3 WA Pilot 120% - - - -

Below, we discuss some of the general characteristics that are common for ancillary/load
following services and then we provide descriptions of the selected pilots. We conclude by
summarizing some of the important design and deployment aspects that any utility needs to
keep in mind when considering DR resources to provide ancillary/load following services.
General Program Characteristics
For DR providing ancillary (spinning, non-spinning, regulation) and load following services, loads
need to respond within a very short notification period, typically less than 10 minutes. This is
often referred to as “Fast DR”. DR providing load following services is relevant in the context of
integrating intermittent renewable resources such a solar and wind. With increasing penetration
of renewables, there is growing interest among utilities and system operators in this type of
service.
Well-established programs exist in ERCOT, PJM, NYISO and HECO jurisdictions. BPA has
launched pilots to specifically test DR integration with renewables.
Table A-36 below summarizes characteristics for DR providing ancillary/load following services.

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Table A-36 Key Characteristics of Ancillary Services/Load Following Services Programs
Program Attributes Description
Targeted Segments Residential and C&I customers.
Event Notification Less than or equal to 10 minutes.
Resource Availability Resources need to be available all year round.
Annual Event Hours  Typically range from 50-100 hours for providing ancillary services.
 Events may be called with high frequency.
Typical Event Duration
 10-60 minutes for providing ancillary services
 Longer event hours, may be extending over a couple of hours or more,
apply for providing load following services
DR Strategies Load reduction and shifting to backup generators.
Event Trigger  System contingency conditions requiring ancillary services.
 Need for balancing intermittencies in renewable energy supply.
Incentive structure Participants are offered both availability ($/kW-hr) and energy ($/kWh)
payments.
Penalties for non-
performance Penalties apply for non-performance.
Customer segments and
loads that could serve as
good candidates
 Sites having flexibility in their operations, from having some sort of
storage within the process (e.g. thermal energy) and production processes
that are not adversely impacted by frequent starts and stops, are likely to
be good candidates.
 DR resources, without any energy storage component, have limited ability
to provide regulation-down services, which is increasing load in response
to sudden increase in supply.
 Facilities with pumping loads often have storage capacity, which allows for
load shifting without impacting production levels. Customer segments
with pumping loads, such as water and wastewater treatment plants,
municipal waterworks, and agricultural pumps, are likely to be good
candidates.
 Facilities with large thermal mass and refrigeration/compressor load are
likely to be good candidates. These sites may be able to increase or
decrease temperature set points, based on the facility load requirements.
Examples of such facilities are food distribution warehouses and food
processing plants, arenas/stadiums/convention centers, data centers,
universities, hospitals.
 Certain industrial processes with storage capacity can provide ancillary
and flexible capacity products without disruptions in operations. Examples
are pulp and paper, and cement.
 Facilities with ventilating fan capacity can often reduce loads by cycling or
turning off fans. Examples are manufacturing with volatile organic
compounds or particulate processes, automobile painting.
Metering and
Communication Systems
 Real time metering and communications required.
 Meter data interval needs to be at 1 minute or less intervals.

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Specific Examples
Below are brief descriptions of the pilots we researched.
BPA-City of Port Angeles C&I DR Pilot
This pilot was conducted during the period April to August 2012. The objective of this pilot was
to test whether process storage could be used to support wind integration, with capabilities for
both load curtailment and load increase. The technical infrastructure set up for monitoring load
performance allowed visibility at one minute intervals.
Nine C&I sites were recruited for participation in the pilot, which included diverse customer types
such as City Hall, waste water utility, housing authority, courthouse, library, medical center, and
pulp and paper mill.
The pulp and paper mill exhibited greatest success in pilot performance. For the pulp and paper
mill, DR signals were dispatched directly to the mill and all load response was directly controlled
by mill personnel. The pulp and paper mill response was supported by inherent “process storage”
capabilities in the production line.
Overall, the pilot was successful in demonstrating the technical feasibility of load response for
integration with wind. Both load increase and load decrease could be attained with 10 minute
response time. The next phase of this pilot is currently testing commercial feasibility of load
response during the 2013-2014 time period.
BPA-Mason County PUD Pilot
This pilot tested water heater controls activated by a renewable energy signal, using Auto-DR
technologies, for residential customers of Mason County Public Utility District No. 3. The pilot
used a special device and an algorithm to allow water heaters to “sync” with wind turbines. The
algorithm helped predict ahead of time when the wind power would be generated. The device,
which was attached to the heaters, gave the utility the capability to turn them on and off during
wind production cycles. Customers also had override switches. Overall, the pilot reported a high
level of customer satisfaction with no impact on participant homes.

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Cost Effectiveness Assessment for Demand Response
Below we describe what constitutes DR program costs and benefits and the overall approach
used for assessing cost-effectiveness of DR programs.
DR Program Costs
Based on our experience with DR potential studies, we have constructed Table A-37 below that
lists the cost components typically considered for a DR program. We briefly discuss these cost
items and how they apply to the different program types included in our analysis.
An important aspect to consider in developing DR program costs is the underlying assumptions
related to program delivery. A DR program can either be delivered by a utility or by a third-party.
The allocation of costs across different types of programs in Table A-37 assumes in-house
delivery across all program types, except for the Firm Curtailment program. For this particular
program, based on commonly observed trends in the industry, we assume that it is delivered by
a third party. Other types of programs, such as Non-Firm Curtailment programs and DLC
programs can also be delivered by third parties. However, that is less commonly observed in the
industry. Our delivery-mechanism assumptions for developing cost components are based on
commonly observed industry trends.
Table A-37 Cost Components by DR Program Type
Cost Items Unit
Type of Program
Direct Load
Control
Firm
Curtailment
Non-Firm
Curtailment
Pricing
Programs
Ancillary/
Load
Following
Services
Program
Development
Cost
$/program x x x x
Administration
Cost $/MW-year x x x x x
Annual
Marketing and
Recruitment
Costs
$/new
participant x x x x
Equipment
capital and
installation costs
$/device
installed x x x
Annual O&M
costs $/year x x x
Participant
incentives
$/participant/
year x
$/kW-year x
$/kWh x x
Third-party
program delivery
cost
$/kW-year x

A brief description of these cost items and how they are treated across programs follows.
 Program Development Cost. This is a one-time cost that is incurred for setting up a brand
new program. This cost is usually specified in the number of FTEs required for setting a
program up. It usually applies uniformly across all program types. The only exception could
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be a third-party delivered firm curtailment program, in which the utility itself does not incur
any cost for setting up the program.
 Annual Program Administration Cost. This constitutes an annual recurring expense that
is incurred for administering a DR program. It usually applies uniformly across all program
types. It is common to specify this cost in terms of the unit load reduction amount ($/MW-
year). There may be cases where the cost is specified as a fixed annual cost in terms of
$/year.
 Annual Marketing and Recruitment Costs. This typically applies to all program types,
except third-party delivered curtailment programs, in which case customer marketing and
outreach activities are primarily undertaken by the third party. For pricing programs in
particular, marketing and recruitment costs depend on whether a particular rate is offered on
a voluntary basis with opt-in provision or as a default rate from which customers can opt-out.
For a voluntary rate offer, per participant marketing and recruitment costs may be much
higher than those incurred by defaulting all customers to a rate. Therefore, one needs to
take into account the type of offer in developing costs for pricing options.
 Equipment Capital and Installation Costs. This usually refers to capital and installation
costs for a load control switch or a thermostat in a DLC program. In pricing programs, this
cost applies to the enabling technology used for achieving load reductions for residential and
small commercial customers. For medium and large sized customers on DR programs,
enabling technology costs commonly refer to costs for enabling Auto-DR on customer
premises. Usually for third party delivered programs, the technology cost is rolled into a
composite program delivery cost, especially where the third party is responsible for bearing
technology costs.
 Annual O&M Costs. This is usually estimated as a fraction of the equipment capital cost
and applies wherever specific enabling technology is deployed for load control.
 Participant Incentives. This applies to all DR programs that are non-price based. The
structure of the incentive may differ, depending on the program type. For example, for DLC,
incentives are usually structured as a fixed annual payment to the participant, irrespective of
the load reduction amount. For other programs, incentive payments are based on actual
performance. Although customer incentives do not apply to pricing options such as TOU, CPP
and RTP rates, they apply to a Peak Time Rebate (PTR) type of offer.
 Third-party Program Delivery Costs. This constitutes the main cost item for a Firm
Curtailment type program, delivered by a third party. The cost is specified in terms of unit
annual capacity reduction ($/kW-year). Items such as customer incentive costs, program
marketing and outreach, and equipment capital and installation costs, are all rolled into the
program delivery cost.
There may be additional items that can be classified as DR program costs, but which may be
difficult to estimate and quantify. Examples are increased costs of environmental compliance in
cases where backup generators are operated for load shifting, costs arising out of “value of lost
service”, and other transaction costs associated with program participation. Therefore, these
items cannot be included in assessing overall program costs.
DR Program Benefits
We discuss below items considered in estimation of DR program benefits.
 Avoided Capacity Cost. The primary component that is included in estimating benefits
from DR programs is the avoided capacity cost. This is universally applied across all types of
DR programs.
 Avoided T&D Cost. This item specifically applies to DR programs that address network
congestion and are deployed to address transmission and distribution capacity constraints. It
does not apply to programs that address only peak load reductions, since T&D capacity
constraints are not a consideration for these programs.
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 Avoided Energy Benefits. Unlike energy efficiency programs, energy savings benefits are
typically not included in estimating DR program benefits. This is due to the small number of
hours that are impacted by DR programs. When programs are called over extended periods
of time, energy savings benefits may need to be included. However, one needs to take into
consideration possible “snapback” effects that could arise after completion of a DR event,
which effectively increases energy usage after DR events. Similarly, if any pre-cooling
strategies are used prior to an event, increase in energy use for such behavior needs to be
considered.
 Avoided Ancillary Services Cost. For DR programs providing ancillary/load following
services, avoided ancillary services costs need to be estimated for calculating benefits.
Ancillary services are valued differently than avoided capacity.
Additional benefits arising from DR programs that are usually difficult to estimate and quantify
include items such as enhanced wholesale market competitiveness, reduced price volatility, and
insurance against extreme events. However, since these are difficult to quantify, they are usually
not included in overall benefit calculations.
Derating of Avoided Costs
One important consideration in estimating DR program benefits is the derating of avoided
capacity benefits. The full value of the avoided costs is based on the performance of a peaking
generator, which is not exactly equivalent to a DR program. For estimating DR benefits, a
derating factor is often applied to the avoided capacity costs to reflect that DR programs typically
supply a lower resource value than equivalent supply-side options. The lower resource value can
be attributed primarily to the following factors:
 A DR program is not as dispatchable as a supply-side option, like a natural gas peaking
generator. A peaking plant will run approximately 200 to 400 hours per year, while a DR
program is typically constrained to run from 40 to 100 hours per year.
 Many DR programs are vested with a seasonal limitation, for example, one cannot exercise
direct load control for Central AC in the middle of the winter.
 DR programs are also limited by constraints on human behavior and/or presence of
automation systems.
Derating factors are often applied by utilities and grid operators to account for the reduced value
of the different availability and dispatchability profiles. There are many ways to calculate the de-
rating factor, based on program characteristics, value of load at certain hours, but there does not
appear to be an industry-standard. Adjustment factors are developed at various levels of
granularity, depending on what the state protocol specifies. For example, California protocols
account for program limitations by applying multiple adjustment factors to the avoided cost of a
new combustion turbine. These factors are determined and applied separately by each load
serving entity in California and vary by program type, depending on the dispatchability and
reliability of the resource. In certain other jurisdictions, a simpler approach may be followed by
applying a common derating factor across all program types. A review of available literature on
the topic indicated capacity derating values generally range from 0.60 to 1.00
Cost-effectiveness Assessment Framework
The Total Resource Cost (TRC) test is commonly followed for assessing cost-effectiveness of DR
programs. Usually in DR programs, customers do not incur additional participation costs. Also ,
loss of revenue to the utility may be negligible. Under these conditions, the TRC formulation
essentially becomes equivalent to the utility cost test (UCT) and the ratepayer impact measure
(RIM) test. All of these tests use the same stream of benefits by default, and for DR, they reduce
to the same stream of costs as well. However, there may be exceptions where program
participation costs are significant and/or loss of revenue is substantial. Under such situations,
one may need to consider additional tests other than TRC.
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Additional Items for Assessing Cost-Effectiveness
Two additional items that are required for assessing cost-effectiveness of DR programs are
program lifetime assumptions and discount rates. Lifetime assumptions vary by DR program. For
example, DLC programs typically have a 10 to 15 year lifetime, depending on the life of the
control technology (load control switch or thermostat). For pricing assumptions, program life is
tied to the life of the meter, which is typically assumed to be 20 years. Curtailment Agreements,
which are third-party-delivered capacity reductions, usually have a contract term of three to five
years.
Impact Estimation Methods for Demand Response
This chapter discusses the commonly used approaches for estimating impacts from DR programs. It
does not go into specifics of how impacts are estimated for a particular type of program. The
discussion focuses on event-based DR programs. Therefore, the methods discussed in this chapter
are likely to apply to all programs types included in this report, other than Real Time Pricing
programs which are non-event based.
Types of Impact Estimation
Impact estimation can broadly be of two types: ex post or ex ante.

 Ex post impact estimation is required for assessing program performance and is also
sometimes used for settlement purposes. However, most programs base settlement on
calculated reductions from a program, which are calculated simply as the sum of demand
reductions determined for each participant, using the program’s settlement methods. Impact
estimation for settlement purposes needs to be simple and produce rapid results. A more
rigorous and accurate program level impact assessment is conducted in later stages to assess
program performance, which may not be practical for settlement purposes.
 Ex ante impact estimation is required for projecting demand savings from future
programs and cost-effectiveness of programs. It can also be used retrospectively for
settlement purposes.
Baseline Calculation Methods25
The commonly followed approaches for calculating baseline load are briefly described below.
Baseline Window
The first step in calculating baseline load is to define the baseline window. This is the period of
time preceding and optionally following a DR event over which electricity usage data is collected
for establishing a baseline. Examples of baseline windows are:
 Last 10 non-holiday weekdays.
 10 most recent program-eligible non-event days.
 10 most recent program-eligible days beginning 2 days before the event.
 Last 45 calendar days.
 Previous year.
The common rules for excluding specific days from the baseline window are the following:
exclude days with DR events, exclude days with outages, exclude days with extreme weather,
and exclude days with highest or lowest loads.

25 “Measurement and Verification for Demand Response” prepared for the National Forum on the National Action Plan on Demand
Response: Measurement and Verification Working Group”. February, 2013.
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Baseline Load Calculation
There are a number of methods for developing the baseline load value using load data from the
baseline window. These are briefly discussed below.
 Average Value Method. This is the most commonly used method for baseline load
calculation, where one simply calculates the average value of the load by hour, for the hours
included in the baseline window.
 Maximum Value Method. This method takes the maximum load over the window period to
calculate baseline load.
 Regression Method. This method calculates load by regressing the load from included days
on weather and other variables, using separate regression coefficients for each hour of the
day.
 Rolling Average Method. This method calculates the unadjusted baseline for an operating
day as equal to 90 percent of the prior unadjusted baseline load, plus 10% of the load on the
most recent included day.
Baseline Adjustments
Once the baseline load is calculated by one of the above methods, an adjustment factor is
applied to align the baseline load with observed conditions during the event day. The baseline
load calculated in the earlier step is referred to as the “unadjusted baseline”. Adjustment factors
may be based on variables such as temperature, humidity, and event day operating conditions.
The North American Energy Standards Board (NAESB) has set some guidelines that define the
adjustment window, which is the timeframe that needs to be considered for baseline load
adjustment. It specifies that the adjustment window should begin no more than four hours prior
to the DR event. Commonly followed examples of adjustment windows are an hour before the
event, two hours before the event, and the two hours that end two hours before the event.
Impact Estimation Methods26
Alternative methods used for estimating impacts from DR programs are briefly described below.

 Individual regression analysis. This method fits a regression model to an individual
customer’s load data over a year or a particular season. A common approach is to develop a
model that describes a customer’s load as a function of weather variables such as
temperature and humidity. The model is developed to fit loads on non-event days and is
used to estimate a customer’s load that would have occurred absent a DR event. The impact
is then calculated as the difference between the observed and modeled load over each event
hour. The model can also be used to calculate post event rebound effects.
 Pooled regression analysis. This method uses a similar approach as the individual
regression analysis, but fits a single model across a large group of participants and hours. A
single set of coefficients is used to describe an average load pattern for all customers in the
pool. This is a better method for estimating coefficients that may not be determined for an
individual customer using individual regression analysis.
 Match days. This method first identifies one or more non-event days that are similar to
each event day based on criteria such as similar temperature, temperature-humidity index,
similar system load, or similar customer load during non-event hours. A particular customer’s
load on the match day, or the average of the loads across multiple match days, serves as the
baseline or reference load. Demand reductions are calculated as the difference between the
match day and event day hourly loads. However, estimating the accuracy of this method is

26 “Measurement and Verification for Demand Response” prepared for the National Forum on the National Action Plan on Demand
Response: Measurement and Verification Working Group”. February, 2013.
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more difficult than accessing the precision of a regression model, and therefore, this method
is not commonly used.
 Experimental design. This involves a random assignment of customers into two groups,
one of which is the “treatment” group and the other is a “control” group. The treatment
group is subjected to event dispatches while the control group is not. The average demand
reduction per participant is calculated as the difference between the averages for the two
groups. An alternative method for calculating impacts is to use the difference of differences
method. In this method, baseline load is estimated separately for both treatment and control
groups. The impact is then calculated as the difference between the treatment group’s
modeled and observed load, minus the corresponding difference for the control group.
This method has been used for estimating impacts for large scale residential and/or
commercial direct load control programs deployed by utilities, especially in California. It
applies to customers who have interval metering data.
In addition to these approaches, end-use metering data can directly be used for estimating
impacts, wherever interval meter data is available.

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APPENDIX B
Time-of-Use Rates
Although TOU rates are out of scope for an analysis of demand response, AEG offered to perform
an analysis of TOU rates so that Avista would have the information for future reference.
Program Description
A TOU rate is a time-varying rate. Relative to a revenue-equivalent flat rate, the rate during on-
peak hours is higher, while the rate during off-peak hours is lower. This provides customers with
an incentive to shift consumption out of the higher-price on-peak hours to the lower cost off-
peak hours. TOU is not a demand-response option, per se, but rather a permanent load shifting
opportunity. Large price differentials are generally more effective than smaller differentials. The
TOU rate included here is based on a 2:1 on-peak to off-peak price ratio. We assumed that this
rate is offered to all three C&I classes.
We considered two types of TOU pricing options. With an opt-in rate, participants voluntarily
enroll in the rate. With an opt-out rate, all customers are placed on the time-varying rate but
they may oft-out and select another rate if they so desire.
Participation in TOU rates requires interval meters. At this time, Avista’s Extra Large General
Service customers have sophisticated telemetry and communications infrastructure in place and
may be offered TOU beginning in 2016. For the other two customer classes, pricing options are
not available until the AMI rollout is completed in 2020. Therefore, we assumed that TOU rates
can be offered to General Service and Large General Service customers starting in 2021.
Table B-1 describes the features of a TOU rate.
Table B-1 Time of Use Rate Features
Program Attributes Description Comments
Targeted Segment All C&I classes. All customers are eligible to participate
in a TOU rate.
Type of Offer
Two types of offers are possible:
1) TOU is offered as a voluntary rate to all
customer classes with opt-in provision.
2) TOU is offered as a default rate to all
customer classes with opt-out provision.
Based on program and pilot
implementation experiences.
Resource
Availability
TOU rates are available throughout the year.
The peak period and off-peak period
definitions can vary by season.
The peak and off-peak periods need to
be defined based on Avista's specific
requirements.
Delivery
Mechanism Delivered by Avista Time varying rates are directly
administered by the utility.
Type of Response
Load curtailment during peak period for a
variety of end-uses and shifting of usage to
off-peak periods.
Participant
Incentive
Peak to off-peak price differential induces
participant to shift usage from peak period
to off-peak periods. The off-peak rate is
lower than the participant's standard rate
Metering
Requirements Interval meter required for participation Based on industry experience.
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TOU Assumptions
The key parameters required to estimate potential for the two pricing options are participation
rate, per participant load reduction and costs for deploying these rates. We have described below
our assumptions on these parameters.
Program Participation Rate
We have defined participation rates for pricing options assuming independent offers of TOU,
which results in voluntary, opt-in TOU rates to all customers and default TOU rates to all
customers with opt-out.
All participation assumptions in pricing options are based on Brattle’s extensive database on
pricing program and pilot experiences.
Table B-2 presents assumed participation rates for C&I customers in independent TOU rate
offers. We assumed that participation ramps up over a five-year timeframe to reach a steady-
state level. For the opt-in offer, ramp up to steady-state participation follows an “S-shaped”
diffusion curve, in which the participation growth rate accelerates over the first half of the five
year period and then slows over the second half. A similar but inverse S-shaped diffusion curve is
used to account for the rate at which customers opt-out of the default rate. TOU rates could be
offered to Extra Large General service customers in 2016. For the other two classes, these rate
are offered after AMI has been fully deployed by 2021.
Table B-2 TOU Participation Rates (% of eligible customers)
Option Start Yr. Yr. 1 Yr. 2 Yr. 3 Yr. 4 Yrs. 5-19 Comments
Opt-in
Standalone
participation estimates
represent average
enrollment rates in
independent rate
offerings across full
scale deployments and
market research
studies.
(Source: Brattle's
Pricing Program
Database)
General Service &
Large General
Service
2021 1.3% 3.9% 7.8% 11.7% 13.0%
Extra Large General
Service 2016 1.3% 3.9% 7.8% 11.7% 13.0%
Opt-out
General Service &
Large General
Service
2021 100% 85.4% 78.9% 75.6% 74.0%
Extra Large General
Service 2016 100% 85.4% 78.9% 75.6% 74.0%

Per Participant Load Reduction
Table B-3 below presents assumed per participant load reduction in TOU rates by customer class.
The assumed impact values are based on a 2:1 peak to off-peak price ratio.
Table B-3 Per-Participant Load Reduction in TOU Rates by Customer Class
Customer Class Value Comments
General Service 0.2% These impacts assume 2:1 peak to off-peak
price ratio.
Source: Brattle's Database on Pricing
Programs.
Large General Service 2.6%
Extra Large General Service 3.1%

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Program Costs
The major cost components for implementation of time varying rates are the fixed annual costs
for administering the rates and providing billing analysis. For an opt-out offer, additional call
center staff may be required during the initial program years to handle the relatively large
volume of calls from customers defaulted to these rates. Table B-4 below shows itemized cost
assumptions for opt-in and opt-out TOU offers. We developed these assumptions in consultation
with the Avista team.
Table B-4 TOU Program Cost Assumptions for Opt-in and Opt-out Offers
Item Unit Value Comments
Costs Applicable to Opt-in and Opt-out:
Program Development
Cost $/program $170,000 One FTE at $170,000 annual cost to design the
TOU rates.
Annual Program
Administration Cost $/year $170,000 One FTE at $170,000 annual cost to administer
the TOU rates
Billing Analyst Cost $/year $105,000 One billing analyst at $105,000 in the call
center to provide customer service.
Billing system upgrade $ $7.5 million Avista provided this estimate; Avista has no
time-varying prices at the present time
Additional costs applicable to Opt-in:
Per Customer Annual
Marketing/Recruitment
Cost
$/new
participant/year
$10

Costs for TOU rates are assumed to be one fifth
the costs for dynamic rates such as CPP.
(Source: TVA Potential Study, 2011)
Additional costs applicable to Opt-out:
Additional call center
staff
$/year for first
two program
years
$255,000
We assumed that 3 additional call center staff
@$85,000 each annual cost to handle customer
calls for an opt-out rate.
Per Customer Annual
Marketing/Recruitment
Cost
$/new
participant/year $1 For opt-out TOU rates, these costs are assumed
to be a tenth of the costs for opt-in TOU rates.

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Applied Energy Group, Inc.
500 Ygnacio Valley Road, Suite 450
Walnut Creek, CA 94596
P: 510.982.3525 F: 925.284.3147
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Avista Electric Conservation Potential Assessment
Study
Final Report

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This report was prepared by
Applied Energy Group, Inc.
500 Ygnacio Valley Blvd., Suite 250
Walnut Creek, CA 94596

Project Director: I. Rohmund
Project Manager: B. Kester
F. Nguyen
S. Yoshida

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Contents
1 Introduction .............................................................................................................. 1
Abbreviations and Acronyms .............................................................................................. 2
2 Analysis Approach and Data Development ............................................................... 4
Overview of Analysis Approach .......................................................................................... 4
LoadMAP Model .................................................................................................... 4
Definitions of Potential .......................................................................................... 6
Market Characterization ......................................................................................... 6
Baseline Projection ................................................................................................ 8
Conservation Measure Analysis .............................................................................. 8
Conservation Potential ......................................................................................... 12
Data Development .......................................................................................................... 13
Data Sources ...................................................................................................... 13
Data Application .................................................................................................. 15
3 Market Characterization and Market Profiles .........................................................23
Energy Use Summary ...................................................................................................... 23
Residential Sector ........................................................................................................... 25
Commercial Sector .......................................................................................................... 32
Industrial Sector ............................................................................................................. 38
4 Baseline Projection .................................................................................................42
Residential Sector ........................................................................................................... 42
Annual Use ......................................................................................................... 42
Residential Summer Peak Projection ..................................................................... 45
Residential Winter Peak Projection ....................................................................... 47
Commercial Sector Baseline Projections ............................................................................ 48
Annual Use ......................................................................................................... 48
Commercial Summer Peak Demand Projection ...................................................... 51
Commercial Winter Peak Demand Projection ......................................................... 53
Industrial Sector Baseline Projections ............................................................................... 55
Annual Use ......................................................................................................... 55
Industrial Summer Peak Demand Projection ......................................................... 57
Industrial Winter Peak Demand Projection ............................................................ 59
Summary of Baseline Projections across Sectors and States ............................................... 61
Annual Use ......................................................................................................... 61
Summer Peak Demand Projection ........................................................................ 62
Winter Peak Demand Projection ........................................................................... 62
5 Conservation Potential ...........................................................................................64
Overall Summary of Energy Efficiency Potential ................................................................ 64
Summary of Annual Energy Savings ..................................................................... 64
Summary of Conservation Potential by Sector ................................................................... 68
Residential Conservation Potential .................................................................................... 69
Commercial Conservation Potential .................................................................................. 77
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Industrial Conservation Potential ...................................................................................... 83
A Market Profiles ............................................................................................................. 89
B Market Adoption (Ramp) Rates .................................................................................. 121
C Equipment Measure Data ........................................................................................... 122
D Non-Equipment Measure Data ............................................................................... D-123

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List of Figures
Figure 2-1 LoadMAP Analysis Framework ................................................................................... 5
Figure 2-2 Approach for Conservation Measure Assessment........................................................ 9
Figure 3-1 Sector-Level Electricity Use in Base Year 2013, Washington...................................... 23
Figure 3-2 Sector-Level Electricity Use in Base Year 2013, Idaho .............................................. 25
Figure 3-3 Residential Electricity Use and Summer Peak Demand by End Use (2013), Washington27
Figure 3-4 Residential Electricity Use and Summer Peak Demand by End Use (2013), Idaho ....... 28
Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2013), Washington . 29
Figure 3-6 Residential Intensity by End Use and Segment (Annual kWh/HH, 2013), Idaho ......... 29
Figure 3-7 Commercial Sector Electricity Consumption by End Use (2013), Washington.............. 33
Figure 3-8 Commercial Sector Electricity Consumption by End Use (2013), Idaho ...................... 34
Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2013), Washington ........... 35
Figure 3-10 Commercial Electricity Usage by End Use Segment (GWh, 2013), Idaho .................... 35
Figure 3-11 Industrial Electricity Use by End Use (2013), All Industries, WA and ID ..................... 39
Figure 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington ....................... 43
Figure 4-2 Residential Baseline Sales Projection by End Use – Annual Use per Household,
Washington ........................................................................................................... 44
Figure 4-3 Residential Baseline Projection by End Use (GWh), Idaho ......................................... 44
Figure 4-4 Residential Baseline Sales Projection by End Use – Annual Use per Household, Idaho 45
Figure 4-5 Residential Summer Peak Baseline Projection by End Use (MW), Washington ............ 46
Figure 4-6 Residential Summer Peak Baseline Projection by End Use (MW), Idaho ..................... 46
Figure 4-7 Residential Winter Peak Baseline Projection by End Use (MW), Washington ............... 48
Figure 4-8 Residential Winter Peak Baseline Projection by End Use (MW), Idaho ....................... 48
Figure 4-9 Commercial Baseline Projection by End Use, Washington ......................................... 50
Figure 4-10 Commercial Baseline Projection by End Use, Idaho .................................................. 50
Figure 4-11 Commercial Summer Peak Baseline Projection by End Use (MW), Washington ........... 52
Figure 4-12 Commercial Summer Peak Baseline Projection by End Use (MW), Idaho .................... 52
Figure 4-13 Commercial Winter Peak Baseline Projection by End Use (MW), Washington ............. 54
Figure 4-14 Commercial Winter Peak Baseline Projection by End Use (MW), Idaho ...................... 54
Figure 4-15 Industrial Baseline Projection by End Use (GWh), Washington .................................. 56
Figure 4-16 Industrial Baseline Projection by End Use (GWh), Idaho ........................................... 56
Figure 4-17 Industrial Summer Peak Baseline Projection by End Use (MW), Washington .............. 58
Figure 4-18 Industrial Summer Peak Baseline Projection by End Use (MW), Idaho ....................... 58
Figure 4-19 Industrial Winter Peak Baseline Projection by End Use (MW), Washington ................. 60
Figure 4-20 Industrial Winter Peak Baseline Projection by End Use (MW), Idaho ......................... 60
Figure 4-21 Baseline Projection Summary (GWh), WA and ID Combined ..................................... 61
Figure 4-22 Baseline Summer Peak Projection Summary (MW), WA and ID Combined ................. 62
Figure 4-23 Baseline Winter Peak Projection Summary (MW), WA and ID Combined .................... 63
Figure 5-1 Summary of EE Potential as % of Baseline Projection (Annual Energy), Washington .. 66
Figure 5-2 Summary of EE Potential as % of Baseline Projection (Annual Energy), Idaho ........... 66
Figure 5-3 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Washington ... 67
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Figure 5-4 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Idaho ............ 67
Figure 5-5 Achievable Conservation Potential by Sector (Annual Energy, GWh) .......................... 68
Figure 5-6 Residential Conservation Savings as a % of the Baseline Projection (Annual Energy),
Washington ........................................................................................................... 70
Figure 5-7 Residential Conservation Savings as a % of the Baseline Projection (Annual Energy),
Idaho .................................................................................................................... 71
Figure 5-8 Residential Achievable Savings Forecast (Cumulative GWh), Washington .................. 74
Figure 5-9 Residential Achievable Savings Forecast (Cumulative GWh), Idaho ........................... 76
Figure 5-10 Commercial Conservation Savings (Energy), Washington .......................................... 78
Figure 5-11 Commercial Conservation Savings (Energy), Idaho .................................................. 79
Figure 5-12 Commercial Achievable Savings Forecast (Cumulative GWh), Washington ................. 81
Figure 5-13 Commercial Achievable Savings Forecast (Cumulative GWh), Idaho .......................... 82
Figure 5-14 Industrial Conservation Potential as a % of the Baseline Projection (Annual Energy),
Washington ........................................................................................................... 84
Figure 5-15 Industrial Conservation Potential as a % of the Baseline Projection (Annual Energy),
Idaho .................................................................................................................... 85
Figure 5-16 Industrial Achievable Savings Forecast (Cumulative GWh), Washington..................... 87
Figure 5-17 Industrial Achievable Savings Forecast (Annual Energy, GWh), Idaho ....................... 88

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List of Tables
Table 1-1 Explanation of Abbreviations and Acronyms ............................................................... 2
Table 2-1 Overview of Avista Analysis Segmentation Scheme .................................................... 7
Table 2-2 Example Equipment Measures for Central AC – Single-Family Home ......................... 10
Table 2-3 Example Non-Equipment Measures – Single Family Home, Existing ........................... 11
Table 2-4 Number of Measures Evaluated .............................................................................. 11
Table 2-5 Data Applied for the Market Profiles ........................................................................ 16
Table 2-6 Residential Electric Equipment Standards ................................................................ 18
Table 2-7 Commercial Electric Equipment Standards ............................................................... 19
Table 2-8 Industrial Electric Equipment Standards .................................................................. 20
Table 2-9 Data Needs for the Measure Characteristics in LoadMAP .......................................... 21
Table 3-1 Avista Sector Control Totals (2013), Washington ..................................................... 24
Table 3-2 Avista Sector Control Totals (2013), Idaho .............................................................. 25
Table 3-3 Residential Sector Control Totals (2013), Washington .............................................. 26
Table 3-4 Residential Sector Control Totals (2013), Idaho ....................................................... 26
Table 3-5 Average Market Profile for the Residential Sector, 2013, Washington ........................ 30
Table 3-6 Average Market Profile for the Residential Sector, 2013, Idaho ................................. 31
Table 3-7 Commercial Sector Control Totals (2013), Washington ............................................. 32
Table 3-8 Commercial Sector Control Totals (2013), Idaho ...................................................... 32
Table 3-9 Average Electric Market Profile for the Commercial Sector, 2013, Washington ........... 36
Table 3-10 Average Electric Market Profile for the Commercial Sector, 2013, Idaho .................... 37
Table 3-11 Industrial Sector Control Totals (2013) .................................................................... 38
Table 3-12 Average Electric Market Profile for the Industrial Sector, 2013, Washington ............... 40
Table 3-13 Average Electric Market Profile for the Industrial Sector, 2013, Idaho ....................... 41
Table 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington ....................... 43
Table 4-2 Residential Baseline Sales Projection by End Use (GWh), Idaho ................................ 43
Table 4-3 Residential Summer Peak Baseline Projection by End Use (MW), Washington ............ 45
Table 4-4 Residential Summer Peak Baseline Projection by End Use (MW), Idaho ..................... 46
Table 4-5 Residential Winter Peak Baseline Projection by End Use (MW), Washington ............... 47
Table 4-6 Residential Winter Peak Baseline Projection by End Use (MW), Idaho ....................... 47
Table 4-7 Commercial Baseline Sales Projection by End Use (GWh), Washington ...................... 48
Table 4-8 Commercial Baseline Sales Projection by End Use (GWh), Idaho ............................... 49
Table 4-9 Commercial Summer Peak Baseline Projection by End Use (MW), Washington ........... 51
Table 4-10 Commercial Summer Peak Baseline Projection by End Use (MW), Idaho .................... 51
Table 4-11 Commercial Winter Peak Baseline Projection by End Use (MW), Washington ............. 53
Table 4-12 Commercial Winter Peak Baseline Projection by End Use (MW), Idaho ...................... 53
Table 4-13 Industrial Baseline Projection by End Use (GWh), Washington .................................. 55
Table 4-14 Industrial Baseline Projection by End Use (GWh), Idaho ........................................... 55
Table 4-15 Industrial Summer Peak Baseline Projection by End Use (MW), Washington .............. 57
Table 4-16 Industrial Summer Peak Baseline Projection by End Use (MW), Idaho ....................... 57
Table 4-17 Industrial Winter Peak Baseline Projection by End Use (MW), Washington ................. 59
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Table 4-18 Industrial Winter Peak Baseline Projection by End Use (MW), Idaho ......................... 59
Table 4-19 Baseline Projection Summary (GWh), WA and ID Combined ..................................... 61
Table 4-20 Baseline Summer Peak Projection Summary (MW), WA and ID Combined ................. 62
Table 4-21 Baseline Winter Peak Projection Summary (MW), WA and ID Combined .................... 62
Table 5-1 Summary of EE Potential (Annual Energy, GWh), Washington .................................. 65
Table 5-2 Summary of EE Potential (Annual Energy, GWh), Idaho ........................................... 65
Table 5-3 Achievable Conservation Potential by Sector (Annual Use), WA and ID ...................... 68
Table 5-4 Residential Conservation Potential (Annual Energy), Washington and Idaho .............. 69
Table 5-5 Residential Conservation Potential (Annual Energy), Washington .............................. 69
Table 5-6 Residential Conservation Potential (Annual Energy), Idaho ....................................... 70
Table 5-7 Residential Top Measures in 2017 (Annual Energy, MWh), Washington and Idaho ..... 72
Table 5-8 Residential Top Measures in 2017 (Annual Energy, MWh), Washington ..................... 73
Table 5-9 Residential Top Measures in 2017 (Annual Energy, MWh), Idaho .............................. 75
Table 5-10 Commercial Conservation Potential (Energy Savings), Washington and Idaho ............ 77
Table 5-11 Commercial Conservation Potential (Energy Savings), Washington ............................ 77
Table 5-12 Commercial Conservation Potential (Energy Savings), Idaho ..................................... 78
Table 5-13 Commercial Top Measures in 2017 (Annual Energy, MWh), Washington and Idaho .... 80
Table 5-14 Commercial Top Measures in 2017 (Annual Energy, MWh), Washington .................... 81
Table 5-15 Commercial Top Measures in 2017 (Annual Energy, MWh), Idaho ............................. 82
Table 5-16 Industrial Conservation Potential (Annual Energy, GWh), Washington and Idaho ....... 83
Table 5-17 Industrial Conservation Potential (Annual Energy, GWh), Washington ....................... 83
Table 5-18 Industrial Conservation Potential (Annual Energy, GWh), Idaho ................................ 84
Table 5-19 Industrial Top Measures in 2017 (Annual Energy, GWh), Washington and Idaho ....... 86
Table 5-20 Industrial Top Measures in 2017 (Annual Energy, GWh), Washington ....................... 87
Table 5-21 Industrial Top Measures in 2017 (Annual Energy, GWh), Idaho ................................ 88

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SECTION 1
Introduction
Avista Corporation (Avista) engaged Applied Energy Group (AEG, formerly EnerNOC Utility
Solutions) to conduct a Conservation Potential Assessment (CPA). The CPA is a 20-year study,
performed in accordance with Washington Initiative 937 (I-937), that provides data on
conservation resources to support development of Avista’s 2013 Integrated Resource Plan (IRP).
The study updates Avista’s last CPA, which AEG performed in 2013.
This study provided enhanced analysis compared to the previous studies.
 The base-year for the analysis was brought forward from 2011 to 2013.
 For the residential sector, the study incorporated Avista’s GenPOP residential saturation
survey from 2012. This provided the foundation for the base-year market characterization
and energy market profiles. The recently completed 2014 Residential Building Stock
Assessment (RBSA) supplemented the GenPOP survey.
 For the commercial sector, the analysis was performed for the major building types in the
service territory. Preliminary results from the 2015 Commercial Building Stock Assessment
(CBSA) provided useful information for this characterization.
 This study also incorporated changes to the list of energy conservation measures, as a result
of research by the Regional Technical Forum (RTF). In particular, LED lamps have dropped in
price and now provide a significant opportunity for savings.
 The study incorporates updated forecasting assumptions that line up with the most recent
Avista load forecast.
 Measure-adoption rates were developed using the Northwest Power and Conservation
Council’s (Council) ramp rates as a starting point and adjusted to reflect Avista program
results in recent years.
 Finally, in addition to analyzing annual energy savings, the study also estimated the
opportunity for reduction of summer peak demand. This involved a full characterization by
sector, segment and end use of summer peak demand in the base year.
Compared to the previous study, potential savings decreased. The 10-year potential for
Washington and Idaho in this CPA is 65.6 aMW, compared to 72.4 aMW from the previous study.
This is a result of lower avoided costs, the expected impact of the most recent wave of appliance
standards, the lighting standards in Energy Independence and Security Act (EISA) legislation,
and Avista’s recent capture of low-hanging fruit.

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Abbreviations and Acronyms
Throughout the report we use several abbreviations and acronyms. Table 1-1 shows the
abbreviation or acronym, along with an explanation.
Table 1-1 Explanation of Abbreviations and Acronyms
Acronym Explanation
aMW Average annual megawatt
ACS American Community Survey
AEO Annual Energy Outlook forecast developed by EIA
AHAM Association of Home Appliance Manufacturers
AMI Advanced Metering Infrastructure
AMR Automated Meter Reading
Auto-DR Automated Demand Response
B/C Ratio Benefit to Cost Ratio
BEST AEG’s Building Energy Simulation Tool
C&I Commercial and Industrial
CAC Central Air Conditioning
CBSA Commercial Building Stock Assessment
CFL Compact fluorescent lamp
CBECS Commercial Buildings Energy Consumption Survey
CHP Combined Heat and Power
Council Northwest Power and Conservation Council
CPA Conservation Potential Assessment
CPP Critical Peak Pricing
CPUC California Public Utilities Commission
DEEM Database of Energy Efficiency Measures
DEER Database for Energy Efficient Resources
DHW Domestic Hot Water
DLC Direct Load Control
DOE Department of Energy
DR Demand Response
DSM Demand Side Management
EE Energy Efficiency
EIA Energy Information Administration
EISA Energy Independence and Security Act
EPA Environmental Protection Agency
EPRI Electric Power Research Institute
EUL Estimated Useful Life
EUI Energy Use Intensity
FERC Federal Energy Regulatory Commission
GWh Gigawatt-hour
HH Household
HID High intensity discharge lamps
HVAC Heating Ventilation and Air Conditioning
KWh Kilowatt-hour
I-937 Washington Initiative 937
ICAP Installed Capacity
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Acronym Explanation
IOU Investor Owned Utility
IRP Integrated Resource Plan
LED Light emitting diode lamp
LoadMAP AEG’s Load Management Analysis and PlanningTM tool
MECS Manufacturing Energy Consumption Survey
MW Megawatt
NAPEE National Action Plan for Energy-Efficiency
NEEA Northwest Energy Efficiency Alliance
NOAA National Oceanic and Atmospheric Administration
NPV Net Present Value
NPCC Northwest Power and Conservation Council
O&M Operations and Maintenance
PCT Programmable Communicating Thermostat
RBSA Residential Building Stock Assessment
RECS Residential Energy Consumption Survey
RTF Regional Technical Forum
RTU Roof top unit
SEER Seasonal Energy Efficiency Ratio
SIC Standard Industrial Classification
Sixth Plan Sixth Northwest Conservation and Electric Power Plan
TRC Total Resource Cost test
UEC Unit Energy Consumption
WH Water heater
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SECTION 2
Analysis Approach and Data Development
This section describes the analysis approach taken for the study and the data sources used to
develop the potential estimates.
Overview of Analysis Approach
To perform the potential analysis, AEG used a bottom-up approach following the major steps
listed below. We describe these analysis steps in more detail throughout the remainder of this
chapter.
1. Perform a market characterization to describe sector-level electricity use for the residential,
commercial, and industrial sectors for the base year, 2013.
2. Develop a baseline projection of energy consumption and peak demand by sector, segment,
and end use for 2013 through 2035.
3. Define and characterize several hundred conservation measures to be applied to all sectors,
segments, and end uses.
4. Estimate technical, economic, and achievable potential at the measure level in terms of
energy and peak demand impacts from conservation measures for 2015-2035.
LoadMAP Model
AEG used its Load Management Analysis and Planning tool (LoadMAPTM) version 4.0 to develop
both the baseline projection and the estimates of potential. AEG developed LoadMAP in 2007 and
has enhanced it over time, using it for the Electric Power Research Institute (EPRI) National
Potential Study and numerous utility-specific forecasting and potential studies since that time.
Built in Excel, the LoadMAP framework (see Figure 2-1) 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 and appliance vintage distributions 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 and existing buildings 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.
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 Includes appliance and equipment models customized by end use. For example, the logic for
lighting 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).
 Incorporates conservation measures, demand-response options, combined heat and power
(CHP) and distributed generation options and fuel switching.
Consistent with the segmentation scheme and the market profiles we describe below, the
LoadMAP model provides projections of baseline energy use by sector, segment, end use, and
technology for existing and new buildings. It also provides forecasts of total energy use and
energy-efficiency savings associated with the various types of potential.1
Figure 2-1 LoadMAP Analysis Framework

1 The model computes energy and peak-demand forecasts for each type of potential for each end use as an intermediate calculation.
Annual-energy and peak-demand savings are calculated as the difference between the value in the baseline projection and the value in
the potential forecast (e.g., the technical potential forecast).
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Definitions of Potential
In this study, the conservation potential estimates represent gross savings developed for three
levels of potential: technical potential, economic potential, and achievable potential. These levels
are described below.
 Technical Potential is defined as the theoretical upper limit of conservation potential. It
assumes that customers adopt all feasible measures regardless of their cost. At the time of
existing 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.

Technical potential also assumes the adoption of every other available 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. These retrofit measures are phased in over a number of
years to align with the stock turnover of related equipment units, rather than modeled as
immediately available all at once.
 Economic Potential represents the adoption of all cost-effective conservation measures.
In this analysis, the cost-effectiveness is measured by the total resource cost (TRC) test,
which compares lifetime energy and capacity benefits to the costs of the delivering the
measure through a utility program, with incentives not included since they are a transfer
payment. If the benefits outweigh the costs (that is, if the TRC ratio is equal to or greater
than 1.0), a given measure is included in the economic potential. Customers are then
assumed to purchase the most cost-effective option applicable to them at any decision
juncture.
 Achievable Potential takes into account market maturity, customer preferences for energy-
efficient technologies, and expected program participation. Achievable potential establishes a
realistic target for the conservation savings that a utility can hope to achieve through its
programs. It is determined by applying a series of annual market adoption factors to the
economic potential for each conservation measure. These factors represent the ramp rates at
which technologies will penetrate the market. To develop these factors, the project team
reviewed Avista’s past conservation achievements and program history over the last five
years, as well as the Northwest Power and Conservation Council’s (Council) ramp rates used
in the Council’s Sixth Plan. Details regarding the market adoption factors appear in Appendix
B.
Market Characterization
Now that we have described the modeling tool and provided the definitions of the potential
cases, the first step in the analysis approach is market characterization. In order to estimate the
savings potential from energy-efficient measures, it is necessary to understand how much energy
is used today and what equipment is currently being used. This characterization begins with a
segmentation of Avista’s electricity footprint to quantify energy use by sector, segment, end-use
application, and the current set of technologies used. We rely primarily on information from
Avista, Northwest Energy Efficiency Alliance (NEEA) and secondary sources as necessary.
Segmentation for Modeling Purposes
The market assessment first defined the market segments (building types, end uses, and other
dimensions) that are relevant in the Avista service territory. The segmentation scheme for this
project is presented in Table 2-1. Note that the low income segment is defined as 200% of the
poverty level. Assuming 2.5 people per household, this is approximately annual household
income of $35,000. The distribution to residential segment is based on the results of the Avista
GenPOP survey.

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Table 2-1 Overview of Avista Analysis Segmentation Scheme
Dimension Segmentation Variable Description
1 Sector Residential, commercial, industrial
2 Segment
Residential: single family, multi family, manufactured
home, low income
Commercial: small office, large office, restaurant,
retail, grocery, college, school, health, lodging,
warehouse, and miscellaneous
Industrial: total
3 Vintage Existing and new construction
4 End uses Cooling, lighting, water heat, motors, etc. (as
appropriate by sector)
5 Appliances/end uses and
technologies
Technologies such as lamp type, air conditioning
equipment, motors by application, etc.
6 Equipment efficiency levels for
new purchases
Baseline and higher-efficiency options as appropriate
for each technology

With the segmentation scheme defined, we then performed a high-level market characterization
of electricity sales in the base year to allocate sales to each customer segment. We used Avista
data and secondary sources to allocate energy use and customers to the various sectors and
segments such that the total customer count, energy consumption, and peak demand matched
the Avista system totals from 2013 billing data. This information provided control totals at a
sector level for calibrating the LoadMAP model to known data for the base-year.
Market Profiles
The next step was to develop market profiles for each sector, customer segment, end use, and
technology. A market profile includes the following elements:
 Market size is a representation of the number of customers in the segment. For the
residential sector, it is number of households. In the commercial sector, it is floor space
measured in square feet. For the industrial sector, it is overall electricity use.
 Saturations define the fraction of homes or square feet with the various technologies. (e.g.,
homes with electric space heating).
 UEC (unit energy consumption) or EUI (energy-use intensity) describes the amount
of energy consumed in 2013 by a specific technology in buildings that have the technology.
For electricity, UECs are expressed in kWh/household for the residential sector, and EUIs are
expressed in kWh/square foot for the commercial sector.
 Annual Energy Intensity for the residential sector represents the average energy use for
the technology across all homes in 2013. It is computed as the product of the saturation and
the UEC and is defined as kWh/household for electricity. For the commercial sector, intensity,
computed as the product of the saturation and the EUI, represents the average use for the
technology across all floor space in 2013.
 Annual Usage is the annual energy use by an end-use technology in the segment. It is the
product of the market size and intensity and is quantified in gigawatt-hour (GWh).
 Peak Demand for each technology, summer peak and winter peak are calculated using
peak fractions of annual energy use from AEG’s EnergyShape library and Avista system peak
data.
The market characterization results and the market profiles are presented in Chapter 3.
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Baseline Projection
The next step was to develop the baseline projection of annual electricity use and summer peak
demand for 2013 through 2034 by customer segment and end use without new utility programs.
The end-use projection includes the relatively certain impacts of codes and standards that will
unfold over the study timeframe. All such mandates that were defined as of December 2013 are
included in the baseline. The baseline projection is the foundation for the analysis of savings
from future conservation efforts as well as the metric against which potential savings are
measured.
Inputs to the baseline projection include:
 Current economic growth forecasts (i.e., customer growth, income growth)
 Electricity price forecasts
 Trends in fuel shares and equipment saturations
 Existing and approved changes to building codes and equipment standards
 Avista’s internally developed sector-level projections for electricity sales
We also developed a baseline projection for summer and winter peak by applying the peak
fractions from the energy market profiles to the annual energy forecast in each year.
We present the baseline-projection results for the system as a whole and for each sector in
Chapter 4.
Conservation Measure Analysis
This section describes the framework used to assess the savings, costs, and other attributes of
conservation measures. These characteristics form the basis for measure-level cost-effectiveness
analyses as well as for determining measure-level savings. For all measures, AEG assembled
information to reflect equipment performance, incremental costs, and equipment lifetimes. We
used this information, along with Avista’s avoided costs data, in the economic screen to
determine economically feasible measures.
Conservation Measures
Figure 2-2 outlines the framework for conservation measure analysis. The framework for
assessing savings, costs, and other attributes of conservation 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 or early replacement of equipment, improvements to the
building envelope, the application of controls to optimize energy use, and other actions resulting
in improved energy efficiency.
We compiled a robust list of conservation measures for each customer sector, drawing upon
Avista’s measure database, and the Regional Technical Forum (RTF) deemed measures
databases, as well as a variety of secondary sources. This universal list of conservation measures
covers all major types of end-use equipment, as well as devices and actions to reduce energy
consumption. If considered today, some of these measures would not pass the economic screens
initially, but may pass in future years as a result of lower projected equipment costs or higher
avoided costs.

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Figure 2-2 Approach for Conservation Measure Assessment

The selected measures are categorized into two types according to the LoadMAP taxonomy:
equipment measures and non-equipment measures.
 Equipment measures are efficient energy-consuming pieces of equipment that save energy
by providing the same service with a lower energy requirement than a standard unit. An
example is an ENERGY STAR refrigerator that replaces a standard efficiency refrigerator. For
equipment measures, many efficiency levels may be available for a given technology, ranging
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 current federal standard SEER 13 unit and spans a broad spectrum up to a
maximum efficiency of a SEER 24 unit.
 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 to run
heating and cooling systems only when people are home. Non-equipment measures can
apply to more than one end use. For instance, addition of wall insulation will affect the
energy use of both space heating and cooling. Non-equipment measures typically fall into
one of the following categories:
o Building shell (windows, insulation, roofing material)
o Equipment controls (thermostat, energy management system)
o Equipment maintenance (cleaning filters, changing setpoints)
o Whole-building design (building orientation, passive solar lighting)
o Lighting retrofits (included as a non-equipment measure because retrofits are performed
prior to the equipment’s normal end of life)
Economic screen
Measure characterization
Measure
descriptions
Energy savings Costs
Lifetime Saturation and
applicability
AEG
universal measure list
Building simulations
AEG measure
data library
Client measure data
library
(TRMs, evaluation
reports, etc)
Avoided costs,
discount rate, delivery
losses
Client review /
feedback
Inputs Process
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o Displacement measures (ceiling fan to reduce use of central air conditioners)
o Commissioning and retro commissioning (initial or ongoing monitoring of building energy
systems to optimize energy use)
We developed a preliminary list of conservation measures, which was distributed to the Avista
project team for review. The list was finalized after incorporating comments and is presented in
the appendix to this volume.
Once we assembled the list of conservation measures, the project team characterized measure
savings, incremental cost, service life, and other performance factors, drawing upon data from
the Avista measure database, the RTF deemed measure workbooks, and simulation modeling.
Following the measure characterization, we performed an economic screening of each measure,
which serves as the basis for developing the economic and achievable potential.
Representative Conservation Measure Data Inputs
To provide an example of the conservation measure data, Table 2-2 and Table 2-3 present
examples of the detailed data inputs behind both equipment and non-equipment measures,
respectively, for the case of residential central air conditioning (CAC) in single-family homes.
Table 2-2 displays the various efficiency levels available as equipment measures, as well as the
corresponding useful life, energy usage, and cost estimates. The columns labeled On Market and
Off Market reflect equipment availability due to codes and standards or the entry of new
products to the market.
Table 2-2 Example Equipment Measures for Central AC – Single-Family Home
Efficiency Level Useful Life
(yrs)
Equipment
Cost
Energy
Usage
(kWh/yr)
On
Market
Off
Market
SEER 13 14 to 20 $2,549 1,466 2013 n/a
SEER 14 (Energy Star) 14 to 20 $3,072 1,344 2013 n/a
SEER 15 (CEE Tier 2) 14 to 20 $3,158 1,300 2013 n/a
SEER 16 (CEE Tier 3) 14 to 20 $3,148 1,262 2013 n/a
SEER 18 14 to 20 $3,708 1,203 2013 n/a
SEER 21 14 to20 $4,090 1,139 2013 n/a
SEER 24 (Ductless, Var. Ref. Flow) 14 to 20 $4,946 1,094 2013 n/a

Table 2-3 lists some of the non-equipment measures applicable to CAC in an existing single-
family home. All measures are evaluated for cost-effectiveness based on the lifetime benefits
relative to the cost of the measure. The total savings and costs are calculated for each year of
the study and depend on the base year saturation of the measure, the applicability2 of the
measure, and the savings as a percentage of the relevant energy end uses.

2 The applicability factors take into account whether the measure is applicable to a particular building type and whether it is feasible to
install the measure. For instance, attic fans are not applicable to homes where there is insufficient space in the attic or there is no attic
at all.
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Table 2-3 Example Non-Equipment Measures – Single Family Home, Existing
End Use Measure Saturation
in 20133
Applica-
bility
Lifetime
(yrs)
Measure
Installed
Cost
Energy
Savings (%)
Cooling Insulation - Ceiling 35% 50.0% 45 $1,134 5%
Cooling Insulation - Radiant Barrier 15% 75.0% 15 $1,245 13%
Cooling Ducting - Repair and Sealing 15% 50.0% 20 $538 5%
Cooling Windows - High Efficiency 20% 75.0% 45 $2,908 9%
Cooling Thermostat - Clock/Programmable 30% 40.0% 15 $230 4%
Screening Measures for Cost-Effectiveness
Only measures that are cost-effective are included in economic and achievable potential.
Therefore, for each individual measure, LoadMAP performs an economic screen. This study uses
the TRC test that compares the lifetime energy and peak demand benefits of each applicable
measure with its cost. The lifetime benefits are calculated 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. Lifetime costs represent
incremental measure cost and annual operations and maintenance (O&M) costs. The analysis
uses each measure’s values for savings, costs, and lifetimes that were developed as part of the
measure characterization process described above.
The LoadMAP model performs this 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 projection.
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.
 If multiple equipment measures have benefit to cost ratios (B/C ratios) greater than or equal
to 1.0, the most efficient technology is selected by the economic screen.
Table 2-4 summarizes the number of measures evaluated for each segment within each sector.
Table 2-4 Number of Measures Evaluated
Sector Total Measures
Measure
Permutations w/ 2
Vintages
Measure
Permutations w/
Segments
Residential 60 120 480
Commercial 82 164 1,804
Industrial 57 114 114
Total Measures Evaluated 199 398 2,398

3 Note that saturation levels reflected for the base year change over time as more measures are adopted.
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The appendix to this volume presents results for the economic screening process by segment,
vintage, end use and measure for all sectors.
Conservation Potential
The approach we used for this study to calculate the conservation potential 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 conservation potential. As described
in Chapter 2, three types of potential were developed as part of this effort: technical potential,
economic potential and achievable potential.
 Technical potential 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 “chooses” the most efficient equipment options for each technology at the time of
equipment replacement. In addition, it installs all relevant non-equipment measures for each
technology to calculate savings. For example, for central air conditioning, as shown in Table
2-2, the most efficient option is a SEER 24. The multiple non-equipment measures shown in
Table 2-3 are then applied to the energy used by the SEER 24 system to further reduce air
conditioning 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.
 Economic potential results from the purchase of the most efficient cost-effective option
available for a given equipment or non-equipment measure as determined in the cost-
effectiveness screening process described above. 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 defines the range of savings that is very likely to occur. It accounts
for customers’ awareness of efficiency options, any barriers to customer adoption, limits to
program design, and other factors that influence the rate at which conservation measures
penetrate the market.
The calculation of technical and economic potential is a straightforward algorithm. To develop
estimates for achievable potential, we develop market adoption rates for each measure that
specify the percentage of customers that will select the highest–efficiency economic option. For
Avista, the project team began with the ramp rates specified in the Sixth Plan conservation
workbooks, but modified these to match Avista program history and service territory specifics.
For specific measures, we examined historic program results for the most recent program results.
We then adjusted the 2014 achievable potential for these measures to approximately match the
historical results. This provided a starting for 2014 potential that was aligned to historic results.
For future years, we increased the potential factors to model increasing market acceptance and
program improvements. For measures not currently included in Avista programs, we relied upon
the Sixth Plan ramp rates and recent AEG potential studies to create market adoption rates for
Avista. The market adoption rates for each measure appear in Appendix B.
Results of all the potentials analysis are presented in Chapter 5.

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.
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Data Development
This section details the data sources used in this study, followed by a discussion of how these
sources were applied. In general, data sources were applied in the following order: Avista data,
Northwest data and, finally, other secondary sources.
Data Sources
The data sources are organized into the following categories:
 Avista data
 Northwest Energy Efficiency Alliance data
 Measure data
 AEG’s databases and analysis tools
 Other secondary data and reports
Avista Data
Our highest priority data sources for this study were those that were specific to Avista.
 Avista customer data: Avista provided billing data for development of customer counts
and energy use for each sector. We also used the results of the Avista GenPOP survey, a
residential saturation survey.
 Load forecasts: Avista provided an economic growth forecast by sector; electric load
forecast; peak-demand forecasts at the sector level; and retail electricity price history and
forecasts.
 Economic information: Avista Power provided avoided cost forecasts, a discount rate, and
line loss factor.
 Avista program data: Avista provided information about past and current programs,
including program descriptions, goals, and achievements to date.
Northwest Energy Efficiency Alliance Data
The Northwest Energy Efficiency Alliance conducts research on an ongoing basis for the
Northwest region. The following studies were particularly useful for this study:
 Northwest Energy Efficiency Alliance, 2011 Residential Building Stock Assessment
Single-Family, Market Research Report, http://neea.org/docs/reports/residential-building-
stock-assessment-single-family-characteristics-and-energy-use.pdf?sfvrsn=8
 Northwest Energy Efficiency Alliance, 2011 Residential Building Stock
Assessment: Manufactured Home, Market Research Report, #E13-249, January, 2013.
http://neea.org/docs/default-source/reports/residential-building-stock-assessment--
manufactured-homes-characteristics-and-energy-use.pdf?sfvrsn=8
 Northwest Energy Efficiency Alliance, Long-Term Northwest Residential Lighting
Tracking and Monitoring Study, Market Research Report, 11-228, August, 2011.
http://neea.org/research/reports/E11-231_Combinedv2.pdf
 Northwest Energy Efficiency Alliance, 2011 Residential Building Stock
Assessment: Multifamily, Market Research Report, #13-263, September, 2013.
http://neea.org/docs/default-source/reports/residential-building-stock-assessment--multi-
family-characteristics-and-energy-use.pdf?sfvrsn=4
 Northwest Energy Efficiency Alliance, 2014 Commercial Building Stock
Assessment, December 16, 2014, http://neea.org/docs/default-source/reports/2014-cbsa-
final-report_05-dec-2014.pdf?sfvrsn=12.
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Conservation Measure Data
Several sources of data were used to characterize the conservation measures. We used the
following regional data sources and supplemented with AEG’s data sources to fill in any gaps.
 Northwest Power and Conservation Council Sixth Plan Conservation Supply Curve
Workbooks. To develop its Sixth Power Plan, the Council used workbooks with detailed
information about measures, available at
http://www.nwcouncil.org/energy/powerplan/6/supplycurves/default.htm .
 Regional Technical Forum Deemed Measures. The NPCC Regional Technical Forum
maintains databases of deemed measure savings data, available at
http://www.nwcouncil.org/energy/rtf/measures/Default.asp .
AEG Data
AEG maintains several databases and modeling tools that we use for forecasting and potential
studies. Relevant data from these tools has been incorporated into the analysis and deliverables
for this study.
 AEG Energy Market Profiles: For more than 10 years, AEG staff has maintained profiles of
end-use consumption for the residential, commercial, and industrial sectors. These profiles
include market size, fuel shares, unit consumption estimates, and annual energy use by fuel
(electricity and natural gas), customer segment and end use for 10 regions in the U.S. The
Energy Information Administration surveys (RECS, CBECS and MECS) as well as state-level
statistics and local customer research provide the foundation for these regional profiles.
 Building Energy Simulation Tool (BEST). AEG’s BEST is a derivative of the Department
of Energy (DOE) 2.2 building simulation model, used to estimate base-year UECs and EUIs,
as well as measure savings for heating, ventilation and air conditioning (HVAC)-related
measures.
 AEG’s EnergyShape™: This database of load shapes includes the following:
o Residential – electric load shapes for ten regions, three housing types, 13 end uses
o Commercial – electric load shapes for nine regions, 54 building types, ten end uses
o Industrial – electric load shapes, whole facility only, 19 2-digit SIC codes, as well as various 3-digit
and 4-digit SIC codes
 AEG’s Database of Energy Efficiency Measures (DEEM): AEG maintains an extensive
database of measure data for our studies. Our database draws upon reliable sources
including the California Database for Energy Efficient Resources (DEER), the Energy
Information Administration (EIA) Technology Forecast Updates – Residential and Commercial
Building Technologies – Reference Case, RS Means cost data, and Grainger Catalog Cost
data.
 Recent studies. AEG has conducted numerous studies of conservation potential in the last
five years. We checked our input assumptions and analysis results against the results from
these other studies, which include Tacoma Power, Idaho Power, PacifiCorp, Ameren Missouri,
Vectren Energy, Indianapolis Power & Light, Tennessee Valley Authority, Ameren Missouri,
Ameren Illinois, and Seattle City Light. In addition, we used the information about impacts of
building codes and appliance standards from recent reports for the Edison Electric Institute5.

5 AEG staff has prepared three white papers on the topic of factors that affect U.S. electricity consumption,
including appliance standards and building codes. Links to all three white papers are provided:
http://www.edisonfoundation.net/IEE/Documents/IEE_RohmundApplianceStandardsEfficiencyCodes1209.pdf
http://www.edisonfoundation.net/iee/Documents/IEE_CodesandStandardsAssessment_2010-2025_UPDATE.pdf.
http://www.edisonfoundation.net/iee/Documents/IEE_FactorsAffectingUSElecConsumption_Final.pdf
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Other Secondary Data and Reports
Finally, a variety of secondary data sources and reports were used for this study. The main
sources are identified below.
 Annual Energy Outlook. The Annual Energy Outlook (AEO), conducted each year by the
U.S. Energy Information Administration (EIA), presents yearly projections and analysis of
energy topics. For this study, we used data from the 2013 AEO.
 Local Weather Data: Weather from NOAA’s National Climatic Data Center for Spokane, WA
was used as the basis for building simulations.
 EPRI End-Use Models (REEPS and COMMEND). These models provide the elasticities we
apply to electricity prices, household income, home size and heating and cooling.
 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) for the state of California. We used the DEER database
to cross check the measure savings we developed using BEST and DEEM.
 Other relevant regional sources: These include reports from the Consortium for Energy
Efficiency, the Environmental Protection Agency (EPA), and the American Council for an
Energy-Efficient Economy.
Data Application
We now discuss how the data sources described above were used for each step of the study.
Data Application for Market Characterization
To construct the high-level market characterization of electricity use and households/floor space
for the residential, commercial and industrial sectors, we used Avista billing data and customer
surveys to estimate energy use.
 For the residential sector, Avista estimated the numbers of customers and the average
energy use per customer for each of the three segments, based on its GenPOP survey,
matched to billing data for surveyed customers. AEG compared the resulting segmentation
with data from the American Community Survey (ACS) regarding housing types and income
and found that the Avista segmentation corresponded well with the ACS data. (See Chapter 3
for additional details.)
 To segment the commercial and industrial segments, we relied upon the allocation from the
previous energy efficiency potential study. For the previous study, customers and sales were
allocated to building type based on standard industrial classification (SIC) codes, with some
adjustments between the commercial and industrial sectors to better group energy use by
facility type and predominate end uses. (See Chapter 3 for additional details.)
Data Application for Market Profiles
The specific data elements for the market profiles, together with the key data sources, are
shown in Table 2-5. To develop the market profiles for each segment, we did the following:
1. Developed control totals for each segment. These include market size, segment-level annual
electricity use, and annual intensity.
2. Used the Avista GenPOP Survey, NEEA’s RBSA, NEEA’s CBSA and AEG’s Energy Market
Profiles database to develop existing appliance saturations, appliance and equipment
characteristics, and building characteristics.

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3. Ensured calibration to control totals for annual electricity sales in each sector and segment.
4. Compared and cross-checked with other recent AEG studies.
5. Worked with Avista staff to vet the data against their knowledge and experience.
Data Application for Baseline Projection
Table 2-5 summarizes the LoadMAP model inputs required for the baseline projection. These
inputs are required for each segment within each sector, as well as for new construction and
existing dwellings/buildings.
Table 2-5 Data Applied for the Market Profiles
Model Inputs Description Key Sources
Market size Base-year residential dwellings, commercial
floor space, and industrial employment
Avista billing data
Avista GenPOP Survey
NEEA RBSA and CBSA
AEO 2013
Annual intensity
Residential: Annual use per household
Commercial: Annual use per square foot
Industrial: Annual use per employee
Avista billing data
AEG’s Energy Market Profiles
NEEA RBSA and CBSA
AEO 2013
Other recent studies
Appliance/equipment
saturations
Fraction of dwellings with an
appliance/technology
Percentage of C&I floor space/employment
with equipment/technology
Avista GenPOP Survey
NEEA RBSA and CBSA
AEG’s Energy Market Profiles
Avista Load Forecasting
UEC/EUI for each end-
use technology
UEC: Annual electricity use in homes and
buildings that have the technology
EUI: Annual electricity use per square
foot/employee for a technology in floor
space that has the technology
NPCC Sixth Plan and RTF data
HVAC uses: BEST simulations using
prototypes developed for Idaho
Engineering analysis
DEEM
Recent AEG studies
Appliance/equipment
age distribution Age distribution for each technology
NPCC Sixth Plan and RTF data
NEEA regional survey data
Utility saturation surveys
Recent AEG studies
Efficiency options for
each technology
List of available efficiency options and
annual energy use for each technology
AEG DEEM
AEO 2013
DEER
NPCC workbooks, RTF
Previous studies
Peak factors Share of technology energy use that occurs
during the peak hour EnergyShape database

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Table 2-5 Data Needs for the Baseline Projection and Potentials Estimation in LoadMAP
Model Inputs Description Key Sources
Customer growth forecasts Forecasts of new construction in
residential and C&I sectors
Avista load forecast
AEO 2013 economic growth
forecast
Equipment purchase
shares for baseline
projection
For each equipment/technology,
purchase shares for each efficiency
level; specified separately for existing
equipment replacement and new
construction
Shipments data from AEO
AEO 2013 regional forecast
assumptions6
Appliance/efficiency standards
analysis
Avista program results and
evaluation reports
Electricity prices Forecast of average energy and capacity
avoided costs and retail prices Avista forecast
Utilization model
parameters
Price elasticities, elasticities for other
variables (income, weather)
EPRI’s REEPS and COMMEND
models
AEO 2013

In addition, we implemented assumptions for known future equipment standards as of December
2013, as shown in Table 2-6, Table 2-7 and Table 2-8. The assumptions tables here extend
through 2025, after which all standards are assumed to hold steady.

6 We developed baseline purchase decisions using the Energy Information Agency’s Annual Energy Outlook report (2013), 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 then held values constant for the study period.
This removes any effects of naturally occurring conservation or effects of future EE programs that may be embedded in the AEO
forecasts.
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Table 2-6 Residential Electric Equipment Standards7

7 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
2013's Efficiency or Standard Assumption 1st Standard (relative to 2013's standard)
2nd Standard (relative to 2013's standard)
End Use Technology 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Central AC
Room AC
Evaporative Central AC
Evaporative Room AC
Cooling/Heating Heat Pump
Space Heating Electric Resistance
Water Heater (<=55 gallons)
Water Heater (>55 gallons)
Screw-in/Pin Lamps
Linear Fluorescent
Refrigerator/2nd Refrigerator
Freezer
Dishwasher
Clothes Washer
Clothes Dryer
Microwave Ovens
Miscellaneous Furnace Fans Conventional
14% more efficient than 2010 standard (307 kWh/yr)
MEF 1.72 for top loader MEF 2.0 for top loaderConventional (MEF
1.26 for top loader)
40% more efficient
Lighting Advanced Incandescent - tier 1 (20 lumens/watt)Incandescent
NAECA
Standard
NAECA
Standard
Appliances
1.0 Watts (maximum standby power)
EF 3.73
25% more efficient
25% more efficient
Conventional (EF 3.01)
Conventional
Advanced Incandescent - tier 2 (45 lumens/watt)
T8 (89 lumens/watt)T8 (92.5 lumens/watt)
Water Heating EF 0.95
Heat Pump Water Heater
Cooling EER 11.0
SEER 13
EER 9.8
Conventional
Conventional
SEER 14.0/HSPF 8.2SEER 13.0/HSPF 7.7
Electric Resistance
EF 0.90
EF 0.90
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Table 2-7 Commercial Electric Equipment Standards8

8 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
2013's Efficiency or Standard Assumption 1st Standard (relative to 2013's standard)
2nd Standard (relative to 2013's standard)
End Use Technology 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Chillers
Roof Top Units
Packaged Terminal AC/HP
Cooling/Heating Heat Pump
Ventilation Ventilation
Screw-in/Pin Lamps
Linear Fluorescent
High Intensity Discharge
Water Heating Water Heater
Walk-in Refrigerator/Freezer
Reach-in Refrigerator
Glass Door Display
Open Display Case
Vending Machines
Ice maker
Miscellaneous Non-HVAC Motors
Cooling
Advanced Incandescent - tier 2 (45 lumens/watt)
2007 ASHRAE 90.1
EER 11.0/11.2
EER 11.0/11.2
EER 11.0/COP 3.3
Constant Air Volume/Variable Air Volume
Incandescent Advanced Incandescent - tier 1 (20 lumens/watt)
Refrigeration
Lighting
EF 0.97
EISA 2007 Standard
EPACT 2005 Standard
EPACT 2005 Standard
EPACT 2005 Standard
33% more efficient than EPAC 2005 Standard
2010 Standard 15% more efficient
40% more efficient
12-28% more efficient
T8 (89 lumens/watt)T8 (92.5 lumens/watt)
10-20% more efficient
Expanded EISA 2007 StandardsEISA 2007 Standards
10-38% more efficient
EPACT 2005 (Mercury Vapor Fixture
Phase-out)Metal Halide Ballast Improvement
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Table 2-8 Industrial Electric Equipment Standards9

9 The assumptions tables here extend through 2025, after which all standards are assumed to hold steady.
2013's Efficiency or Standard Assumption 1st Standard (relative to 2013's standard)
2nd Standard (relative to 2013's standard)
End Use Technology 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Chillers
Roof Top Units
Packaged Terminal AC/HP
Cooling/Heating Heat Pump
Ventilation Ventilation
Screw-in/Pin Lamps
Linear Fluorescent
High Intensity Discharge
Motors
Pumps, Fans & Blowers,
Compressed Air, Material
Handling and Processing
Constant Air Volume/Variable Air Volume
Incandescent
Lighting
Advanced Incandescent - tier 1 (20 lumens/watt)Advanced Incandescent - tier 2 (45 lumens/watt)
Cooling
2007 ASHRAE 90.1
EER 11.0/11.2
EER 11.0
EER 11.0/COP 3.3
Expanded EISA 2007 Standards
EPACT 2005 (Mercury Vapor Fixture
Phase-out)Metal Halide Ballast Improvement
T8 (89 lumens/watt)T8 (92.5 lumens/watt)
EISA 2007 Standards
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Conservation Measure Data Application
Table 2-9 details the energy-efficiency data inputs to the LoadMAP model. It describes each
input and identifies the key sources used in the Avista analysis.
Table 2-9 Data Needs for the Measure Characteristics in LoadMAP
Model Inputs Description Key Sources
Energy Impacts
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.
Avista measure data
NPCC Sixth Plan
conservation workbooks
BEST
AEG DEEM
AEO 2013
DEER
NPCC workbooks, RTF
Other secondary sources
Peak Demand Impacts
Savings during the peak demand periods are
specified for each electric measure. These impacts
relate to the energy savings and depend on the
extent to which each measure is coincident with
the system peak.
Avista measure data
NPCC Sixth Plan
conservation workbooks
BEST
AEG DEEM
EnergyShape
Costs
Equipment Measures: Includes the full cost of
purchasing and installing the equipment on a per-
household, per-square-foot, per employee or per
service point basis for the residential, commercial,
and industrial sectors, respectively.
Non-equipment measures: Existing buildings – full
installed cost. New Construction - the costs may be
either the full cost of the measure, or as
appropriate, it may be the incremental cost of
upgrading from a standard level to a higher
efficiency level.
Avista measure data
NPCC Sixth Plan
conservation workbooks
RTF deemed measure
database
AEG DEEM
AEO 2013
DEER
RS Means
Other secondary sources
Measure Lifetimes
Estimates derived from the technical data and
secondary data sources that support the measure
demand and energy savings analysis.
Avista measure data
NPCC Sixth Plan
conservation workbooks
RTF deemed measure
database
AEG DEEM
AEO 2013
DEER
Other secondary sources
Applicability
Estimate of the percentage of dwellings in the
residential sector, square feet in the commercial
sector, or employees in the industrial sector where
the measure is applicable and where it is
technically feasible to implement.
Avista measure data
NPCC Sixth Plan
conservation workbooks
RTF deemed measure
database
AEG DEEM
DEER
Other secondary sources
On Market and Off
Market Availability
Expressed as years for equipment measures to
reflect when the equipment technology is available
or no longer available in the market.
AEG appliance standards
and building codes analysis

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Data Application for Cost-effectiveness Screening
To perform the cost-effectiveness screening, a number of economic assumptions were needed.
All cost and benefit values were analyzed as real 2013 dollars. We applied a discount rate of 4%
in in real dollars. All impacts in this report are presented at the customer meter, but electric
energy delivery losses of 6.5% were provided by Avista in order to gross up impacts to the
generator for economic analysis. The avoided costs provided by Avista were increased by 10% to
account for the Power Act’s conservation preference.
Achievable Potential Estimation
To estimate achievable potential, two sets of parameters are needed to represent customer
decision making behavior with respect to energy-efficiency choices.
 Technical diffusion curves for non-equipment measures. Equipment measures are
installed when existing units fail. Non-equipment measures do not have this natural
periodicity, so rather than installing all available non-equipment measures in the first year of
the projection (instantaneous potential), they are phased in according to adoption schedules
that generally align with the diffusion of similar equipment measures. The adoption rates for
the Avista study were based on ramp rate curves specified in the NPCC Sixth Power Plan, but
modified to reflect Avista program history. These adoption rates are used within LoadMAP to
generate the Technical and Economic potentials for non-equipment measures.
 Adoption rates. Customer adoption rates or take rates are applied to Economic potential to
estimate Achievable Potential. These rates were developed by mapping each measure to a
ramp rate developed by the Northwest Power and Conservation Council for the Sixth Plan.
These rates are then compared with the recent Avista program results and adjustments were
made, if necessary. For example, if the program had been running for several years and had
achieved higher results in the previous year, the ramp rate started further along in the curve.
These rates represent customer adoption of economic measures when delivered through a
best-practice portfolio of well-operated efficiency programs under a reasonable policy or
regulatory framework. Information channels are assumed to be established and efficient for
marketing, educating consumers, and coordinating with trade allies and delivery partners.
The primary barrier to adoption reflected in this case is customer preferences. Adoption rates
are presented in Appendix B.

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SECTION 3
Market Characterization and Market Profiles
In this section, we describe how customers in the Avista service territory use electricity in the
base year of the study, 2013. It begins with a high-level summary of energy use across all
sectors and then delves into each sector in more detail.
Energy Use Summary
Total electricity use for the residential, commercial, and industrial sectors for Avista in 2013 was
8,081 GWh; 5,555 GWh (WA) and 2,526 GWh (ID). As shown in the tables below, in both states
the residential sector accounts for over 45% of the annual energy use, followed by commercial
with over 35% of the annual energy use. In terms of summer peak demand, the total system
peak in 2013 was 1,459 MW; 1,017 MW (WA) and 442 MW (ID). The total system peak in the
winter was 1,417 MW; 973 MW (WA) and 444 MW (ID). In both states, the residential sector
contributes over 40% to peak.
Figure 3-1 Sector-Level Electricity Use in Base Year 2013, Washington

Residential
46%
Commercial
37%
Industrial
17%
Annual Use (GWh)
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Table 3-1 Avista Sector Control Totals (2013), Washington
Sector
Annual
Electricity
Use (GWh)
% of
Annual Use
Summer Peak
Demand
(MW)
% of
Summer Peak
Winter Peak
Demand
(MW)
% of
Winter Peak
Residential 2,546 46% 404 40% 438 45%
Commercial 2,086 38% 368 36% 333 34%
Industrial 922 17% 245 24% 202 21%
Total 5,555 100% 1,017 100% 973 100%

Residential
40%
Commercial
36%
Industrial
24%
Summer Peak (MW)
Residential
45%
Commercial
34%
Industrial
21%
Winter Peak (MW)
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Figure 3-2 Sector-Level Electricity Use in Base Year 2013, Idaho

Table 3-2 Avista Sector Control Totals (2013), Idaho
Sector
Annual
Electricity
Use (GWh)
% of
Annual Use
Summer Peak
Demand
(MW)
% of
Summer Peak
Winter Peak
Demand
(MW)
% of
Winter Peak
Residential 1,207 48% 184 42% 217 49%
Commercial 976 39% 167 38% 152 34%
Industrial 343 14% 91 21% 75 17%
Total 2,526 100% 442 100% 444 100%
Residential Sector
The total number of households and electricity sales for the service territory were obtained from
Avista’s customer database. In 2013, there were 213,640 households in the state of Washington
Residential
48%
Commercial
39%
Industrial
13%
Annual Use (GWh)
Residential
42%
Commercial
38%
Industrial
20%
Summer Peak (MW)
Residential
49%
Commercial
34%
Industrial
17%
Winter Peak (MW)
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that used a total of 2,546 GWh with a summer peak demand of 404 MW and a winter peak
demand of 438 MW. Average use per customer (or household) at 11,919 kWh is about average
compared to other regions of the country. We allocated these totals into four residential
segments and the values are shown in Table 3-3.
Table 3-4 shows the total number of households and electricity sales in the state of Idaho. . In
2013, there were 107,449 households that used a total of 1,207 GWh with summer peak demand
of 184 MW and winter peak demand of 217 MW. Average use per customer (or household) was
11,233.
Table 3-3 Residential Sector Control Totals (2013), Washington
Segment
Number of
Customers
Electricity Use
(GWh)
% of Annual
Use
Annual
Use/Customer
(kWh/HH)
Summer Peak
(MW)
Winter Peak
(MW)
Single Family 129,893 1,783 70% 13,726 296 304
Multifamily 11,964 99 4% 8,236 13 22
Mobile Home 7,691 95 4% 12,354 13 16
Low Income 64,092 570 22% 8,892 82 96
Total 213,640 2,546 100% 11,919 404 438
Table 3-4 Residential Sector Control Totals (2013), Idaho
Segment
Number of
Customers
Electricity Use
(GWh)
% of Annual
Use
Annual
Use/Customer
(kWh/HH)
Summer Peak
(MW)
Winter Peak
(MW
Single Family 65,329 843 70% 12,902 133 153
Multifamily 5,265 41 3% 7,733 6 9
Mobile Home 4,835 56 5% 11,599 8 10
Low Income 32,020 267 22% 8,349 38 46
Total 107,449 1,207 100% 11,233 184 217

As we describe in the previous chapter, the market profiles provide the foundation for
development of the baseline projection and the potential estimates. The average market profile
for the residential sector is presented in Table 3-5 (WA) and Table 3-6 (ID). Segment-specific
market profiles are presented in Appendix A.
Figure 3-3 (WA) and Figure 3-4 (ID) show the distribution of annual electricity use by end use for
all customers. Two main electricity end uses —appliances and space heating— account for
approximately 50% of total use. Appliances include refrigerators, freezers, stoves, clothes
washers, clothes dryers, dishwashers, and microwaves. The remainder of the energy falls into
the water heating, lighting, cooling, electronics, and the miscellaneous category – which is
comprised of furnace fans, pool pumps, and other “plug” loads (all other usage not covered by
those listed in Table 3-5 and Table 3-6 such as hair dryers, power tools, coffee makers, etc.).
The charts also show estimates of peak demand by end use. Appliances are the largest
contributor to summer peak demand, followed by water heating. During the winter, heating is
the largest contributor to peak demand, followed by appliances.
Figure 3-5 (WA) and Figure 3-6 (ID) present the electricity intensities by end use and housing
type. Single family homes have the highest use per customer at 13,726 kWh/year (WA) and
12,902 kWh/year (ID).
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Figure 3-3 Residential Electricity Use and Summer Peak Demand by End Use (2013),
Washington

Cooling
6%
Heating
27%
Water
Heating
15%
Interior
Lighting
11%Exterior
Lighting
2%
Appliances
22%
Electronics
8%
Miscellaneous
9%
Annual Use by End Use
Cooling
11%
Heating
0%
Water Heating
17%
Interior
Lighting
12%
Exterior
Lighting
3%
Appliances
35%
Electronics
11%
Miscellaneous
11%
Summer Peak Demand
Cooling
0%
Heating
36%
Water
Heating
15%
Interior
Lighting
17%
Exterior
Lighting
4%
Appliances
20%
Electronics
4%
Miscellaneous
4%
Winter Peak Demand
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Figure 3-4 Residential Electricity Use and Summer Peak Demand by End Use (2013),
Idaho

Cooling
5%
Heating
29%
Water
Heating
14%
Interior
Lighting
13%Exterior
Lighting
3%
Appliances
23%
Electronics
8%
Miscellaneous
5%
Annual Use by End Use
Cooling
10%
Heating
0%
Water Heating
18%
Interior
Lighting
14%
Exterior
Lighting
3%
Appliances
37%
Electronics
10%
Miscellaneous
8%
Summer Peak Demand
Cooling
0%
Heating
37%
Water
Heating
14%
Interior
Lighting
19%
Exterior
Lighting
4%
Appliances
20%
Electronics
4%
Miscellaneous
2%
Winter Peak Demand
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Figure 3-5 Residential Intensity by End Use and Segment (Annual kWh/HH, 2013),
Washington

Figure 3-6 Residential Intensity by End Use and Segment (Annual kWh/HH, 2013),
Idaho

- 5,000 10,000 15,000
Single Family
Multi Family
Mobile Home
Low Income
Total
Intensity (kWh/HH)
Cooling
Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
- 5,000 10,000 15,000
Single Family
Multi Family
Mobile Home
Low Income
Total
Intensity (kWh/HH)
Cooling
Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Table 3-5 Average Market Profile for the Residential Sector, 2013, Washington
End Use Technology Saturation UEC Intensity Usage
(kWh) (kWh/HH) (GWh)
Cooling Central AC 36.9% 1,249 461 98
Cooling Room AC 26.4% 402 106 23
Cooling Air-Source Heat Pump 6.5% 1,268 82 17
Cooling Geothermal Heat Pump 0.2% 1,326 2 0
Cooling Evaporative AC 1.2% 809 10 2
Space Heating Electric Room Heat 24.3% 5,302 1,288 275
Space Heating Electric Furnace 13.4% 9,021 1,213 259
Space Heating Air-Source Heat Pump 6.5% 10,487 677 145
Space Heating Geothermal Heat Pump 0.2% 5,564 10 2
Water Heating Water Heater (<= 55 Gal) 50.9% 3,025 1,539 329
Water Heating Water Heater (55 to 75 Gal) 6.5% 3,145 203 43
Water Heating Water Heater (> 75 Gal) 0.3% 4,209 12 3
Interior Lighting Screw-in/Hard-wire 100.0% 955 955 204
Interior Lighting Linear Fluorescent 100.0% 114 114 24
Interior Lighting Specialty Lighting 100.0% 286 286 61
Exterior Lighting Screw-in/Hard-wire 100.0% 289 289 62
Appliances Clothes Washer 91.8% 104 95 20
Appliances Clothes Dryer 49.9% 738 368 79
Appliances Dishwasher 77.1% 447 345 74
Appliances Refrigerator 100.0% 829 829 177
Appliances Freezer 55.3% 669 370 79
Appliances Second Refrigerator 20.7% 1,010 209 45
Appliances Stove 70.3% 453 318 68
Appliances Microwave 94.8% 139 132 28
Electronics Personal Computers 64.3% 214 138 29
Electronics Monitor 78.6% 91 71 15
Electronics Laptops 76.3% 57 43 9
Electronics TVs 177.4% 255 452 97
Electronics Printer/Fax/Copier 72.6% 65 47 10
Electronics Set top Boxes/DVRs 143.9% 128 184 39
Electronics Devices and Gadgets 100.0% 54 54 11
Miscellaneous Pool Pump 1.9% 2,514 49 10
Miscellaneous Pool Heater 0.5% 4,025 19 4
Miscellaneous Furnace Fan 58.7% 249 146 31
Miscellaneous Well pump 9.3% 642 60 13
Miscellaneous Miscellaneous 100.0% 744 744 159
Total 11,919 2,546

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Table 3-6 Average Market Profile for the Residential Sector, 2013, Idaho
End Use Technology Saturation UEC Intensity Usage
(kWh) (kWh/HH) (GWh)
Cooling Central AC 33.4% 1,134 379 41
Cooling Room AC 18.6% 416 77 8
Cooling Air-Source Heat Pump 5.3% 1,282 68 7
Cooling Geothermal Heat Pump 0.0% 0 0 0
Cooling Evaporative AC 1.5% 777 12 1
Space Heating Electric Room Heat 24.2% 6,354 1,540 165
Space Heating Electric Furnace 13.1% 8,904 1,168 126
Space Heating Air-Source Heat Pump 5.3% 10,465 557 60
Space Heating Geothermal Heat Pump 0.0% 0 0 0
Water Heating Water Heater (<= 55 Gal) 49.2% 2,904 1,429 154
Water Heating Water Heater (55 to 75 Gal) 6.2% 3,025 189 20
Water Heating Water Heater (> 75 Gal) 0.3% 3,847 11 1
Interior Lighting Screw-in/Hard-wire 100.0% 1,041 1,041 112
Interior Lighting Linear Fluorescent 100.0% 129 129 14
Interior Lighting Specialty Lighting 100.0% 243 243 26
Exterior Lighting Screw-in/Hard-wire 100.0% 323 323 35
Appliances Clothes Washer 85.1% 99 84 9
Appliances Clothes Dryer 60.3% 754 454 49
Appliances Dishwasher 77.6% 424 329 35
Appliances Refrigerator 100.0% 789 789 85
Appliances Freezer 52.3% 643 337 36
Appliances Second Refrigerator 21.1% 945 199 21
Appliances Stove 63.6% 433 275 30
Appliances Microwave 91.2% 132 120 13
Electronics Personal Computers 56.9% 200 114 12
Electronics Monitor 69.6% 85 59 6
Electronics Laptops 79.3% 53 42 5
Electronics TVs 174.6% 248 434 47
Electronics Printer/Fax/Copier 66.7% 61 41 4
Electronics Set top Boxes/DVRs 92.5% 120 111 12
Electronics Devices and Gadgets 100.0% 51 51 5
Miscellaneous Pool Pump 1.6% 2,342 38 4
Miscellaneous Pool Heater 0.4% 3,750 15 2
Miscellaneous Furnace Fan 59.7% 239 142 15
Miscellaneous Well pump 12.5% 598 75 8
Miscellaneous Miscellaneous 100.0% 356 356 38
Total 11,233 1,207

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Commercial Sector
The total electric energy consumed by commercial customers in Avista’s service area in 2013 was
2,086 GWh (WA) and 976 GWh (ID). Summer peak demand was 368 MW (WA) and 167 MW
(ID). Winter peak demand was 333 MW (WA) and 152 MW (ID). Avista billing data, CBSA and
secondary data were used to allocate this energy usage to building type segments and to
develop estimates of energy intensity (annual kWh/square foot). Using the electricity use and
intensity estimates, we infer floor space which is the unit of analysis in LoadMAP for the
commercial sector. The values are shown in Table 3-7 (WA) and Table 3-8 (ID).
Table 3-7 Commercial Sector Control Totals (2013), Washington
Segment
Electricity
Sales
(GWh)
% of Total
Usage
Intensity
(Annual
kWh/SqFt)
Summer Peak
(MW)
Winter Peak
(MW)
Small Office 280 13% 15.4 71 48
Large Office 106 5% 17.5 16 19
Restaurant 70 3% 42.4 11 11
Retail 285 14% 13.8 59 43
Grocery 209 10% 47.3 33 28
College 78 4% 13.9 13 14
School 117 6% 9.9 5 13
Health 271 13% 29.1 41 39
Lodging 112 5% 16.1 14 23
Warehouse 103 5% 7.5 12 17
Miscellaneous 455 22% 13.8 93 78
Total 2,086 100% 15.9 368 333
Table 3-8 Commercial Sector Control Totals (2013), Idaho
Segment
Electricity
Sales
(GWh)
% of Total
Usage
Intensity
(Annual
kWh/SqFt)
Summer Peak
(MW)
Winter Peak
(MW)
Small Office 134 14% 15.4 35 23
Large Office 17 2% 17.5 3 3
Restaurant 12 1% 42.4 2 2
Retail 168 17% 13.8 35 25
Grocery 92 9% 47.3 14 12
College 73 7% 13.9 12 13
School 109 11% 9.9 4 12
Health 106 11% 29.1 16 15
Lodging 49 5% 16.1 6 10
Warehouse 47 5% 7.5 5 8
Miscellaneous 168 17% 13.8 34 29
Total 976 100% 14.9 167 152
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Figure 3-7 (WA) and Figure 3-8 (ID) show the distribution of annual electricity consumption and
peak demand by end use across all commercial buildings. Electric usage is dominated by cooling
and lighting, which comprise almost 50% of annual electricity usage. Summer peak demand is
dominated by cooling and winter peak demand is dominated by heating.
Figure 3-9 (WA) and Figure 3-10 (ID) presents the electricity usage in GWh by end use and
segment. Small offices, retail, and miscellaneous buildings use the most electricity in the service
territory. As far as end uses, cooling and lighting are the major uses across all segments. Office
equipment is concentrated more in the larger customers.
Figure 3-7 Commercial Sector Electricity Consumption by End Use (2013), Washington

Cooling
16%
Heating
11%
Ventilation
10%
Water Heating
6%
Interior Lighting
23%
Exterior Lighting
8%
Refrigeration
8%
Food Preparation
4%
Office Equipment
7%
Miscellaneous
7%
Annual Use by End Use
Cooling
44%
Heating
0%
Ventilation
7%
Water Heating
5%
Interior Lighting
20%
Exterior Lighting
3%
Refrigeration
7%
Food Preparation
3%
Office
Equipment
5%
Miscellaneous
6%
Summer Peak Demand
Cooling
3%
Heating
27%
Ventilation
9%
Water Heating
8%
Interior Lighting
26%
Exterior Lighting
3%
Refrigeration
7%
Food Preparation
4%
Office
Equipment
6%
Miscellaneous
7%
Winter Peak Demand
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Figure 3-8 Commercial Sector Electricity Consumption by End Use (2013), Idaho

Cooling
16%
Heating
12%
Ventilation
10%
Water Heating
5%
Interior Lighting
23%
Exterior Lighting
8%
Refrigeration
8%
Food Preparation
4%
Office Equipment
7%
Miscellaneous
7%
Annual Use by End Use
Cooling
45%
Heating
0%Ventilation
7%
Water Heating
4%
Interior Lighting
21%
Exterior Lighting
3%
Refrigeration
7%
Food Preparation
3%
Office
Equipment
5%
Miscellaneous
5%
Summer Peak Demand
Cooling
2%
Heating
28%
Ventilation
9%
Water Heating
8%
Interior Lighting
27%
Exterior Lighting
4%
Refrigeration
6%
Food Preparation
3%
Office
Equipment
6%
Miscellaneous
7%
Winter Peak Demand
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Figure 3-9 Commercial Electricity Usage by End Use Segment (GWh, 2013), Washington

Figure 3-10 Commercial Electricity Usage by End Use Segment (GWh, 2013), Idaho

Table 3-9 (WA) and Table 3-10 (ID) show the average market profile for electricity of the
commercial sector as a whole, representing a composite of all segments and buildings. Market
profiles for each segment are presented in the appendix to this volume.
-
50
100
150
200
250
300
350
400
450
500
An
n
u
a
l

E
n
e
r
g
y

U
s
e

(
G
W
h
)
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
-
20
40
60
80
100
120
140
160
180
An
n
u
a
l

E
n
e
r
g
y

U
s
e

(
G
W
h
)
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Table 3-9 Average Electric Market Profile for the Commercial Sector, 2013, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 10.3%3.38 0.35 46.0
Cooling Water-Cooled Chiller 12.3%5.11 0.63 83.0
Cooling RTU 37.5%3.27 1.22 161.1
Cooling Room AC 4.6%2.93 0.13 17.5
Cooling Air-Source Heat Pump 5.6%3.01 0.17 22.1
Cooling Geothermal Heat Pump 1.8%1.85 0.03 4.4
Heating Electric Furnace 12.7%6.72 0.86 112.5
Heating Electric Room Heat 7.6%7.69 0.58 76.9
Heating Air-Source Heat Pump 5.6%5.87 0.33 43.1
Heating Geothermal Heat Pump 1.8%4.30 0.08 10.1
Ventilation Ventilation 100.0%1.59 1.59 209.2
Water Heating Water Heater 53.1%1.69 0.90 118.2
Interior Lighting Screw-in/Hard-wire 100.0%0.92 0.92 121.3
Interior Lighting High-Bay Fixtures 100.0%0.51 0.51 67.3
Interior Lighting Linear Fluorescent 100.0%2.17 2.17 285.8
Exterior Lighting Screw-in/Hard-wire 100.0%0.23 0.23 30.0
Exterior Lighting HID 100.0%0.64 0.64 83.8
Exterior Lighting Linear Fluorescent 100.0%0.35 0.35 46.4
Refrigeration Walk-in Refrigerator/Freezer 8.8%1.81 0.16 21.1
Refrigeration Reach-in Refrigerator/Freezer 12.1%0.29 0.04 4.6
Refrigeration Glass Door Display 15.6%0.98 0.15 20.1
Refrigeration Open Display Case 7.7%9.75 0.76 99.3
Refrigeration Icemaker 29.6%0.54 0.16 21.2
Refrigeration Vending Machine 20.2%0.33 0.07 8.9
Food Preparation Oven 15.5%0.92 0.14 18.8
Food Preparation Fryer 3.3%2.63 0.09 11.4
Food Preparation Dishwasher 16.8%1.68 0.28 37.2
Food Preparation Steamer 3.3%2.23 0.07 9.6
Food Preparation Hot Food Container 6.4%0.32 0.02 2.7
Office Equipment Desktop Computer 100.0%0.62 0.62 82.2
Office Equipment Laptop 98.8%0.08 0.08 10.9
Office Equipment Server 86.8%0.20 0.17 22.9
Office Equipment Monitor 100.0%0.11 0.11 14.5
Office Equipment Printer/Copier/Fax 100.0%0.08 0.08 9.9
Office Equipment POS Terminal 57.7%0.05 0.03 4.0
Miscellaneous Non-HVAC Motors 53.0%0.19 0.10 13.2
Miscellaneous Pool Pump 5.8%0.02 0.00 0.2
Miscellaneous Pool Heater 1.8%0.03 0.00 0.1
Miscellaneous Other Miscellaneous 100.0%1.03 1.03 135.1
Total 15.86 2,086.3
Electric Market Profiles
End Use Technology Saturation
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Table 3-10 Average Electric Market Profile for the Commercial Sector, 2013, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 12.4%3.24 0.40 26.4
Cooling Water-Cooled Chiller 10.2%5.15 0.53 34.6
Cooling RTU 35.6%3.17 1.13 74.0
Cooling Room AC 4.6%2.77 0.13 8.4
Cooling Air-Source Heat Pump 5.6%2.81 0.16 10.2
Cooling Geothermal Heat Pump 1.8%1.68 0.03 2.0
Heating Electric Furnace 11.5%6.74 0.77 50.7
Heating Electric Room Heat 7.6%7.76 0.59 38.9
Heating Air-Source Heat Pump 5.6%5.91 0.33 21.5
Heating Geothermal Heat Pump 1.8%4.41 0.08 5.2
Ventilation Ventilation 100.0%1.46 1.46 95.5
Water Heating Water Heater 51.4%1.58 0.81 53.2
Interior Lighting Screw-in/Hard-wire 100.0%0.88 0.88 57.5
Interior Lighting High-Bay Fixtures 100.0%0.51 0.51 33.3
Interior Lighting Linear Fluorescent 100.0%2.11 2.11 138.8
Exterior Lighting Screw-in/Hard-wire 100.0%0.20 0.20 13.1
Exterior Lighting HID 100.0%0.60 0.60 39.1
Exterior Lighting Linear Fluorescent 100.0%0.47 0.47 30.7
Refrigeration Walk-in Refrigerator/Freezer 8.8%1.30 0.11 7.5
Refrigeration Reach-in Refrigerator/Freezer 13.4%0.26 0.04 2.3
Refrigeration Glass Door Display 15.4%0.85 0.13 8.6
Refrigeration Open Display Case 8.4%7.98 0.67 44.1
Refrigeration Icemaker 31.6%0.48 0.15 10.0
Refrigeration Vending Machine 20.0%0.32 0.06 4.1
Food Preparation Oven 16.2%0.86 0.14 9.1
Food Preparation Fryer 3.1%2.15 0.07 4.3
Food Preparation Dishwasher 16.1%1.49 0.24 15.7
Food Preparation Steamer 3.1%1.99 0.06 4.0
Food Preparation Hot Food Container 7.4%0.25 0.02 1.2
Office Equipment Desktop Computer 100.0%0.58 0.58 37.7
Office Equipment Laptop 98.9%0.07 0.07 4.7
Office Equipment Server 89.1%0.18 0.16 10.7
Office Equipment Monitor 100.0%0.10 0.10 6.7
Office Equipment Printer/Copier/Fax 100.0%0.07 0.07 4.7
Office Equipment POS Terminal 57.6%0.05 0.03 1.8
Miscellaneous Non-HVAC Motors 51.6%0.17 0.09 5.8
Miscellaneous Pool Pump 5.7%0.02 0.00 0.1
Miscellaneous Pool Heater 1.7%0.03 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.91 0.91 59.5
Total 14.87 975.5
Electric Market Profiles
End Use Technology Saturation
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Industrial Sector
The total electricity used in 2013 by Avista’s industrial customers was 1,265 GWh; 922 GWh (WA)
and 343 GWh (ID). Summer peak demand was 336 MW; 245 MW (WA) and 91 MW (ID). Winter peak
demand was 277 MW; 202 MW (WA) and 75 MW (ID). Avista billing data, load forecast and
secondary sources were used to develop estimates of energy intensity (annual kWh/employee). Using
the electricity use and intensity estimates, we infer the number of employees which is the unit of
analysis in LoadMAP for the industrial sector. These are shown in Table 3-11.
Table 3-11 Industrial Sector Control Totals (2013)
State
Electricity Sales
(GWh)
Intensity
(Annual
kWh/employee) Summer Peak (MW) Winter Peak (MW)
Washington 922 56,846 245 202
Idaho 343 38,668 91 75

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Figure 3-11 shows the distribution of annual electricity consumption and summer and winter
peak demand by end use for all industrial customers. Motors are the largest overall end use for
the industrial sector, accounting for 54% of energy use. Note that this end use includes a wide
range of industrial equipment, such as air compressors and refrigeration compressors, pumps,
conveyor motors, and fans. The process end use accounts for 27% of annual energy use, which
includes heating, cooling, refrigeration, and electro-chemical processes. Lighting is the next
highest, followed by cooling, miscellaneous, heating and ventilation.

Figure 3-11 Industrial Electricity Use by End Use (2013), All Industries, WA and ID

Cooling
5%Heating
2%
Ventilation
2%
Interior
Lighting
5%
Exterior
Lighting
1%
Motors
54%
Process
27%
Miscellaneous
4%
Annual Use by End Use
Cooling
0%Heating
0%
Ventilation
2%Interior Lighting
5%
Exterior Lighting
0%
Motors
59%
Process
30%
Miscellaneous
4%
Summer Peak Demand
Cooling
0%Heating
4%
Ventilation
2%
Interior Lighting
5%
Exterior Lighting
0%
Motors
56%
Process
29%
Miscellaneous
4%
Winter Peak Demand
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Table 3-12 (WA) and Table 3-13 (ID) show the composite market profile for the industrial sector.
Table 3-12 Average Electric Market Profile for the Industrial Sector, 2013, Washington

Usage
(GWh)
Cooling Air-Cooled Chiller 13.0%17.4
Cooling Water-Cooled Chiller 1.4%2.2
Cooling RTU 17.0%22.4
Cooling Room AC 1.1%1.5
Cooling Air-Source Heat Pump 1.6%2.1
Cooling Geothermal Heat Pump 0.0%0.0
Heating Electric Furnace 4.9%12.5
Heating Electric Room Heat 1.7%4.2
Heating Air-Source Heat Pump 1.6%3.1
Heating Geothermal Heat Pump 0.0%0.0
Ventilation Ventilation 100.0%19.3
Interior Lighting Screw-in/Hard-wire 100.0%4.9
Interior Lighting High-Bay Fixtures 100.0%20.4
Interior Lighting Linear Fluorescent 100.0%23.8
Exterior Lighting Screw-in/Hard-wire 100.0%3.9
Exterior Lighting HID 100.0%3.2
Exterior Lighting Linear Fluorescent 100.0%3.2
Motors Pumps 100.0%86.8
Motors Fans & Blowers 100.0%68.0
Motors Compressed Air 100.0%54.3
Motors Conveyors 100.0%245.0
Motors Other Motors 100.0%38.0
Process Process Heating 100.0%99.2
Process Process Cooling 100.0%32.5
Process Process Refrigeration 100.0%32.5
Process Process Electro-Chemical 100.0%64.5
Process Process Other 100.0%21.8
Miscellaneous Miscellaneous 100.0%35.6
922.3
Average Market Profiles
End Use Technology Saturation
Total
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Table 3-13 Average Electric Market Profile for the Industrial Sector, 2013, Idaho

Usage
(GWh)
Cooling Air-Cooled Chiller 13.0%6.5
Cooling Water-Cooled Chiller 1.4%0.8
Cooling RTU 17.0%8.4
Cooling Room AC 1.1%0.6
Cooling Air-Source Heat Pump 1.6%0.8
Cooling Geothermal Heat Pump 0.0%0.0
Heating Electric Furnace 4.9%4.6
Heating Electric Room Heat 1.7%1.5
Heating Air-Source Heat Pump 1.6%1.1
Heating Geothermal Heat Pump 0.0%0.0
Ventilation Ventilation 100.0%7.2
Interior Lighting Screw-in/Hard-wire 100.0%1.8
Interior Lighting High-Bay Fixtures 100.0%7.6
Interior Lighting Linear Fluorescent 100.0%8.8
Exterior Lighting Screw-in/Hard-wire 100.0%1.4
Exterior Lighting HID 100.0%1.2
Exterior Lighting Linear Fluorescent 100.0%1.2
Motors Pumps 100.0%32.3
Motors Fans & Blowers 100.0%25.3
Motors Compressed Air 100.0%20.2
Motors Conveyors 100.0%91.1
Motors Other Motors 100.0%14.1
Process Process Heating 100.0%36.9
Process Process Cooling 100.0%12.1
Process Process Refrigeration 100.0%12.1
Process Process Electro-Chemical 100.0%24.0
Process Process Other 100.0%8.1
Miscellaneous Miscellaneous 100.0%13.3
343.0
Average Market Profiles
End Use Technology Saturation
Total
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Applied Energy Group, Inc. 42
SECTION 4
Baseline Projection
Prior to developing estimates of energy-efficiency potential, we developed a baseline end-use
projection to quantify what the consumption is likely to be in the future and in absence of any
future conservation programs. The savings from past programs are embedded in the forecast,
but the baseline projection assumes that those past programs cease to exist in the future.
Possible savings from future programs are captured by the potential estimates.
The baseline projection incorporates assumptions about:
 Customer population and economic growth
 Appliance/equipment standards and building codes already mandated (see Section 2)
 Forecasts of future electricity prices and other drivers of consumption
 Trends in fuel shares and appliance saturations and assumptions about miscellaneous
electricity growth
Although it aligns closely with it, the baseline projection is not Avista’s official load forecast.
Rather it was developed to serve as the metric against which conservation potentials are
measured. This chapter presents the baseline projections we developed for this study. Below, we
present the baseline projections for each sector and state, which include projections of annual
use in GWh and summer and winter peak demand in MW. We also present a summary across all
sectors.
Please note that the base-year for the study is 2013. Annual energy use and peak demand values
reflect actual weather in that year. In future years, energy use and peak demand reflect normal
weather, as defined by Avista. In the figures below, the shift from actual to normal weather is
apparent in the decrease in energy use and peak demand in 2014 for the residential and
commercial sectors. This results from the fact that 2013 was hotter during the summer months
or cooler during the winter months than normal.
Residential Sector
Annual Use
Table 4-1 (WA) and Table 4-2 (ID) present the baseline projection for electricity at the end-use
level for the residential sector as a whole. Overall in Washington, residential use increases from
2,546 GWh in 2013 to 2,761 GWh in 2035, an increase of 8%. Residential use in Idaho increases
from 1,207 GWh in 2013 to 1,375 GWh, an increase of 14%. This reflects a modest customer
growth forecast in both states. Figure 4-1 (WA) and Figure 4-3 (ID) display the graphical
representation of the baseline projection.
Figure 4-2 (WA) and Figure 4-4 (ID) present the baseline projection of annual electricity use per
household. Most noticeable is that lighting use decreases throughout the time period as the
lighting standards from EISA come into effect. Usage in the cooling decreases over the forecast
due to going from actual weather in 2014 to normal weather for the rest of the forecast.

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Table 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington
End Use 2013 2016 2017 2020 2025 2035
% Change
('13-'35)
Cooling 141 92 93 93 93 96 -32%
Heating 681 702 706 713 722 743 9%
Water Heating 375 379 380 381 388 416 11%
Interior Lighting 289 244 230 196 151 140 -52%
Exterior Lighting 62 51 48 40 30 27 -56%
Appliances 569 572 571 568 567 585 3%
Electronics 211 226 229 239 262 331 57%
Miscellaneous 218 238 245 267 311 423 94%
Total 2,546 2,503 2,500 2,498 2,523 2,761 8.4%
Table 4-2 Residential Baseline Sales Projection by End Use (GWh), Idaho
End Use 2013 2016 2017 2020 2025 2035
% Change
('13-'35)
Cooling 58 38 38 39 40 42 -26%
Heating 351 366 370 379 392 417 19%
Water Heating 175 179 180 184 190 211 20%
Interior Lighting 152 132 126 111 89 87 -43%
Exterior Lighting 35 29 28 24 18 17 -50%
Appliances 278 282 283 286 291 312 12%
Electronics 91 99 102 108 122 160 75%
Miscellaneous 67 73 76 82 96 129 92%
Total 1,207 1,199 1,203 1,213 1,238 1,375 13.9%
Figure 4-1 Residential Baseline Sales Projection by End Use (GWh), Washington

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Figure 4-2 Residential Baseline Sales Projection by End Use – Annual Use per Household,
Washington

Figure 4-3 Residential Baseline Projection by End Use (GWh), Idaho

0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
2013 2016 2019 2022 2025 2028 2031 2034
Annual Use
(kWh/HH)
Cooling
Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Figure 4-4 Residential Baseline Sales Projection by End Use – Annual Use per Household,
Idaho

Residential Summer Peak Projection
Table 4-3 (WA) and Table 4-4 (ID) present the residential baseline projection for summer peak
demand at the end-use level. Overall in Washington, residential summer peak increases from 404
MW in 2013 to 438 MW in 2035, an increase of 8%. In Idaho, the residential summer peak
increases from 184 MW to 207 MW, an increase of 13%. All end uses except cooling and lighting
show increases in the baseline peak projections. The summer peak associated with electronics
and miscellaneous uses increases substantially, in correspondence with growth in annual energy
use. Figure 4-5 (WA) and Figure 4-6 (ID) display the graphical representation of the baseline
projection for summer peak. Usage in residential cooling decreases over the forecast due to
going from actual weather in 2014 to weather-normal weather for the forecast.
Table 4-3 Residential Summer Peak Baseline Projection by End Use (MW), Washington
End Use 2013 2016 2017 2020 2025 2035
% Change
('13-'35)
Cooling 46 30 30 30 31 32 -30%
Heating - - - - - - 0%
Water Heating 71 71 71 72 73 78 11%
Interior Lighting 49 41 39 33 25 24 -52%
Exterior Lighting 10 9 8 7 5 5 -56%
Appliances 141 141 141 140 140 144 2%
Electronics 44 47 48 50 54 69 57%
Miscellaneous 44 49 50 55 64 87 95%
Total 404 388 387 386 392 438 8.3%

0
2,000
4,000
6,000
8,000
10,000
12,000
2013 2016 2019 2022 2025 2028 2031 2034
Annual Use
(kWh/HH)
Cooling
Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Table 4-4 Residential Summer Peak Baseline Projection by End Use (MW), Idaho
End Use 2013 2016 2017 2020 2025 2035
% Change
('13-'35)
Cooling 19 13 13 13 13 14 -24%
Heating - - - - - - 0%
Water Heating 33 34 34 35 36 40 20%
Interior Lighting 25 22 21 19 15 15 -43%
Exterior Lighting 6 5 5 4 3 3 -50%
Appliances 68 69 69 69 71 75 11%
Electronics 19 21 21 23 26 34 75%
Miscellaneous 14 15 16 17 20 27 93%
Total 184 178 179 180 183 207 12.6%
Figure 4-5 Residential Summer Peak Baseline Projection by End Use (MW), Washington

Figure 4-6 Residential Summer Peak Baseline Projection by End Use (MW), Idaho

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Residential Winter Peak Projection
Table 4-5 (WA) and Table 4-6 (ID) present the residential baseline projection for winter peak
demand at the end-use level. Overall in Washington, residential winter peak increases from 438
MW in 2013 to 440 MW in 2035, an increase of 0.4%. In Idaho, the residential winter peak
increases from 217 MW to 233 MW, an increase of 8%. All end uses except lighting show
increases in the baseline peak projections. The winter peak associated with electronics and
miscellaneous uses increases substantially, in correspondence with growth in annual energy use.
Figure 4-7Figure 4-5 (WA) and Figure 4-8Figure 4-6 (ID) display the graphical representation of
the baseline projection for winter peak.
Table 4-5 Residential Winter Peak Baseline Projection by End Use (MW), Washington
End Use 2013 2016 2017 2020 2025 2035
% Change
('13-'35)
Cooling - - - - - - 0%
Heating 156 161 162 164 165 170 9%
Water Heating 66 67 67 68 69 74 11%
Interior Lighting 77 65 61 52 40 37 -52%
Exterior Lighting 16 14 13 11 8 7 -56%
Appliances 89 90 90 89 90 94 5%
Electronics 17 18 18 19 21 26 56%
Miscellaneous 16 18 18 20 23 32 96%
Total 438 432 429 422 416 440 0.4%
Table 4-6 Residential Winter Peak Baseline Projection by End Use (MW), Idaho
End Use 2013 2016 2017 2020 2025 2035
% Change
('13-'35)
Cooling - - - - - - 0%
Heating 80 84 85 87 90 96 19%
Water Heating 31 32 32 33 34 37 20%
Interior Lighting 40 35 34 30 24 23 -43%
Exterior Lighting 9 8 7 6 5 5 -50%
Appliances 43 44 44 45 46 49 14%
Electronics 8 8 8 9 10 13 75%
Miscellaneous 5 6 6 6 8 10 97%
Total 217 216 216 215 215 233 7.6%
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Figure 4-7 Residential Winter Peak Baseline Projection by End Use (MW), Washington

Figure 4-8 Residential Winter Peak Baseline Projection by End Use (MW), Idaho

Commercial Sector Baseline Projections
Annual Use
In Washington, annual electricity use in the commercial sector grows during the overall forecast
horizon, starting at 2,086 GWh in 2013, and increasing to 2,282 in 2035, an increase of 9%. In
Idaho, annual electricity use grows from 976 GWh in 2013 to 1,063 GWh in 2035, an increase of
9%. The tables and graphs below present the baseline projection at the end-use level for the
commercial sector as a whole. Usage in lighting is declining throughout the forecast, due largely
to the phasing in of codes and standards such as the EISA 2007 lighting standards. Usage in
commercial cooling decreases over the forecast due to going from actual weather in 2014 to
weather-normal weather for the forecast.
Table 4-7 Commercial Baseline Sales Projection by End Use (GWh), Washington
End Use 2013 2016 2017 2020 2025 2035 % Change
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Electronics
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('13-'35)
Cooling 334 282 282 285 287 293 -12.3%
Heating 243 248 250 255 263 277 14.3%
Ventilation 209 211 212 215 217 224 6.9%
Water Heating 118 119 119 121 125 132 11.9%
Interior Lighting 474 462 460 455 452 475 0.1%
Exterior Lighting 160 146 143 133 122 121 -24.6%
Refrigeration 175 186 191 204 227 276 57.6%
Food Preparation 80 83 84 88 94 115 44.9%
Office Equipment 144 136 134 132 134 145 0.4%
Miscellaneous 149 153 155 166 184 224 51.0%
Total 2,086 2,027 2,031 2,053 2,106 2,282 9.4%
Table 4-8 Commercial Baseline Sales Projection by End Use (GWh), Idaho
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling 156 131 131 132 133 135 -13.3%
Heating 116 119 119 122 125 130 12.1%
Ventilation 96 96 97 98 98 101 5.5%
Water Heating 53 53 54 54 56 59 10.1%
Interior Lighting 229 223 222 219 217 226 -1.4%
Exterior Lighting 83 77 75 71 66 66 -20.7%
Refrigeration 77 82 84 90 100 123 61.1%
Food Preparation 34 36 37 39 42 52 50.8%
Office Equipment 66 63 62 61 62 68 2.1%
Miscellaneous 65 68 70 75 84 104 59.1%
Total 976 949 950 960 983 1,063 9.0%

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Figure 4-9 Commercial Baseline Projection by End Use, Washington

Figure 4-10 Commercial Baseline Projection by End Use, Idaho

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Commercial Summer Peak Demand Projection
The tables and charts below present the summer peak baseline projection at the end-use level
for the commercial sector as a whole. In Washington, summer peak demand increases during the
overall forecast horizon, starting at 368 MW in 2013 and increasing by 4% to 383 MW in 2035.
In Idaho, the summer peak demand is 167 MW in 2013 and 173 MW in 2035, an increase of 4%.
Table 4-9 Commercial Summer Peak Baseline Projection by End Use (MW), Washington
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling 162 137 137 138 139 143 -12.2%
Heating 0 0 0 0 0 0 17.5%
Ventilation 26 27 27 27 27 28 7.0%
Water Heating 18 18 18 18 19 20 13.4%
Interior Lighting 74 73 72 72 71 75 0.7%
Ext. Lighting 9 8 8 7 7 7 -24.6%
Refrigeration 27 28 29 31 35 42 57.7%
Food Prep 11 11 11 12 13 16 49.6%
Office Equip 19 18 17 17 17 19 1.4%
Miscellaneous 22 22 23 24 27 33 51.6%
Total 368 342 343 347 356 383 4.1%

Table 4-10 Commercial Summer Peak Baseline Projection by End Use (MW), Idaho
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling 75 63 63 64 64 65 -12.9%
Heating 0 0 0 0 0 0 17.5%
Ventilation 12 12 12 12 12 13 5.5%
Water Heating 7 8 8 8 8 8 12.1%
Interior Lighting 35 34 34 34 33 35 -0.3%
Ext. Lighting 5 4 4 4 4 4 -20.7%
Refrigeration 11 12 13 14 15 19 62.1%
Food Prep 4 4 5 5 5 7 62.9%
Office Equip 8 8 8 7 8 8 2.6%
Miscellaneous 9 10 10 10 12 15 60.7%
Total 167 155 156 157 161 173 3.8%
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Figure 4-11 Commercial Summer Peak Baseline Projection by End Use (MW),
Washington

Figure 4-12 Commercial Summer Peak Baseline Projection by End Use (MW), Idaho

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Commercial Winter Peak Demand Projection
The tables and charts below present the winter peak baseline projection at the end-use level for
the commercial sector as a whole. In Washington, winter peak demand increases during the
overall forecast horizon, starting at 333 MW in 2013 and increasing by 14% to 380 MW in 2035.
In Idaho, the winter peak demand is 152 MW in 2013 and 173 MW in 2035, an increase of 14%.
Table 4-11 Commercial Winter Peak Baseline Projection by End Use (MW), Washington
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling 10 8 8 8 8 9 -11.4%
Heating 90 92 93 95 98 103 14.8%
Ventilation 30 31 31 31 31 32 6.9%
Water Heating 26 27 27 27 28 30 13.0%
Interior Lighting 86 84 84 83 82 86 0.4%
Ext. Lighting 10 9 9 8 8 7 -24.6%
Refrigeration 22 23 24 26 28 35 57.2%
Food Prep 12 13 13 14 15 18 49.2%
Office Equip 21 20 20 20 20 22 1.3%
Miscellaneous 25 26 26 28 31 38 51.5%
Total 333 332 334 339 350 380 14.2%

Table 4-12 Commercial Winter Peak Baseline Projection by End Use (MW), Idaho
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling 4 3 3 3 3 3 -11.7%
Heating 42 43 43 44 45 48 13.0%
Ventilation 14 14 14 14 14 15 5.5%
Water Heating 11 11 11 12 12 13 11.4%
Interior Lighting 41 40 40 40 39 41 -0.9%
Ext. Lighting 5 5 5 4 4 4 -20.7%
Refrigeration 10 10 10 11 13 15 60.8%
Food Prep 5 5 5 6 6 8 61.7%
Office Equip 9 9 9 9 9 10 2.3%
Miscellaneous 11 11 12 12 14 17 60.0%
Total 152 152 153 155 160 173 13.9%
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Figure 4-13 Commercial Winter Peak Baseline Projection by End Use (MW),
Washington

Figure 4-14 Commercial Winter Peak Baseline Projection by End Use (MW), Idaho

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350
400
An
n
u
a
l

U
s
e

W
i
n
t
e
r

(
M
W
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Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
-
20
40
60
80
100
120
140
160
180
200
An
n
u
a
l

U
s
e

W
i
n
t
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r

(
M
W
)
Cooling
Heating
Ventilation
Water Heating
Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Industrial Sector Baseline Projections
Annual Use
Annual industrial use increases almost 25% through the forecast horizon, driven primarily by
expected customer growth. The tables and graphs below present the projection at the end-use
level. Overall in Washington, industrial annual electricity use increases from 922 GWh in 2013 to
1,149 GWh in 2035. In Idaho, annual electricity use increases from 343 GWh in 2013 to 426
GWh in 2035. This comprises an overall increase of 25% over the 23-year period in both states.
Table 4-13 Industrial Baseline Projection by End Use (GWh), Washington
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling 46 41 41 41 42 44 -4%
Heating 20 21 22 22 23 24 23%
Ventilation 19 20 20 19 18 16 -18%
Interior Lighting 49 52 52 52 53 57 16%
Exterior Lighting 10 10 10 10 10 10 -1%
Process 492 534 540 555 578 626 27%
Motors 251 272 275 282 294 319 27%
Miscellaneous 36 40 40 42 46 53 48%
Total 922 989 999 1,024 1,064 1,149 24.5%

Table 4-14 Industrial Baseline Projection by End Use (GWh), Idaho
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling 17 15 15 15 16 16 -5%
Heating 7 8 8 8 8 9 23%
Ventilation 7 7 7 7 7 6 -18%
Interior Lighting 18 19 19 19 20 21 15%
Exterior Lighting 4 4 4 4 4 4 -1%
Process 183 198 200 206 215 232 27%
Motors 93 101 102 105 109 118 27%
Miscellaneous 13 15 15 16 17 20 48%
Total 343 367 371 380 395 426 24.3%
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Figure 4-15 Industrial Baseline Projection by End Use (GWh), Washington

Figure 4-16 Industrial Baseline Projection by End Use (GWh), Idaho

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200
400
600
800
1,000
1,200
1,400
2013 2016 2019 2022 2025 2028 2031 2034
Annual Use (GWh)
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
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50
100
150
200
250
300
350
400
450
2013 2016 2019 2022 2025 2028 2031 2034
Annual Use (GWh)
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
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Industrial Summer Peak Demand Projection
The tables and graphs below present the projection of summer peak demand for the industrial
sector. This projection looks similar to the energy forecast largely because the industrial sector
has a high load factor.
Table 4-15 Industrial Summer Peak Baseline Projection by End Use (MW), Washington
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling - - - - - - 0%
Heating - - - - - - 0%
Ventilation 4 4 4 4 3 3 -18%
Interior Lighting 13 14 14 14 14 15 16%
Exterior Lighting 1 1 1 1 1 1 -1%
Process 144 156 158 162 169 183 27%
Motors 73 79 80 83 86 93 27%
Miscellaneous 10 12 12 12 13 15 48%
Total 245 265 268 275 287 311 26.8%

Table 4-16 Industrial Summer Peak Baseline Projection by End Use (MW), Idaho
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling - - - - - - 0%
Heating - - - - - - 0%
Ventilation 1 1 1 1 1 1 -18%
Interior Lighting 5 5 5 5 5 6 15%
Exterior Lighting 0 0 0 0 0 0 -1%
Process 54 58 59 60 63 68 27%
Motors 27 30 30 31 32 35 27%
Miscellaneous 4 4 4 5 5 6 48%
Total 91 99 100 102 106 115 26.6%
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Figure 4-17 Industrial Summer Peak Baseline Projection by End Use (MW), Washington

Figure 4-18 Industrial Summer Peak Baseline Projection by End Use (MW), Idaho

-
50
100
150
200
250
300
350
2013 2016 2019 2022 2025 2028 2031 2034
Annual Use Summer
(MW)
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
-
20
40
60
80
100
120
140
2013 2016 2019 2022 2025 2028 2031 2034
Annual Use Summer
(MW)
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
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Industrial Winter Peak Demand Projection
The tables and graphs below present the projection of winter peak demand for the industrial
sector. This projection looks similar to the energy forecast largely because the industrial sector
has a high load factor.
Table 4-17 Industrial Winter Peak Baseline Projection by End Use (MW), Washington
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling - - - - - - 0%
Heating 8 9 9 9 9 10 23%
Ventilation 3 3 3 3 3 2 -18%
Interior Lighting 10 11 11 11 11 12 16%
Exterior Lighting 1 1 1 1 1 1 -1%
Process 114 124 125 128 134 145 27%
Motors 58 63 64 65 68 74 27%
Miscellaneous 8 9 9 10 11 12 48%
Total 202 219 221 227 236 256 26.63%

Table 4-18 Industrial Winter Peak Baseline Projection by End Use (MW), Idaho
End Use 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Cooling - - - - - - 0%
Heating 3 3 3 3 3 4 23%
Ventilation 1 1 1 1 1 1 -18%
Interior Lighting 4 4 4 4 4 4 15%
Exterior Lighting 0 0 0 0 0 0 -1%
Process 42 46 46 48 50 54 27%
Motors 22 23 24 24 25 27 27%
Miscellaneous 3 3 3 4 4 5 48%
Total 75 81 82 84 88 95 26.42%

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Figure 4-19 Industrial Winter Peak Baseline Projection by End Use (MW), Washington

Figure 4-20 Industrial Winter Peak Baseline Projection by End Use (MW), Idaho

-
50
100
150
200
250
300
2013 2016 2019 2022 2025 2028 2031 2034
Annual Use Winter
(MW)
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
-
10
20
30
40
50
60
70
80
90
100
2013 2016 2019 2022 2025 2028 2031 2034
Annual Use Winter
(MW)
Cooling
Heating
Ventilation
Interior Lighting
Exterior Lighting
Motors
Process
Miscellaneous
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Summary of Baseline Projections across Sectors and States
Annual Use
Table 4-19 and Figure 4-21 provide a summary of the baseline projection for annual use by
sector for the entire Avista service territory. Overall, the projection shows strong growth in
electricity use, driven primarily by customer growth forecasts.
Table 4-19 Baseline Projection Summary (GWh), WA and ID Combined
Sector 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Residential 3,753 3,703 3,703 3,711 3,761 4,136 10.2%
Commercial 3,062 2,976 2,981 3,013 3,089 3,346 9.3%
Industrial 1,265 1,356 1,370 1,404 1,458 1,575 24.5%
Total 8,081 8,035 8,054 8,128 8,308 9,057 12.1%

Figure 4-21 Baseline Projection Summary (GWh), WA and ID Combined

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2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
Annual Use (GWh)Industrial
Commercial
Residential
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Summer Peak Demand Projection
Table 4-20 and Figure 4-22 provide a summary of the baseline projection for summer peak
demand. Overall, the projection shows steady growth.
Table 4-20 Baseline Summer Peak Projection Summary (MW), WA and ID Combined
Sector 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Residential 588 566 566 566 575 645 9.6%
Commercial 535 497 498 505 517 556 4.0%
Industrial 336 364 368 378 393 426 26.7%
Total 1,459 1,427 1,432 1,448 1,486 1,627 11.5%

Figure 4-22 Baseline Summer Peak Projection Summary (MW), WA and ID Combined

Winter Peak Demand Projection
Table 4-21Table 4-20 and Figure 4-23 provide a summary of the baseline projection for winter
peak demand. Overall, the projection shows steady growth.
Table 4-21 Baseline Winter Peak Projection Summary (MW), WA and ID Combined
Sector 2013 2016 2017 2020 2025 2035 % Change
('13-'35)
Residential 655 648 645 637 631 673 2.8%
Commercial 485 485 486 494 509 554 14.1%
Industrial 277 300 303 311 324 351 26.6%
Total 1,417 1,433 1,434 1,442 1,464 1,577 11.3%

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200
400
600
800
1,000
1,200
1,400
1,600
1,800
Summer Peak Demand
(MW)
Industrial
Commercial
Residential
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Figure 4-23 Baseline Winter Peak Projection Summary (MW), WA and ID Combined

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200
400
600
800
1,000
1,200
1,400
1,600
1,800
Winter Peak Demand
(MW)
Industrial
Commercial
Residential
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SECTION 5
Conservation Potential
This section presents the measure-level conservation potential for Avista. This includes every
possible measure that is considered in the measure list, regardless of program implementation
concerns.
We present the annual energy savings in GWh and aMW for selected years from conservation
measures. Year-by-year savings for annual energy and peak demand are available in the
LoadMAP model, which was provided to Avista at the conclusion of the study.
This section begins a summary of annual energy savings across all three sectors. Then we
provide details for each sector. Please note that all savings are provided at the customer meter.
Overall Summary of Energy Efficiency Potential
Summary of Annual Energy Savings
Table 5-1 (WA) and Table 5-2 (ID) summarize the EE savings in terms of annual energy use for
all measures for three levels of potential relative to the baseline projection. Figure 5-1(WA) and
Figure 5-2 (ID) displays the three levels of potential by year. Figure 5-3 (WA) and Figure 5-4
(ID) display the EE projections.
 Technical potential reflects the adoption of all conservation measures regardless of cost-
effectiveness. For Washington, first-year savings are 116 GWh, or 2.1% of the baseline
projection. Cumulative savings in 2035 are 1,682 GWh, or 27.2% of the baseline. For Idaho,
first-year savings are 57 GWh, or 2.2% of the baseline projection. Cumulative savings in
2035 are 824 GWh, or 28.8% of the baseline.
 Economic potential reflects the savings when the most efficient cost-effective measures
are taken by all customers. For Washington, the first-year savings in 2016 are 45 GWh, or
0.8% of the baseline projection. By 2035, cumulative savings reach 884 GWh, or 14.3% of
the baseline projection. For Idaho, the first-year savings in 2016 are 23 GWh, or 0.9% of the
baseline projection. By 2035, cumulative savings reach 408 GWh, or 14.2% of the baseline
projection.
 Achievable potential represents savings that are possible through utility programs. It
shows for Washington, 23 GWh savings in the first year, or 0.4% of the baseline and by 2035
cumulative achievable savings reach 746 GWh, or 12% of the baseline projection. This
results in average annual savings of 0.5% of the baseline each year. Achievable potential
reflects 84% of economic potential throughout the forecast horizon. For Idaho, first year
savings are 11 GWh or 0.4% of the baseline and by 2035 cumulative achievable savings
reach 344 GWh, or 12% of the baseline.

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Table 5-1 Summary of EE Potential (Annual Energy, GWh), Washington
2016 2017 2020 2025 2035
Baseline projection (GWh) 5,520 5,530 5,575 5,693 6,192
Cumulative Savings (GWh)
Achievable Potential 23 50 159 391 746
Economic Potential 45 92 242 499 884
Technical Potential 116 231 563 1,065 1,682
Cumulative Savings (aMW)
Achievable Potential 2.6 5.7 18.1 44.6 85.2
Economic Potential 5.1 10.6 27.6 56.9 100.9
Technical Potential 13.3 26.4 64.2 121.6 192.0
Cumulative Savings as a % of Baseline
Achievable Potential 0.4% 0.9% 2.8% 6.9% 12.0%
Economic Potential 0.8% 1.7% 4.3% 8.8% 14.3%
Technical Potential 2.1% 4.2% 10.1% 18.7% 27.2%
Table 5-2 Summary of EE Potential (Annual Energy, GWh), Idaho
2016 2017 2020 2025 2035
Baseline projection (GWh) 2,515 2,525 2,553 2,615 2,865
Cumulative Savings (GWh)
Achievable Potential 11 24 77 184 344
Economic Potential 23 46 118 234 408
Technical Potential 57 113 274 516 824
Cumulative Savings (aMW)
Achievable Potential 1.3 2.8 8.8 21.0 39.3
Economic Potential 2.6 5.3 13.5 26.8 46.6
Technical Potential 6.5 12.9 31.3 58.9 94.1
Cumulative Savings as a % of Baseline
Achievable Potential 0.4% 1.0% 3.0% 7.0% 12.0%
Economic Potential 0.9% 1.8% 4.6% 9.0% 14.2%
Technical Potential 2.2% 4.5% 10.7% 19.7% 28.8%
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Figure 5-1 Summary of EE Potential as % of Baseline Projection (Annual Energy),
Washington

Figure 5-2 Summary of EE Potential as % of Baseline Projection (Annual Energy), Idaho

0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
2016 2017 2020 2025 2035
En
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Achievable Potential
Economic Potential
Technical Potential
0.0%
5.0%
10.0%
15.0%
20.0%
25.0%
30.0%
35.0%
2016 2017 2020 2025 2035
En
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Achievable Potential
Economic Potential
Technical Potential
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Figure 5-3 Baseline Projection and EE Forecast Summary (Annual Energy, GWh),
Washington

Figure 5-4 Baseline Projection and EE Forecast Summary (Annual Energy, GWh), Idaho

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Achievable Potential
Economic Potential
Technical Potential
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Achievable Potential
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Technical Potential
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Summary of Conservation Potential by Sector
Table 5-3 and Figure 5-5 summarize the range of electric achievable potential by sector, both
states combined. The residential and commercial sectors contribute the most savings in the early
years, but by 2020 the commercial sector provides the most savings.
Table 5-3 Achievable Conservation Potential by Sector (Annual Use), WA and ID
2016 2017 2020 2025 2035
Cumulative Savings (GWh)
Residential 13 30 87 169 274
Commercial 13 28 105 304 617
Industrial 8 16 44 101 199
Total 34 74 236 574 1,090

Cumulative Savings (aMW)
Residential 1.5 3.4 9.9 19.3 31.3
Commercial 1.5 3.2 12.0 34.7 70.5
Industrial 0.9 1.8 5.1 11.6 22.7
Total 3.9 8.5 27.0 65.6 124.5
Figure 5-5 Achievable Conservation Potential by Sector (Annual Energy, GWh)

0
200
400
600
800
1,000
1,200
2016 2017 2020 2025 2035
Achievable
Savings (GWh)
Industrial
Commercial
Residential
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Residential Conservation Potential
Table 5-4 (Total), Table 5-5 (WA) and Table 5-6 (ID) present estimates for measure-level
conservation potential for the residential sector in terms of annual energy savings. Figure 5-6
(WA) and Figure 5-7 (ID) display the three levels of potential by year. For Washington,
achievable potential in the first year, 2016 is 9 GWh, or 0.3% of the baseline projection. By
2035, cumulative achievable savings are 181 GWh, or 6.6% of the baseline projection. At this
level, it represents over 80% of economic potential. For Idaho, first year achievable savings are
5 GWh or 0.4% of the baseline and by 2035 cumulative achievable savings reach 93 GWh, or
6.8% of the baseline.

Table 5-4 Residential Conservation Potential (Annual Energy), Washington and Idaho
2016 2017 2020 2025 2035
Baseline projection (GWh) 3,703 3,703 3,711 3,761 4,136
Cumulative Net Savings (GWh)
Achievable Potential 13 30 87 169 274
Economic Potential 29 60 137 219 334
Technical Potential 84 169 400 719 1,117
Cumulative Net Savings (aMW)
Achievable Potential 1.5 3.4 9.9 19.3 31.3
Economic Potential 3.3 6.9 15.6 25.0 38.1
Technical Potential 9.6 19.3 45.7 82.1 127.5
Cumulative Net Savings as a % of Baseline
Achievable Potential 0.4% 0.8% 2.3% 4.5% 6.6%
Economic Potential 0.8% 1.6% 3.7% 5.8% 8.1%
Technical Potential 2.3% 4.6% 10.8% 19.1% 27.0%

Table 5-5 Residential Conservation Potential (Annual Energy), Washington
2016 2017 2020 2025 2035
Baseline projection (GWh) 2,503 2,500 2,498 2,523 2,761
Cumulative Net Savings (GWh)
Achievable Potential 9 19 56 111 181
Economic Potential 19 39 88 145 221
Technical Potential 55 110 261 469 721
Cumulative Net Savings (aMW)
Achievable Potential 1.0 2.2 6.4 12.6 20.7
Economic Potential 2.2 4.4 10.1 16.5 25.2
Technical Potential 6.3 12.6 29.8 53.6 82.3
Cumulative Net Savings as a % of Baseline
Achievable Potential 0.3% 0.8% 2.2% 4.4% 6.6%
Economic Potential 0.8% 1.5% 3.5% 5.7% 8.0%
Technical Potential 2.2% 4.4% 10.5% 18.6% 26.1%
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Table 5-6 Residential Conservation Potential (Annual Energy), Idaho
2016 2017 2020 2025 2035
Baseline projection (GWh) 1,199 1,203 1,213 1,238 1,375
Cumulative Net Savings (GWh)
Achievable Potential 5 11 31 58 93
Economic Potential 10 21 48 75 113
Technical Potential 29 59 139 250 395
Cumulative Net Savings (aMW)
Achievable Potential 0.5 1.2 3.5 6.6 10.6
Economic Potential 1.2 2.4 5.5 8.5 12.9
Technical Potential 3.3 6.7 15.9 28.5 45.1
Cumulative Net Savings as a % of Baseline
Achievable Potential 0.4% 0.9% 2.5% 4.7% 6.8%
Economic Potential 0.9% 1.8% 4.0% 6.0% 8.2%
Technical Potential 2.4% 4.9% 11.5% 20.2% 28.8%
Figure 5-6 Residential Conservation Savings as a % of the Baseline Projection (Annual
Energy), Washington

0%
5%
10%
15%
20%
25%
30%
2016 2017 2020 2025 2035
Energy Savings
(% of Baseline
Forecast)
Achievable Potential
Economic Potential
Technical Potential
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Figure 5-7 Residential Conservation Savings as a % of the Baseline Projection (Annual
Energy), Idaho

Below, we present the top residential measures from the perspective of annual energy use. We
first present information for both states, followed by Washington-only results and Idaho-only
results.

0%
5%
10%
15%
20%
25%
30%
35%
2016 2017 2020 2025 2035
Energy Savings
(% of Baseline
Forecast)
Achievable Potential
Economic Potential
Technical Potential
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Table 5-7 identifies the top 20 residential measures from the perspective of annual energy
savings in 2017 for Washington and Idaho combined. The top three measures include interior
and exterior lighting measures and repair and sealing of ducting. The lighting measures are a
result of purchases of LED lamps which are cost effective throughout the forecast horizon.
Table 5-7 Residential Top Measures in 2017 (Annual Energy, MWh), Washington and
Idaho
Rank Residential Measure
2017 Cumulative
Energy Savings
(MWh)
% of
Total
1 Interior Lighting - Screw-in/Hard-wire 13,616 46%
2 Ducting - Repair and Sealing 5,057 17%
3 Exterior Lighting - Screw-in/Hard-wire 4,152 14%
4 Water Heater - Pipe Insulation 2,264 8%
5 Water Heater - Faucet Aerators 1,037 3%
6 Behavioral Programs 688 2%
7 Thermostat - Clock/Programmable 674 2%
8 Insulation - Ducting 621 2%
9 Water Heater - Low-Flow Showerheads 419 1%
10 Electronics - Personal Computers 285 1%
11 Appliances - Freezer 272 1%
12 Water Heater - Drainwater Heat Recovery 241 1%
13 Miscellaneous - Pool Pump 172 1%
14 Appliances - Second Refrigerator 169 1%
15 Electronics - Laptops 77 0%
16 Appliances - Refrigerator 56 0%
17 Water Heating - Water Heater (55 to 75 Gal) 36 0%
18 Water Heater - Desuperheater 17 0%
19 Electronics - Monitor 13 0%
20 Electronics - TVs 7 0%
Total Total 29,875 100.0%

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Table 5-8 identifies the top 20 residential measures from the perspective of annual energy
savings in 2017 for Washington. The top three measures include interior and exterior lighting
measures and repair and sealing of ducting. The lighting measures are a result of purchases of
LED lamps which are cost effective throughout the forecast horizon.

Table 5-8 Residential Top Measures in 2017 (Annual Energy, MWh), Washington
Rank Residential Measure
2017 Cumulative
Energy Savings
(MWh)
% of
Total
1 Interior Lighting - Screw-in/Hard-wire 8,479 44.0%
2 Ducting - Repair and Sealing 3,483 18.1%
3 Exterior Lighting - Screw-in/Hard-wire 2,564 13.3%
4 Water Heater - Pipe Insulation 1,535 8.0%
5 Water Heater - Faucet Aerators 699 3.6%
6 Behavioral Programs 464 2.4%
7 Thermostat - Clock/Programmable 443 2.3%
8 Insulation - Ducting 429 2.2%
9 Water Heater - Low-Flow Showerheads 284 1.5%
10 Electronics - Personal Computers 199 1.0%
11 Appliances - Freezer 177 0.9%
12 Water Heater - Drainwater Heat Recovery 157 0.8%
13 Miscellaneous - Pool Pump 121 0.6%
14 Appliances - Second Refrigerator 110 0.6%
15 Electronics - Laptops 51 0.3%
16 Appliances - Refrigerator 36 0.2%
17 Water Heating - Water Heater (55 to 75 Gal) 24 0.1%
18 Water Heater - Desuperheater 12 0.1%
19 Electronics - Monitor 9 0.0%
20 Electronics - TVs 5 0.0%
Total Total 19,280 100.0%

Figure 5-8 presents forecasts of cumulative energy savings for Washington. Lighting savings
account for a substantial portion of the savings throughout the forecast horizon. The same is
true for exterior lighting. Savings from heating measures and appliances are steadily increasing
throughout the forecast horizon.
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Figure 5-8 Residential Achievable Savings Forecast (Cumulative GWh), Washington

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2015 2018 2021 2024 2027 2030 2033
Al
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Cooling
Heating
Water Heating
Interior Lighting
Exterior Lighting
Appliances
Electronics
Miscellaneous
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Table 5-9 identifies the top 20 residential measures from the perspective of annual energy
savings in 2017 for Idaho. The top three measures include interior and exterior lighting measures
and repair and sealing of ducting. The lighting measures are a result of purchases of LED lamps
which are cost effective throughout the forecast horizon.

Table 5-9 Residential Top Measures in 2017 (Annual Energy, MWh), Idaho
Rank Residential Measure
2017 Cumulative
Energy Savings
(MWh)
% of
Total
1 Interior Lighting - Screw-in/Hard-wire 5,137 48.5%
2 Exterior Lighting - Screw-in/Hard-wire 1,588 15.0%
3 Ducting - Repair and Sealing 1,574 14.9%
4 Water Heater - Pipe Insulation 729 6.9%
5 Water Heater - Faucet Aerators 337 3.2%
6 Thermostat - Clock/Programmable 231 2.2%
7 Behavioral Programs 225 2.1%
8 Insulation - Ducting 193 1.8%
9 Water Heater - Low-Flow Showerheads 135 1.3%
10 Appliances - Freezer 95 0.9%
11 Electronics - Personal Computers 86 0.8%
12 Water Heater - Drainwater Heat Recovery 85 0.8%
13 Appliances - Second Refrigerator 59 0.6%
14 Miscellaneous - Pool Pump 51 0.5%
15 Electronics - Laptops 26 0.2%
16 Appliances - Refrigerator 21 0.2%
17 Water Heating - Water Heater (55 to 75 Gal) 12 0.1%
18 Water Heater - Desuperheater 6 0.1%
19 Electronics - Monitor 4 0.0%
20 Electronics - TVs 2 0.0%
Total Total 10,595 100.0%

Figure 5-9 presents forecasts of cumulative energy savings for Idaho. Results are similar to
Washington.
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Figure 5-9 Residential Achievable Savings Forecast (Cumulative GWh), Idaho

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Exterior Lighting
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Miscellaneous
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Commercial Conservation Potential
Table 5-10 (Total), Table 5-11 (WA) and Table 5-12 (ID) present estimates for the three levels of
conservation potential for the commercial sector from the perspective of annual energy savings.
Figure 5-10 (WA) and Figure 5-11(ID) display the three levels of potential by year. For
Washington, the first year of the projection, achievable potential is 9 GWh, or 0.4% of the
baseline projection. By 2035, savings are 419 GWh, or 18.4% of the baseline projection.
Throughout the forecast horizon, achievable potential represents about 85% of economic
potential. . For Idaho, first year achievable savings are 4 GWh or 0.4% of the baseline and by
2035 cumulative achievable savings reach 198 GWh, or 18.7% of the baseline.

Table 5-10 Commercial Conservation Potential (Energy Savings), Washington and Idaho
2016 2017 2020 2025 2035
Baseline projection (GWh) 2,976 2,981 3,013 3,089 3,346
Cumulative Net Savings (GWh)
Achievable Potential 13 28 105 304 617
Economic Potential 29 60 171 395 728
Technical Potential 71 142 353 694 1,096
Cumulative Net Savings (aMW)
Achievable Potential 1.5 3.2 12.0 34.7 70.5
Economic Potential 3.3 6.8 19.5 45.1 83.1
Technical Potential 8.1 16.2 40.3 79.2 125.1
Cumulative Net Savings as a % of Baseline
Achievable Potential 0.4% 1.0% 3.5% 9.9% 18.4%
Economic Potential 1.0% 2.0% 5.7% 12.8% 21.7%
Technical Potential 2.4% 4.8% 11.7% 22.5% 32.8%

Table 5-11 Commercial Conservation Potential (Energy Savings), Washington
2016 2017 2020 2025 2035
Baseline projection (GWh) 2,027 2,031 2,053 2,106 2,282
Cumulative Net Savings (GWh)
Achievable Potential 9 19 71 207 419
Economic Potential 20 41 116 268 494
Technical Potential 49 97 241 473 746
Cumulative Net Savings (aMW)
Achievable Potential 1.0 2.2 8.1 23.6 47.8
Economic Potential 2.3 4.6 13.3 30.6 56.4
Technical Potential 5.5 11.0 27.5 54.0 85.2
Cumulative Net Savings as a % of Baseline
Achievable Potential 0.4% 1.0% 3.5% 9.8% 18.4%
Economic Potential 1.0% 2.0% 5.7% 12.7% 21.6%
Technical Potential 2.4% 4.8% 11.7% 22.5% 32.7%
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Table 5-12 Commercial Conservation Potential (Energy Savings), Idaho
2016 2017 2020 2025 2035
Baseline projection (GWh) 949 950 960 983 1,063
Cumulative Net Savings (GWh)
Achievable Potential 4 9 33 98 198
Economic Potential 9 19 55 127 234
Technical Potential 23 45 112 221 349
Cumulative Net Savings (aMW)
Achievable Potential 0.5 1.0 3.8 11.2 22.6
Economic Potential 1.1 2.2 6.2 14.5 26.7
Technical Potential 2.6 5.2 12.8 25.3 39.9
Cumulative Net Savings as a % of Baseline
Achievable Potential 0.4% 1.0% 3.5% 9.9% 18.7%
Economic Potential 1.0% 2.0% 5.7% 12.9% 22.0%
Technical Potential 2.4% 4.7% 11.7% 22.5% 32.9%
Figure 5-10 Commercial Conservation Savings (Energy), Washington

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20%
25%
30%
35%
2016 2017 2020 2025 2035
Energy Savings
(% of Baseline
Forecast)
Achievable Potential
Economic Potential
Technical Potential
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Figure 5-11 Commercial Conservation Savings (Energy), Idaho

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20%
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30%
35%
2016 2017 2020 2025 2035
Energy Savings
(% of Baseline
Forecast)
Achievable Potential
Economic Potential
Technical Potential
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Below, we present the top commercial measures from the perspective of annual energy use for
Washington and Idaho combined, followed by each state on its own.

Table 5-13 identifies the top 20 commercial-sector measures from the perspective of annual
energy savings in 2017 for Washington and Idaho combined. The top measure is interior LED
replacements for linear-fluorescent style lighting applications. Lighting dominates the top 10
measures. Other measures among the top 10 include chilled water reset, duct repair and sealing,
and night covers for open display cases in grocery stores.

Table 5-13 Commercial Top Measures in 2017 (Annual Energy, MWh), Washington and
Idaho
Rank Commercial Measure
2017 Cumulative
Energy Savings
(MWh)
% of
Total
1 Interior Lighting - Linear LED 6,604 23.3%
2 Interior Lighting - Screw-in/Hard-wire 3,889 13.7%
3 Chiller - Chilled Water Reset 1,362 4.8%
4 Exterior Lighting - Linear LED 1,135 4.0%
5 Interior Lighting - High-Bay Fixtures 1,130 4.0%
6 HVAC - Duct Repair and Sealing 1,068 3.8%
7 Interior Lighting - Occupancy Sensors 975 3.4%
8 Interior Lighting - Skylights 831 2.9%
9 Exterior Lighting - Screw-in/Hard-wire 702 2.5%
10 Exterior Lighting - HID 671 2.4%
11 Grocery - Open Display Case - Night Covers 661 2.3%
12 Insulation - Ducting 599 2.1%
13 Refrigerator - High Efficiency Compressor 575 2.0%
14 Cooling - Water-Cooled Chiller 540 1.9%
15 HVAC - Economizer 519 1.8%
16 Food Preparation - Dishwasher 506 1.8%
17 Insulation - Ceiling 475 1.7%
18 Space Heating - Heat Recovery Ventilator 468 1.7%
19 Exterior Lighting - Bi-Level Fixture 458 1.6%
20 Exterior Lighting - Photovoltaic Installation 453 1.6%
Total Total Top 20 23,620 83.0%

Table 5-14 identifies the top 20 commercial-sector measures from the perspective of annual
energy savings in 2017 in Washington and Table 5-15 shows the top measures for Idaho. For
both states, the top measure is interior LED replacements for linear-fluorescent style lighting
applications. Lighting dominates the top 10 measures. Other measures among the top 10 include
chilled water reset, duct repair and sealing, and night covers for open display cases in grocery
stores.
Figure 5-12 (WA) and Figure 5-13 (ID) present forecasts of cumulative energy savings by end
use. Lighting savings from interior and exterior applications account for a substantial portion of
the savings throughout the forecast horizon. Cooling savings are also substantial throughout the
forecast.
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Table 5-14 Commercial Top Measures in 2017 (Annual Energy, MWh), Washington
Rank Commercial Measure
2017 Cumulative
Energy Savings
(MWh)
% of
Total
1 Interior Lighting - Linear LED 4,470 23.1%
2 Interior Lighting - Screw-in/Hard-wire 2,652 13.7%
3 Chiller - Chilled Water Reset 924 4.8%
4 HVAC - Duct Repair and Sealing 793 4.1%
5 Interior Lighting - High-Bay Fixtures 764 4.0%
6 Exterior Lighting - Linear LED 688 3.6%
7 Interior Lighting - Occupancy Sensors 678 3.5%
8 Interior Lighting - Skylights 561 2.9%
9 Exterior Lighting - Screw-in/Hard-wire 478 2.5%
10 Grocery - Open Display Case - Night Covers 459 2.4%
11 Exterior Lighting - HID 454 2.3%
12 Insulation - Ducting 408 2.1%
13 Refrigerator - High Efficiency Compressor 401 2.1%
14 Cooling - Water-Cooled Chiller 391 2.0%
15 Food Preparation - Dishwasher 347 1.8%
16 HVAC - Economizer 345 1.8%
17 Insulation - Ceiling 337 1.7%
18 Space Heating - Heat Recovery Ventilator 315 1.6%
19 Exterior Lighting - Bi-Level Fixture 299 1.5%
20 Exterior Lighting - Photovoltaic Installation 289 1.5%
Total Total Top 20 16,053 83.0%
Figure 5-12 Commercial Achievable Savings Forecast (Cumulative GWh), Washington

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Water Heating
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Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
Miscellaneous
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Table 5-15 Commercial Top Measures in 2017 (Annual Energy, MWh), Idaho
Rank Commercial Measure
2017 Cumulative
Energy Savings
(MWh)
% of
Total
1 Interior Lighting - Linear LED 2,134 23.6%
2 Interior Lighting - Screw-in/Hard-wire 1,237 13.7%
3 Exterior Lighting - Linear LED 448 5.0%
4 Chiller - Chilled Water Reset 437 4.8%
5 Interior Lighting - High-Bay Fixtures 366 4.1%
6 Interior Lighting - Occupancy Sensors 297 3.3%
7 HVAC - Duct Repair and Sealing 275 3.0%
8 Interior Lighting - Skylights 270 3.0%
9 Exterior Lighting - Screw-in/Hard-wire 224 2.5%
10 Exterior Lighting - HID 217 2.4%
11 Grocery - Open Display Case - Night Covers 202 2.2%
12 Insulation - Ducting 191 2.1%
13 Refrigerator - High Efficiency Compressor 174 1.9%
14 HVAC - Economizer 174 1.9%
15 Exterior Lighting - Photovoltaic Installation 164 1.8%
16 Food Preparation - Dishwasher 159 1.8%
17 Exterior Lighting - Bi-Level Fixture 158 1.8%
18 Space Heating - Heat Recovery Ventilator 153 1.7%
19 Cooling - Water-Cooled Chiller 149 1.6%
20 Refrigerator - Variable Speed Compressor 140 1.6%
Total Total Top 20 7,569 83.8%

Figure 5-13 Commercial Achievable Savings Forecast (Cumulative GWh), Idaho

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Interior Lighting
Exterior Lighting
Refrigeration
Food Preparation
Office Equipment
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Industrial Conservation Potential
Table 5-16 (Total), Table 5-17 (WA) and Table 5-18 (ID) present potential estimates at the
measure level for the industrial sector, from the perspective of annual energy savings.
Figure 5-14 (WA) and Figure 5-15 (ID) display the three levels of potential by year.
For Washington, achievable savings in the first year, 2016, are 5 GWh, or 0.5% of the baseline
projection. In 2035, savings reach 146 GWh, or 12.7% of the baseline projection. For Idaho,
achievable savings in the first year, 2016, are 2 GWh, or 0.7% of the baseline projection. In
2035, savings reach 53 GWh, or 12.4% of the baseline projection.
Table 5-16 Industrial Conservation Potential (Annual Energy, GWh), Washington and
Idaho
2016 2017 2020 2025 2035
Baseline projection (GWh) 1,356 1,370 1,404 1,458 1,575
Cumulative Net Savings (GWh)
Achievable Potential 8 16 44 101 199
Economic Potential 9 19 52 118 231
Technical Potential 17 34 84 168 293
Cumulative Net Savings (aMW)
Achievable Potential 0.9 1.8 5.1 11.6 22.7
Economic Potential 1.0 2.1 5.9 13.5 26.3
Technical Potential 1.9 3.9 9.6 19.2 33.5
Cumulative Net Savings as a % of Baseline
Achievable Potential 0.6% 1.2% 3.2% 7.0% 12.6%
Economic Potential 0.7% 1.4% 3.7% 8.1% 14.7%
Technical Potential 1.3% 2.5% 6.0% 11.5% 18.6%

Table 5-17 Industrial Conservation Potential (Annual Energy, GWh), Washington
2016 2017 2020 2025 2035
Baseline projection (GWh) 989 999 1,024 1,064 1,149
Cumulative Net Savings (GWh)
Achievable Potential 5 11 31 73 146
Economic Potential 6 13 37 86 169
Technical Potential 12 25 61 123 214
Cumulative Net Savings (aMW)
Achievable Potential 0.6 1.3 3.6 8.4 16.7
Economic Potential 0.7 1.5 4.2 9.8 19.3
Technical Potential 1.4 2.8 7.0 14.0 24.4
Cumulative Net Savings as a % of Baseline
Achievable Potential 0.5% 1.1% 3.1% 6.9% 12.7%
Economic Potential 0.6% 1.3% 3.6% 8.0% 14.7%
Technical Potential 1.3% 2.5% 6.0% 11.5% 18.6%
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Table 5-18 Industrial Conservation Potential (Annual Energy, GWh), Idaho
2016 2017 2020 2025 2035
Baseline projection (GWh) 367 371 380 395 426
Cumulative Net Savings (GWh)
Achievable Potential 2 5 13 28 53
Economic Potential 3 6 15 33 61
Technical Potential 5 9 23 46 79
Cumulative Net Savings (aMW)
Achievable Potential 0.3 0.6 1.5 3.2 6.0
Economic Potential 0.3 0.6 1.7 3.8 7.0
Technical Potential 0.5 1.0 2.6 5.2 9.1
Cumulative Net Savings as a % of Baseline
Achievable Potential 0.7% 1.3% 3.4% 7.1% 12.4%
Economic Potential 0.8% 1.5% 4.0% 8.3% 14.4%
Technical Potential 1.3% 2.5% 6.0% 11.5% 18.6%

Figure 5-14 Industrial Conservation Potential as a % of the Baseline Projection
(Annual Energy), Washington

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16%
18%
20%
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Energy Savings
(% of Baseline
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Achievable Potential
Economic Potential
Technical Potential
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Figure 5-15 Industrial Conservation Potential as a % of the Baseline Projection
(Annual Energy), Idaho

Below, we present the top industrial measures from the perspective of annual energy use for
Washington and Idaho combined, followed by each state.

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16%
18%
20%
2016 2017 2020 2025 2035
Energy Savings
(% of Baseline
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Achievable Potential
Economic Potential
Technical Potential
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Table 5-19 identifies the top 20 industrial measures from the perspective of annual energy
savings in 2017 for Washington and Idaho. Table 5-20 and Table 5-21 show the top measures
for each state individually. For both states, the top measure is optimization and improvements on
fan systems. The measure with the second highest savings is variable frequency drive for pumps.

Figure 5-16 (WA) and Figure 5-17 (ID) present forecasts of energy savings by end use as a
percent of total annual savings and cumulative savings. Motor-related measures account for a
substantial portion of the savings throughout the forecast horizon. The share of savings by end
use remains fairly similar throughout the forecast period.
Table 5-19 Industrial Top Measures in 2017 (Annual Energy, GWh), Washington and
Idaho
Rank Industrial Measure
2017 Cumulative
Energy Savings
(MWh)
% of
Total
1 Fan System - Optimization and Improvements 4,524 28.3%
2 Motors - Variable Frequency Drive (Pumps) 3,020 18.9%
3 Motors - Variable Frequency Drive (Fans & Blowers) 1,505 9.4%
4 Compressed Air - Air Usage Reduction 1,247 7.8%
5 Pumping System - Optimization and Improvements 893 5.6%
6 Interior Lighting - Occupancy Sensors 703 4.4%
7 Interior Lighting - High-Bay Fixtures 420 2.6%
8 Fan System - Maintenance 414 2.6%
9 Interior Lighting - Screw-in/Hard-wire 403 2.5%
10 Motors - Variable Frequency Drive (Compressed Air) 399 2.5%
11 HVAC - Duct Repair and Sealing 362 2.3%
12 Transformer - High Efficiency 298 1.9%
13 Motors - Variable Frequency Drive (Other) 272 1.7%
14 Compressed Air - System Optimization and
Improvements 271 1.7%
15 Exterior Lighting - Screw-in/Hard-wire 240 1.5%
16 Chiller - Chilled Water Reset 216 1.3%
17 Insulation - Wall Cavity 143 0.9%
18 Compressed Air - Compressor Replacement 142 0.9%
19 Interior Lighting - Skylights 118 0.7%
20 Destratification Fans (HVLS) 101 0.6%
Total Total 15,692 98.1%

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Table 5-20 Industrial Top Measures in 2017 (Annual Energy, GWh), Washington
Rank Industrial Measure
2017 Cumulative
Energy Savings
(MWh)
% of
Total
1 Fan System - Optimization and Improvements 3,298 29.5%
2 Motors - Variable Frequency Drive (Pumps) 2,206 19.8%
3 Motors - Variable Frequency Drive (Fans & Blowers) 1,098 9.8%
4 Compressed Air - Air Usage Reduction 911 8.2%
5 Pumping System - Optimization and Improvements 663 5.9%
6 Interior Lighting - Occupancy Sensors 520 4.7%
7 Motors - Variable Frequency Drive (Compressed Air) 377 3.4%
8 Interior Lighting - High-Bay Fixtures 306 2.7%
9 Interior Lighting - Screw-in/Hard-wire 294 2.6%
10 HVAC - Duct Repair and Sealing 264 2.4%
11 Transformer - High Efficiency 217 1.9%
12 Exterior Lighting - Screw-in/Hard-wire 175 1.6%
13 Motors - Variable Frequency Drive (Other) 162 1.4%
14 Chiller - Chilled Water Reset 157 1.4%
15 Insulation - Wall Cavity 106 1.0%
16 Compressed Air - Compressor Replacement 104 0.9%
17 Interior Lighting - Skylights 86 0.8%
18 Chiller - Chilled Water Variable-Flow System 47 0.4%
19 Exterior Lighting - HID 44 0.4%
20 Chiller - VSD on Fans 43 0.4%
Total Total 11,080 99.2%

Figure 5-16 Industrial Achievable Savings Forecast (Cumulative GWh), Washington

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Table 5-21 Industrial Top Measures in 2017 (Annual Energy, GWh), Idaho
Rank Industrial Measure
2017 Cumulative
Energy Savings
(MWh)
% of
Total
1 Fan System - Optimization and Improvements 1,226 25.4%
2 Motors - Variable Frequency Drive (Pumps) 814 16.8%
3 Fan System - Maintenance 414 8.6%
4 Motors - Variable Frequency Drive (Fans & Blowers) 407 8.4%
5 Compressed Air - Air Usage Reduction 336 7.0%
6 Compressed Air - System Optimization and
Improvements 271 5.6%
7 Pumping System - Optimization and Improvements 230 4.8%
8 Interior Lighting - Occupancy Sensors 183 3.8%
9 Interior Lighting - High-Bay Fixtures 114 2.4%
10 Motors - Variable Frequency Drive (Other) 110 2.3%
11 Interior Lighting - Screw-in/Hard-wire 109 2.3%
12 Destratification Fans (HVLS) 101 2.1%
13 HVAC - Duct Repair and Sealing 98 2.0%
14 Transformer - High Efficiency 81 1.7%
15 Exterior Lighting - Screw-in/Hard-wire 65 1.3%
16 Chiller - Chilled Water Reset 59 1.2%
17 Compressed Air - Compressor Replacement 39 0.8%
18 Insulation - Wall Cavity 37 0.8%
19 Interior Lighting - Skylights 32 0.7%
20 Motors - Variable Frequency Drive (Compressed Air) 22 0.5%
Total Total 4,747 98.2%

Figure 5-17 Industrial Achievable Savings Forecast (Annual Energy, GWh), Idaho

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APPENDIX A
Market Profiles
This appendix presents the market profiles for each sector and segment for Washington,
followed by Idaho.
Table A-1 Residential Single Family Electric Market Profile, Washington

UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 47.8% 1,462 699 91
Cooling Room AC 15.3%532 81 11
Cooling Air-Source Heat Pump 8.0% 1,531 123 16
Cooling Geothermal Heat Pump 0.3% 1,352 4 0
Cooling Evaporative AC 1.3% 1,054 14 2
Space Heating Electric Room Heat 6.3% 15,052 951 124
Space Heating Electric Furnace 7.4% 17,137 1,271 165
Space Heating Air-Source Heat Pump 8.0% 12,902 1,034 134
Space Heating Geothermal Heat Pump 0.3% 5,686 16 2
Water Heating Water Heater (<= 55 Gal)42.1% 3,866 1,629 212
Water Heating Water Heater (55 to 75 Gal)5.1% 4,065 209 27
Water Heating Water Heater (> 75 Gal)0.4% 4,261 19 2
Interior Lighting Screw-in/Hard-wire 100.0% 1,135 1,135 147
Interior Lighting Linear Fluorescent 100.0%154 154 20
Interior Lighting Specialty Lighting 100.0%425 425 55
Exterior Lighting Screw-in/Hard-wire 100.0%445 445 58
Appliances Clothes Washer 96.4%111 107 14
Appliances Clothes Dryer 38.6%862 333 43
Appliances Dishwasher 80.9%476 385 50
Appliances Refrigerator 100.0%888 888 115
Appliances Freezer 59.1%710 419 54
Appliances Second Refrigerator 29.4% 1,034 304 40
Appliances Stove 66.9%509 341 44
Appliances Microwave 95.6%148 142 18
Electronics Personal Computers 80.5%223 180 23
Electronics Monitor 98.4%95 93 12
Electronics Laptops 94.4%59 56 7
Electronics TVs 205.8%253 521 68
Electronics Printer/Fax/Copier 85.5%68 58 8
Electronics Set top Boxes/DVRs 175.4%134 234 30
Electronics Devices and Gadgets 100.0%58 58 7
Miscellaneous Pool Pump 3.1% 2,526 78 10
Miscellaneous Pool Heater 0.8% 4,045 31 4
Miscellaneous Furnace Fan 75.8%279 212 28
Miscellaneous Well pump 14.9%645 96 12
Miscellaneous Miscellaneous 100.0%982 982 128
13,726 1,783
Average Market Profiles - Electricity
Total
End Use Technology Saturation
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Table A-2 Residential Multifamily Electric Market Profile, Washington

UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 16.2%355 57 1
Cooling Room AC 48.5%282 137 2
Cooling Air-Source Heat Pump 3.6%355 13 0
Cooling Geothermal Heat Pump 0.0%314 0 0
Cooling Evaporative AC 0.9%293 3 0
Space Heating Electric Room Heat 74.4% 2,814 2,095 25
Space Heating Electric Furnace 7.8% 3,204 249 3
Space Heating Air-Source Heat Pump 3.6% 1,754 63 1
Space Heating Geothermal Heat Pump 0.0%773 0 0
Water Heating Water Heater (<= 55 Gal)65.9% 2,205 1,453 17
Water Heating Water Heater (55 to 75 Gal)8.7% 2,319 202 2
Water Heating Water Heater (> 75 Gal)0.0% 2,430 0 0
Interior Lighting Screw-in/Hard-wire 100.0%639 639 8
Interior Lighting Linear Fluorescent 100.0%40 40 0
Interior Lighting Specialty Lighting 100.0%37 37 0
Exterior Lighting Screw-in/Hard-wire 100.0% 0 0 0
Appliances Clothes Washer 82.7%96 79 1
Appliances Clothes Dryer 69.1%593 410 5
Appliances Dishwasher 70.9%413 293 4
Appliances Refrigerator 100.0%771 771 9
Appliances Freezer 46.4%620 288 3
Appliances Second Refrigerator 3.0%898 27 0
Appliances Stove 74.5%357 266 3
Appliances Microwave 93.6%129 121 1
Electronics Personal Computers 35.5%194 69 1
Electronics Monitor 43.4%82 36 0
Electronics Laptops 41.9%52 22 0
Electronics TVs 124.7%269 335 4
Electronics Printer/Fax/Copier 49.5%59 29 0
Electronics Set top Boxes/DVRs 91.4%116 106 1
Electronics Devices and Gadgets 100.0%50 50 1
Miscellaneous Pool Pump 0.0% 2,197 0 0
Miscellaneous Pool Heater 0.0% 3,517 0 0
Miscellaneous Furnace Fan 18.9%98 19 0
Miscellaneous Well pump 0.0%556 0 0
Miscellaneous Miscellaneous 100.0%328 328 4
8,236 99
Average Market Profiles - Electricity
Total
End Use Technology Saturation
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Table A-3 Residential Manufactured Home Electric Market Profile, Washington

UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 30.8%556 171 1
Cooling Room AC 29.1%439 128 1
Cooling Air-Source Heat Pump 5.1%556 29 0
Cooling Geothermal Heat Pump 0.0%490 0 0
Cooling Evaporative AC 1.7%354 6 0
Space Heating Electric Room Heat 4.1% 7,208 294 2
Space Heating Electric Furnace 52.3% 8,207 4,295 33
Space Heating Air-Source Heat Pump 5.1% 6,752 346 3
Space Heating Geothermal Heat Pump 0.0% 3,094 0 0
Water Heating Water Heater (<= 55 Gal)63.3% 2,370 1,501 12
Water Heating Water Heater (55 to 75 Gal)8.4% 2,492 209 2
Water Heating Water Heater (> 75 Gal)0.0% 2,612 0 0
Interior Lighting Screw-in/Hard-wire 100.0%724 724 6
Interior Lighting Linear Fluorescent 100.0%87 87 1
Interior Lighting Specialty Lighting 100.0%134 134 1
Exterior Lighting Screw-in/Hard-wire 100.0%170 170 1
Appliances Clothes Washer 91.2%91 83 1
Appliances Clothes Dryer 66.7%888 592 5
Appliances Dishwasher 70.2%394 277 2
Appliances Refrigerator 100.0%732 732 6
Appliances Freezer 61.4%586 360 3
Appliances Second Refrigerator 21.0%852 179 1
Appliances Stove 82.5%510 421 3
Appliances Microwave 93.0%123 114 1
Electronics Personal Computers 45.8%184 85 1
Electronics Monitor 56.0%78 44 0
Electronics Laptops 66.7%49 33 0
Electronics TVs 156.3%273 426 3
Electronics Printer/Fax/Copier 58.3%56 33 0
Electronics Set top Boxes/DVRs 91.7%110 101 1
Electronics Devices and Gadgets 100.0%48 48 0
Miscellaneous Pool Pump 0.0% 2,087 0 0
Miscellaneous Pool Heater 0.0% 3,341 0 0
Miscellaneous Furnace Fan 84.6%205 173 1
Miscellaneous Well pump 0.0%428 0 0
Miscellaneous Miscellaneous 100.0%560 560 4
12,354 95
Average Market Profiles - Electricity
Total
End Use Technology Saturation
2015 Electric IRP Appendix C
745
Energy Efficiency Potential Study
Applied Energy Group, Inc. 92
Table A-4 Residential Low Income Electric Market Profile, Washington

UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 19.4%456 88 6
Cooling Room AC 44.7%333 149 10
Cooling Air-Source Heat Pump 4.0%460 18 1
Cooling Geothermal Heat Pump 0.0%406 0 0
Cooling Evaporative AC 1.0%350 3 0
Space Heating Electric Room Heat 53.8% 3,606 1,939 124
Space Heating Electric Furnace 22.1% 4,106 906 58
Space Heating Air-Source Heat Pump 4.0% 2,697 108 7
Space Heating Geothermal Heat Pump 0.0% 1,202 0 0
Water Heating Water Heater (<= 55 Gal)64.3% 2,142 1,378 88
Water Heating Water Heater (55 to 75 Gal)8.5% 2,253 191 12
Water Heating Water Heater (> 75 Gal)0.0% 2,361 1 0
Interior Lighting Screw-in/Hard-wire 100.0%676 676 43
Interior Lighting Linear Fluorescent 100.0%51 51 3
Interior Lighting Specialty Lighting 100.0%68 68 4
Exterior Lighting Screw-in/Hard-wire 100.0%42 42 3
Appliances Clothes Washer 84.3%91 77 5
Appliances Clothes Dryer 67.1%603 405 26
Appliances Dishwasher 71.4%393 280 18
Appliances Refrigerator 100.0%732 732 47
Appliances Freezer 48.5%589 286 18
Appliances Second Refrigerator 6.2%853 53 3
Appliances Stove 74.9%360 270 17
Appliances Microwave 93.7%123 115 7
Electronics Personal Computers 39.0%184 72 5
Electronics Monitor 47.7%78 37 2
Electronics Laptops 47.3%49 23 1
Electronics TVs 132.4%255 337 22
Electronics Printer/Fax/Copier 52.4%56 29 2
Electronics Set top Boxes/DVRs 96.2%110 106 7
Electronics Devices and Gadgets 100.0%48 48 3
Miscellaneous Pool Pump 0.2% 2,087 4 0
Miscellaneous Pool Heater 0.0% 3,341 1 0
Miscellaneous Furnace Fan 28.5%119 34 2
Miscellaneous Well pump 0.8%519 4 0
Miscellaneous Miscellaneous 100.0%361 361 23
8,892 570
Average Market Profiles - Electricity
Total
End Use Technology Saturation
2015 Electric IRP Appendix C
746
Energy Efficiency Potential Study
Applied Energy Group, Inc. 93
Table A-5 Small Office Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 0.5%4.59 0.02 0.4
Cooling Water-Cooled Chiller 0.0%5.20 0.00 0.0
Cooling RTU 77.9%3.79 2.96 53.5
Cooling Room AC 3.6%3.90 0.14 2.6
Cooling Air-Source Heat Pump 8.2%3.79 0.31 5.6
Cooling Geothermal Heat Pump 3.2%2.31 0.07 1.3
Heating Electric Furnace 16.0%6.82 1.09 19.7
Heating Electric Room Heat 14.5%6.50 0.94 17.1
Heating Air-Source Heat Pump 8.2%5.76 0.47 8.5
Heating Geothermal Heat Pump 3.2%4.38 0.14 2.5
Ventilation Ventilation 100.0%1.40 1.40 25.3
Water Heating Water Heater 69.8%1.05 0.73 13.2
Interior Lighting Screw-in/Hard-wire 100.0%0.62 0.62 11.3
Interior Lighting High-Bay Fixtures 100.0%0.34 0.34 6.2
Interior Lighting Linear Fluorescent 100.0%2.05 2.05 37.1
Exterior Lighting Screw-in/Hard-wire 100.0%0.14 0.14 2.5
Exterior Lighting HID 100.0%0.19 0.19 3.4
Exterior Lighting Linear Fluorescent 100.0%0.07 0.07 1.2
Refrigeration Walk-in Refrigerator/Freezer 0.2%2.34 0.01 0.1
Refrigeration Reach-in Refrigerator/Freezer 1.6%0.52 0.01 0.2
Refrigeration Glass Door Display 0.5%0.54 0.00 0.0
Refrigeration Open Display Case 0.5%3.19 0.01 0.3
Refrigeration Icemaker 0.5%0.88 0.00 0.1
Refrigeration Vending Machine 0.2%0.41 0.00 0.0
Food Preparation Oven 0.8%1.50 0.01 0.2
Food Preparation Fryer 0.1%2.17 0.00 0.0
Food Preparation Dishwasher 1.0%2.99 0.03 0.5
Food Preparation Steamer 0.1%2.19 0.00 0.0
Food Preparation Hot Food Container 0.1%0.41 0.00 0.0
Office Equipment Desktop Computer 100.0%1.55 1.55 28.1
Office Equipment Laptop 100.0%0.24 0.24 4.3
Office Equipment Server 100.0%0.46 0.46 8.3
Office Equipment Monitor 100.0%0.27 0.27 5.0
Office Equipment Printer/Copier/Fax 100.0%0.21 0.21 3.8
Office Equipment POS Terminal 40.0%0.12 0.05 0.9
Miscellaneous Non-HVAC Motors 22.0%0.20 0.04 0.8
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.86 0.86 15.5
Total 15.44 279.6
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
747
Energy Efficiency Potential Study
Applied Energy Group, Inc. 94
Table A-6 Large Office Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 23.5%2.69 0.63 3.8
Cooling Water-Cooled Chiller 23.5%2.97 0.70 4.2
Cooling RTU 33.4%3.28 1.10 6.6
Cooling Room AC 0.6%3.37 0.02 0.1
Cooling Air-Source Heat Pump 7.5%3.28 0.25 1.5
Cooling Geothermal Heat Pump 6.5%2.00 0.13 0.8
Heating Electric Furnace 15.7%5.04 0.79 4.8
Heating Electric Room Heat 14.3%4.80 0.68 4.1
Heating Air-Source Heat Pump 7.5%4.62 0.35 2.1
Heating Geothermal Heat Pump 6.5%3.66 0.24 1.4
Ventilation Ventilation 100.0%2.96 2.96 17.9
Water Heating Water Heater 68.0%0.99 0.67 4.1
Interior Lighting Screw-in/Hard-wire 100.0%0.62 0.62 3.8
Interior Lighting High-Bay Fixtures 100.0%0.37 0.37 2.3
Interior Lighting Linear Fluorescent 100.0%2.74 2.74 16.6
Exterior Lighting Screw-in/Hard-wire 100.0%0.14 0.14 0.8
Exterior Lighting HID 100.0%0.37 0.37 2.2
Exterior Lighting Linear Fluorescent 100.0%0.23 0.23 1.4
Refrigeration Walk-in Refrigerator/Freezer 2.0%1.62 0.03 0.2
Refrigeration Reach-in Refrigerator/Freezer 14.0%0.36 0.05 0.3
Refrigeration Glass Door Display 4.0%0.37 0.01 0.1
Refrigeration Open Display Case 4.0%2.22 0.09 0.5
Refrigeration Icemaker 4.0%0.61 0.02 0.1
Refrigeration Vending Machine 2.1%0.29 0.01 0.0
Food Preparation Oven 10.0%0.76 0.08 0.5
Food Preparation Fryer 1.0%1.10 0.01 0.1
Food Preparation Dishwasher 12.0%1.52 0.18 1.1
Food Preparation Steamer 1.0%1.11 0.01 0.1
Food Preparation Hot Food Container 1.0%0.21 0.00 0.0
Office Equipment Desktop Computer 100.0%1.96 1.96 11.8
Office Equipment Laptop 100.0%0.30 0.30 1.8
Office Equipment Server 100.0%0.19 0.19 1.2
Office Equipment Monitor 100.0%0.35 0.35 2.1
Office Equipment Printer/Copier/Fax 100.0%0.18 0.18 1.1
Office Equipment POS Terminal 40.0%0.03 0.01 0.1
Miscellaneous Non-HVAC Motors 89.6%0.22 0.20 1.2
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.86 0.86 5.2
Total 17.54 105.9
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
748
Energy Efficiency Potential Study
Applied Energy Group, Inc. 95
Table A-7 Restaurant Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 0.3%3.59 0.01 0.0
Cooling Water-Cooled Chiller 0.0%3.97 0.00 0.0
Cooling RTU 76.3%4.51 3.44 5.7
Cooling Room AC 6.6%4.63 0.31 0.5
Cooling Air-Source Heat Pump 6.6%4.51 0.30 0.5
Cooling Geothermal Heat Pump 3.3%2.75 0.09 0.1
Heating Electric Furnace 5.1%7.05 0.36 0.6
Heating Electric Room Heat 0.1%6.72 0.01 0.0
Heating Air-Source Heat Pump 6.6%4.98 0.33 0.5
Heating Geothermal Heat Pump 3.3%3.51 0.12 0.2
Ventilation Ventilation 100.0%2.48 2.48 4.1
Water Heating Water Heater 35.2%8.81 3.10 5.1
Interior Lighting Screw-in/Hard-wire 100.0%2.09 2.09 3.5
Interior Lighting High-Bay Fixtures 100.0%0.40 0.40 0.7
Interior Lighting Linear Fluorescent 100.0%3.62 3.62 6.0
Exterior Lighting Screw-in/Hard-wire 100.0%0.23 0.23 0.4
Exterior Lighting HID 100.0%1.61 1.61 2.7
Exterior Lighting Linear Fluorescent 100.0%0.47 0.47 0.8
Refrigeration Walk-in Refrigerator/Freezer 74.0%6.56 4.85 8.0
Refrigeration Reach-in Refrigerator/Freezer 7.0%2.94 0.21 0.3
Refrigeration Glass Door Display 77.6%1.51 1.17 1.9
Refrigeration Open Display Case 26.0%8.95 2.33 3.9
Refrigeration Icemaker 75.9%2.47 1.88 3.1
Refrigeration Vending Machine 0.0%1.16 0.00 0.0
Food Preparation Oven 16.0%9.79 1.57 2.6
Food Preparation Fryer 14.0%14.16 1.98 3.3
Food Preparation Dishwasher 48.0%9.75 4.68 7.8
Food Preparation Steamer 14.0%7.15 1.00 1.7
Food Preparation Hot Food Container 31.0%1.33 0.41 0.7
Office Equipment Desktop Computer 100.0%0.29 0.29 0.5
Office Equipment Laptop 100.0%0.04 0.04 0.1
Office Equipment Server 50.0%0.34 0.17 0.3
Office Equipment Monitor 100.0%0.05 0.05 0.1
Office Equipment Printer/Copier/Fax 100.0%0.06 0.06 0.1
Office Equipment POS Terminal 100.0%0.09 0.09 0.1
Miscellaneous Non-HVAC Motors 20.0%0.58 0.12 0.2
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%2.57 2.57 4.3
Total 42.40 70.3
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
749
Energy Efficiency Potential Study
Applied Energy Group, Inc. 96
Table A-8 Retail Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 9.5%2.74 0.26 5.4
Cooling Water-Cooled Chiller 2.4%3.10 0.07 1.5
Cooling RTU 54.2%2.26 1.23 25.4
Cooling Room AC 2.8%2.48 0.07 1.4
Cooling Air-Source Heat Pump 1.7%2.26 0.04 0.8
Cooling Geothermal Heat Pump 1.4%1.38 0.02 0.4
Heating Electric Furnace 5.8%4.86 0.28 5.8
Heating Electric Room Heat 2.1%4.63 0.10 2.0
Heating Air-Source Heat Pump 1.7%3.89 0.07 1.4
Heating Geothermal Heat Pump 1.4%2.65 0.04 0.7
Ventilation Ventilation 100.0%0.98 0.98 20.2
Water Heating Water Heater 63.0%0.79 0.50 10.3
Interior Lighting Screw-in/Hard-wire 100.0%0.85 0.85 17.5
Interior Lighting High-Bay Fixtures 100.0%1.02 1.02 21.1
Interior Lighting Linear Fluorescent 100.0%3.43 3.43 70.9
Exterior Lighting Screw-in/Hard-wire 100.0%0.36 0.36 7.4
Exterior Lighting HID 100.0%1.30 1.30 26.9
Exterior Lighting Linear Fluorescent 100.0%0.87 0.87 18.0
Refrigeration Walk-in Refrigerator/Freezer 2.0%2.04 0.04 0.8
Refrigeration Reach-in Refrigerator/Freezer 0.0%0.46 0.00 0.0
Refrigeration Glass Door Display 16.3%0.47 0.08 1.6
Refrigeration Open Display Case 14.0%2.79 0.39 8.1
Refrigeration Icemaker 7.1%0.77 0.05 1.1
Refrigeration Vending Machine 22.8%0.36 0.08 1.7
Food Preparation Oven 8.0%2.43 0.19 4.0
Food Preparation Fryer 1.6%3.51 0.06 1.2
Food Preparation Dishwasher 2.0%4.84 0.10 2.0
Food Preparation Steamer 1.6%3.55 0.06 1.2
Food Preparation Hot Food Container 1.0%0.66 0.01 0.1
Office Equipment Desktop Computer 100.0%0.34 0.34 7.0
Office Equipment Laptop 100.0%0.05 0.05 1.1
Office Equipment Server 82.0%0.06 0.05 1.0
Office Equipment Monitor 100.0%0.06 0.06 1.2
Office Equipment Printer/Copier/Fax 100.0%0.05 0.05 1.0
Office Equipment POS Terminal 100.0%0.01 0.01 0.3
Miscellaneous Non-HVAC Motors 40.2%0.17 0.07 1.4
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.64 0.64 13.2
Total 13.80 285.2
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
750
Energy Efficiency Potential Study
Applied Energy Group, Inc. 97
Table A-9 Grocery Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 5.3%5.10 0.27 1.2
Cooling Water-Cooled Chiller 0.0%5.77 0.00 0.0
Cooling RTU 69.6%4.21 2.93 13.0
Cooling Room AC 0.0%4.33 0.00 0.0
Cooling Air-Source Heat Pump 3.1%3.72 0.12 0.5
Cooling Geothermal Heat Pump 0.0%1.57 0.00 0.0
Heating Electric Furnace 15.4%5.68 0.87 3.9
Heating Electric Room Heat 1.5%5.41 0.08 0.4
Heating Air-Source Heat Pump 3.1%3.05 0.10 0.4
Heating Geothermal Heat Pump 0.0%1.95 0.00 0.0
Ventilation Ventilation 100.0%2.07 2.07 9.2
Water Heating Water Heater 38.2%2.18 0.83 3.7
Interior Lighting Screw-in/Hard-wire 100.0%1.93 1.93 8.5
Interior Lighting High-Bay Fixtures 100.0%1.70 1.70 7.5
Interior Lighting Linear Fluorescent 100.0%5.83 5.83 25.8
Exterior Lighting Screw-in/Hard-wire 100.0%0.19 0.19 0.8
Exterior Lighting HID 100.0%1.16 1.16 5.1
Exterior Lighting Linear Fluorescent 100.0%0.48 0.48 2.1
Refrigeration Walk-in Refrigerator/Freezer 16.0%5.13 0.82 3.6
Refrigeration Reach-in Refrigerator/Freezer 83.1%0.33 0.27 1.2
Refrigeration Glass Door Display 95.6%3.37 3.23 14.3
Refrigeration Open Display Case 95.6%19.99 19.12 84.6
Refrigeration Icemaker 66.6%0.28 0.18 0.8
Refrigeration Vending Machine 36.5%0.26 0.09 0.4
Food Preparation Oven 17.0%2.44 0.42 1.8
Food Preparation Fryer 13.0%3.53 0.46 2.0
Food Preparation Dishwasher 7.0%4.86 0.34 1.5
Food Preparation Steamer 13.0%3.57 0.46 2.1
Food Preparation Hot Food Container 16.0%0.67 0.11 0.5
Office Equipment Desktop Computer 100.0%0.25 0.25 1.1
Office Equipment Laptop 64.0%0.04 0.03 0.1
Office Equipment Server 100.0%0.15 0.15 0.7
Office Equipment Monitor 100.0%0.04 0.04 0.2
Office Equipment Printer/Copier/Fax 100.0%0.03 0.03 0.1
Office Equipment POS Terminal 100.0%0.10 0.10 0.4
Miscellaneous Non-HVAC Motors 34.6%0.57 0.20 0.9
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%2.40 2.40 10.6
Total 47.25 209.1
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
751
Energy Efficiency Potential Study
Applied Energy Group, Inc. 98
Table A-10 College Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 34.8%3.08 1.07 6.0
Cooling Water-Cooled Chiller 8.7%4.56 0.40 2.2
Cooling RTU 15.6%2.00 0.31 1.7
Cooling Room AC 5.0%2.05 0.10 0.6
Cooling Air-Source Heat Pump 3.6%1.99 0.07 0.4
Cooling Geothermal Heat Pump 0.0%1.21 0.00 0.0
Heating Electric Furnace 10.5%8.76 0.92 5.1
Heating Electric Room Heat 29.7%8.34 2.48 13.9
Heating Air-Source Heat Pump 3.6%6.22 0.23 1.3
Heating Geothermal Heat Pump 0.0%4.81 0.00 0.0
Ventilation Ventilation 100.0%1.48 1.48 8.3
Water Heating Water Heater 26.3%2.02 0.53 3.0
Interior Lighting Screw-in/Hard-wire 100.0%0.83 0.83 4.6
Interior Lighting High-Bay Fixtures 100.0%0.30 0.30 1.7
Interior Lighting Linear Fluorescent 100.0%2.04 2.04 11.5
Exterior Lighting Screw-in/Hard-wire 100.0%0.01 0.01 0.0
Exterior Lighting HID 100.0%0.27 0.27 1.5
Exterior Lighting Linear Fluorescent 100.0%0.97 0.97 5.4
Refrigeration Walk-in Refrigerator/Freezer 7.7%0.29 0.02 0.1
Refrigeration Reach-in Refrigerator/Freezer 13.4%0.13 0.02 0.1
Refrigeration Glass Door Display 8.0%0.07 0.01 0.0
Refrigeration Open Display Case 4.8%0.40 0.02 0.1
Refrigeration Icemaker 28.2%0.22 0.06 0.3
Refrigeration Vending Machine 8.8%0.10 0.01 0.1
Food Preparation Oven 13.7%0.68 0.09 0.5
Food Preparation Fryer 1.6%0.98 0.02 0.1
Food Preparation Dishwasher 11.7%1.35 0.16 0.9
Food Preparation Steamer 1.6%0.99 0.02 0.1
Food Preparation Hot Food Container 8.4%0.19 0.02 0.1
Office Equipment Desktop Computer 100.0%0.51 0.51 2.9
Office Equipment Laptop 100.0%0.02 0.02 0.1
Office Equipment Server 100.0%0.06 0.06 0.3
Office Equipment Monitor 100.0%0.09 0.09 0.5
Office Equipment Printer/Copier/Fax 100.0%0.07 0.07 0.4
Office Equipment POS Terminal 36.0%0.02 0.01 0.0
Miscellaneous Non-HVAC Motors 88.8%0.14 0.12 0.7
Miscellaneous Pool Pump 6.0%0.01 0.00 0.0
Miscellaneous Pool Heater 1.0%0.01 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.61 0.61 3.4
Total 13.93 78.1
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
752
Energy Efficiency Potential Study
Applied Energy Group, Inc. 99
Table A-11 School Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 24.5%2.56 0.63 7.5
Cooling Water-Cooled Chiller 6.1%3.79 0.23 2.8
Cooling RTU 11.9%1.66 0.20 2.4
Cooling Room AC 5.0%1.70 0.09 1.0
Cooling Air-Source Heat Pump 8.6%1.65 0.14 1.7
Cooling Geothermal Heat Pump 3.9%1.01 0.04 0.5
Heating Electric Furnace 3.7%9.39 0.35 4.2
Heating Electric Room Heat 1.8%8.94 0.16 1.9
Heating Air-Source Heat Pump 8.6%6.66 0.57 6.8
Heating Geothermal Heat Pump 3.9%5.16 0.20 2.4
Ventilation Ventilation 100.0%1.17 1.17 14.0
Water Heating Water Heater 38.1%1.63 0.62 7.4
Interior Lighting Screw-in/Hard-wire 100.0%0.55 0.55 6.6
Interior Lighting High-Bay Fixtures 100.0%0.13 0.13 1.5
Interior Lighting Linear Fluorescent 100.0%1.10 1.10 13.1
Exterior Lighting Screw-in/Hard-wire 100.0%0.00 0.00 0.1
Exterior Lighting HID 100.0%0.17 0.17 2.0
Exterior Lighting Linear Fluorescent 100.0%0.96 0.96 11.5
Refrigeration Walk-in Refrigerator/Freezer 19.0%0.51 0.10 1.2
Refrigeration Reach-in Refrigerator/Freezer 33.0%0.23 0.08 0.9
Refrigeration Glass Door Display 19.7%0.12 0.02 0.3
Refrigeration Open Display Case 11.9%0.69 0.08 1.0
Refrigeration Icemaker 69.7%0.38 0.27 3.2
Refrigeration Vending Machine 21.8%0.18 0.04 0.5
Food Preparation Oven 34.0%0.58 0.20 2.3
Food Preparation Fryer 4.0%0.84 0.03 0.4
Food Preparation Dishwasher 29.0%1.15 0.33 4.0
Food Preparation Steamer 4.0%0.84 0.03 0.4
Food Preparation Hot Food Container 21.0%0.16 0.03 0.4
Office Equipment Desktop Computer 100.0%0.45 0.45 5.4
Office Equipment Laptop 100.0%0.03 0.03 0.3
Office Equipment Server 100.0%0.11 0.11 1.3
Office Equipment Monitor 100.0%0.08 0.08 1.0
Office Equipment Printer/Copier/Fax 100.0%0.05 0.05 0.6
Office Equipment POS Terminal 36.0%0.01 0.01 0.1
Miscellaneous Non-HVAC Motors 43.7%0.11 0.05 0.6
Miscellaneous Pool Pump 6.0%0.01 0.00 0.0
Miscellaneous Pool Heater 1.0%0.01 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.55 0.55 6.6
Total 9.85 117.5
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
753
Energy Efficiency Potential Study
Applied Energy Group, Inc. 100
Table A-12 Health Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 16.5%5.62 0.93 8.7
Cooling Water-Cooled Chiller 65.9%7.38 4.86 45.4
Cooling RTU 10.8%5.40 0.58 5.5
Cooling Room AC 0.4%5.55 0.02 0.2
Cooling Air-Source Heat Pump 1.1%5.39 0.06 0.5
Cooling Geothermal Heat Pump 0.4%3.28 0.01 0.1
Heating Electric Furnace 0.3%13.34 0.04 0.3
Heating Electric Room Heat 9.3%12.71 1.18 11.1
Heating Air-Source Heat Pump 1.1%9.12 0.10 0.9
Heating Geothermal Heat Pump 0.4%6.69 0.02 0.2
Ventilation Ventilation 100.0%4.96 4.96 46.3
Water Heating Water Heater 22.3%4.64 1.03 9.7
Interior Lighting Screw-in/Hard-wire 100.0%1.54 1.54 14.3
Interior Lighting High-Bay Fixtures 100.0%0.35 0.35 3.3
Interior Lighting Linear Fluorescent 100.0%3.92 3.92 36.6
Exterior Lighting Screw-in/Hard-wire 100.0%0.04 0.04 0.4
Exterior Lighting HID 100.0%0.46 0.46 4.3
Exterior Lighting Linear Fluorescent 100.0%0.16 0.16 1.5
Refrigeration Walk-in Refrigerator/Freezer 33.0%1.05 0.35 3.2
Refrigeration Reach-in Refrigerator/Freezer 50.0%0.23 0.12 1.1
Refrigeration Glass Door Display 8.6%0.24 0.02 0.2
Refrigeration Open Display Case 6.7%1.43 0.10 0.9
Refrigeration Icemaker 21.1%0.79 0.17 1.6
Refrigeration Vending Machine 27.9%0.37 0.10 1.0
Food Preparation Oven 13.0%2.58 0.34 3.1
Food Preparation Fryer 10.0%3.73 0.37 3.5
Food Preparation Dishwasher 25.0%5.14 1.28 12.0
Food Preparation Steamer 10.0%3.77 0.38 3.5
Food Preparation Hot Food Container 10.0%0.70 0.07 0.7
Office Equipment Desktop Computer 100.0%0.91 0.91 8.5
Office Equipment Laptop 100.0%0.06 0.06 0.5
Office Equipment Server 100.0%0.11 0.11 1.0
Office Equipment Monitor 100.0%0.16 0.16 1.5
Office Equipment Printer/Copier/Fax 100.0%0.10 0.10 0.9
Office Equipment POS Terminal 100.0%0.07 0.07 0.7
Miscellaneous Non-HVAC Motors 74.1%0.37 0.27 2.6
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%3.84 3.84 35.8
Total 29.06 271.4
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
754
Energy Efficiency Potential Study
Applied Energy Group, Inc. 101
Table A-13 Lodging Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 4.4%1.18 0.05 0.4
Cooling Water-Cooled Chiller 17.8%1.54 0.27 1.9
Cooling RTU 8.1%2.62 0.21 1.5
Cooling Room AC 27.5%2.69 0.74 5.1
Cooling Air-Source Heat Pump 17.6%2.62 0.46 3.2
Cooling Geothermal Heat Pump 2.5%2.26 0.06 0.4
Heating Electric Furnace 60.2%4.21 2.54 17.6
Heating Electric Room Heat 3.6%4.01 0.15 1.0
Heating Air-Source Heat Pump 17.6%3.85 0.68 4.7
Heating Geothermal Heat Pump 2.5%2.50 0.06 0.4
Ventilation Ventilation 100.0%1.42 1.42 9.9
Water Heating Water Heater 31.5%4.81 1.51 10.5
Interior Lighting Screw-in/Hard-wire 100.0%3.31 3.31 23.0
Interior Lighting High-Bay Fixtures 100.0%0.27 0.27 1.8
Interior Lighting Linear Fluorescent 100.0%0.87 0.87 6.0
Exterior Lighting Screw-in/Hard-wire 100.0%0.13 0.13 0.9
Exterior Lighting HID 100.0%0.51 0.51 3.6
Exterior Lighting Linear Fluorescent 100.0%0.03 0.03 0.2
Refrigeration Walk-in Refrigerator/Freezer 3.0%0.82 0.02 0.2
Refrigeration Reach-in Refrigerator/Freezer 19.0%0.18 0.03 0.2
Refrigeration Glass Door Display 40.0%0.19 0.08 0.5
Refrigeration Open Display Case 0.0%1.12 0.00 0.0
Refrigeration Icemaker 88.9%0.62 0.55 3.8
Refrigeration Vending Machine 57.8%0.29 0.17 1.2
Food Preparation Oven 24.0%0.83 0.20 1.4
Food Preparation Fryer 4.0%1.20 0.05 0.3
Food Preparation Dishwasher 39.0%0.82 0.32 2.2
Food Preparation Steamer 4.0%0.60 0.02 0.2
Food Preparation Hot Food Container 10.0%0.11 0.01 0.1
Office Equipment Desktop Computer 100.0%0.20 0.20 1.4
Office Equipment Laptop 100.0%0.03 0.03 0.2
Office Equipment Server 100.0%0.12 0.12 0.8
Office Equipment Monitor 100.0%0.04 0.04 0.2
Office Equipment Printer/Copier/Fax 100.0%0.02 0.02 0.2
Office Equipment POS Terminal 58.0%0.03 0.02 0.1
Miscellaneous Non-HVAC Motors 91.3%0.15 0.14 1.0
Miscellaneous Pool Pump 76.0%0.02 0.02 0.1
Miscellaneous Pool Heater 27.0%0.03 0.01 0.1
Miscellaneous Other Miscellaneous 100.0%0.76 0.76 5.3
Total 16.08 111.7
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
755
Energy Efficiency Potential Study
Applied Energy Group, Inc. 102
Table A-14 Warehouse Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 13.0%4.14 0.54 7.4
Cooling Water-Cooled Chiller 1.4%4.74 0.07 0.9
Cooling RTU 17.0%4.07 0.69 9.5
Cooling Room AC 1.1%4.18 0.05 0.6
Cooling Air-Source Heat Pump 1.6%4.07 0.07 0.9
Cooling Geothermal Heat Pump 0.0%2.48 0.00 0.0
Heating Electric Furnace 4.9%7.90 0.39 5.3
Heating Electric Room Heat 1.7%7.53 0.13 1.8
Heating Air-Source Heat Pump 1.6%5.91 0.09 1.3
Heating Geothermal Heat Pump 0.0%4.50 0.00 0.0
Ventilation Ventilation 100.0%0.60 0.60 8.2
Water Heating Water Heater 76.9%0.61 0.47 6.4
Interior Lighting Screw-in/Hard-wire 100.0%0.23 0.23 3.2
Interior Lighting High-Bay Fixtures 100.0%0.96 0.96 13.2
Interior Lighting Linear Fluorescent 100.0%1.12 1.12 15.4
Exterior Lighting Screw-in/Hard-wire 100.0%0.18 0.18 2.5
Exterior Lighting HID 100.0%0.15 0.15 2.1
Exterior Lighting Linear Fluorescent 100.0%0.15 0.15 2.1
Refrigeration Walk-in Refrigerator/Freezer 1.1%4.49 0.05 0.7
Refrigeration Reach-in Refrigerator/Freezer 2.0%1.01 0.02 0.3
Refrigeration Glass Door Display 0.0%1.03 0.00 0.0
Refrigeration Open Display Case 0.0%6.13 0.00 0.0
Refrigeration Icemaker 8.3%1.69 0.14 1.9
Refrigeration Vending Machine 6.9%0.80 0.05 0.7
Food Preparation Oven 0.0%0.28 0.00 0.0
Food Preparation Fryer 0.0%0.41 0.00 0.0
Food Preparation Dishwasher 2.0%0.56 0.01 0.2
Food Preparation Steamer 0.0%0.41 0.00 0.0
Food Preparation Hot Food Container 0.0%0.08 0.00 0.0
Office Equipment Desktop Computer 100.0%0.23 0.23 3.2
Office Equipment Laptop 100.0%0.03 0.03 0.4
Office Equipment Server 89.0%0.27 0.24 3.4
Office Equipment Monitor 100.0%0.04 0.04 0.6
Office Equipment Printer/Copier/Fax 100.0%0.03 0.03 0.4
Office Equipment POS Terminal 77.0%0.07 0.06 0.8
Miscellaneous Non-HVAC Motors 49.9%0.14 0.07 1.0
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.65 0.65 8.9
Total 7.50 102.9
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
756
Energy Efficiency Potential Study
Applied Energy Group, Inc. 103
Table A-15 Miscellaneous Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 4.2%3.85 0.16 5.3
Cooling Water-Cooled Chiller 16.7%4.36 0.73 24.0
Cooling RTU 34.5%3.18 1.10 36.3
Cooling Room AC 4.9%3.27 0.16 5.3
Cooling Air-Source Heat Pump 6.2%3.18 0.20 6.5
Cooling Geothermal Heat Pump 1.1%1.94 0.02 0.7
Heating Electric Furnace 15.2%8.97 1.36 45.0
Heating Electric Room Heat 8.4%8.54 0.72 23.7
Heating Air-Source Heat Pump 6.2%7.44 0.46 15.1
Heating Geothermal Heat Pump 1.1%5.77 0.07 2.2
Ventilation Ventilation 100.0%1.39 1.39 45.9
Water Heating Water Heater 51.3%2.64 1.35 44.8
Interior Lighting Screw-in/Hard-wire 100.0%0.75 0.75 24.9
Interior Lighting High-Bay Fixtures 100.0%0.25 0.25 8.1
Interior Lighting Linear Fluorescent 100.0%1.42 1.42 46.9
Exterior Lighting Screw-in/Hard-wire 100.0%0.43 0.43 14.2
Exterior Lighting HID 100.0%0.91 0.91 30.0
Exterior Lighting Linear Fluorescent 100.0%0.07 0.07 2.3
Refrigeration Walk-in Refrigerator/Freezer 9.0%0.98 0.09 2.9
Refrigeration Reach-in Refrigerator/Freezer 0.0%0.22 0.00 0.0
Refrigeration Glass Door Display 15.0%0.23 0.03 1.1
Refrigeration Open Display Case 0.0%1.34 0.00 0.0
Refrigeration Icemaker 41.6%0.37 0.15 5.1
Refrigeration Vending Machine 28.6%0.35 0.10 3.3
Food Preparation Oven 28.0%0.24 0.07 2.3
Food Preparation Fryer 4.0%0.35 0.01 0.5
Food Preparation Dishwasher 31.0%0.49 0.15 5.0
Food Preparation Steamer 4.0%0.36 0.01 0.5
Food Preparation Hot Food Container 7.0%0.07 0.00 0.2
Office Equipment Desktop Computer 100.0%0.37 0.37 12.4
Office Equipment Laptop 100.0%0.06 0.06 1.9
Office Equipment Server 66.0%0.22 0.15 4.8
Office Equipment Monitor 100.0%0.07 0.07 2.2
Office Equipment Printer/Copier/Fax 100.0%0.04 0.04 1.4
Office Equipment POS Terminal 28.0%0.06 0.02 0.5
Miscellaneous Non-HVAC Motors 59.9%0.15 0.09 3.0
Miscellaneous Pool Pump 4.0%0.02 0.00 0.0
Miscellaneous Pool Heater 1.0%0.03 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.79 0.79 26.2
Total 13.75 454.6
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
757
Energy Efficiency Potential Study
Applied Energy Group, Inc. 104
Table A-16 Industrial Electric Market Profile, Washington

EUI Intensity Usage
(kWh)(kWh/Employee)(GWh)
Cooling Air-Cooled Chiller 13.0% 8,256 1,072 17.40
Cooling Water-Cooled Chiller 1.4% 9,464 137 2.22
Cooling RTU 17.0% 8,121 1,383 22.44
Cooling Room AC 1.1% 8,347 94 1.53
Cooling Air-Source Heat Pump 1.6% 8,118 130 2.12
Cooling Geothermal Heat Pump 0.0% 5,414 0 0.00
Heating Electric Furnace 4.9% 15,767 769 12.47
Heating Electric Room Heat 1.7% 15,016 258 4.18
Heating Air-Source Heat Pump 1.6% 11,786 189 3.07
Heating Geothermal Heat Pump 0.0% 7,861 0 0.00
Ventilation Ventilation 100.0% 1,190 1,190 19.30
Interior Lighting Screw-in/Hard-wire 100.0%302 302 4.90
Interior Lighting High-Bay Fixtures 100.0% 1,256 1,256 20.38
Interior Lighting Linear Fluorescent 100.0% 1,466 1,466 23.78
Exterior Lighting Screw-in/Hard-wire 100.0%238 238 3.86
Exterior Lighting HID 100.0%196 196 3.19
Exterior Lighting Linear Fluorescent 100.0%198 198 3.21
Motors Pumps 100.0% 5,352 5,352 86.83
Motors Fans & Blowers 100.0% 4,189 4,189 67.97
Motors Compressed Air 100.0% 3,345 3,345 54.27
Motors Conveyors 100.0% 15,101 15,101 245.01
Motors Other Motors 100.0% 2,341 2,341 37.99
Process Process Heating 100.0% 6,115 6,115 99.21
Process Process Cooling 100.0% 2,005 2,005 32.53
Process Process Refrigeration 100.0% 2,005 2,005 32.53
Process Process Electro-Chemical 100.0% 3,972 3,972 64.45
Process Process Other 100.0% 1,345 1,345 21.83
Miscellaneous Miscellaneous 100.0% 2,197 2,197 35.64
56,846 922.32
Average Market Profiles - Electricity
End Use Technology Saturation
Total
2015 Electric IRP Appendix C
758
Energy Efficiency Potential Study
Applied Energy Group, Inc. 105
Table A-17 Residential Single Family Electric Market Profile, Idaho

UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 38.2% 1,424 544 36
Cooling Room AC 12.3%518 64 4
Cooling Air-Source Heat Pump 7.0% 1,491 104 7
Cooling Geothermal Heat Pump 0.0% 1,317 0 0
Cooling Evaporative AC 1.6% 1,027 16 1
Space Heating Electric Room Heat 9.8% 14,299 1,397 91
Space Heating Electric Furnace 7.4% 16,280 1,212 79
Space Heating Air-Source Heat Pump 7.0% 12,257 852 56
Space Heating Geothermal Heat Pump 0.0% 5,402 0 0
Water Heating Water Heater (<= 55 Gal)43.1% 3,530 1,523 100
Water Heating Water Heater (55 to 75 Gal)5.3% 3,712 195 13
Water Heating Water Heater (> 75 Gal)0.5% 3,890 18 1
Interior Lighting Screw-in/Hard-wire 100.0% 1,267 1,267 83
Interior Lighting Linear Fluorescent 100.0%179 179 12
Interior Lighting Specialty Lighting 100.0%350 350 23
Exterior Lighting Screw-in/Hard-wire 100.0%491 491 32
Appliances Clothes Washer 95.5%103 98 6
Appliances Clothes Dryer 65.6%802 527 34
Appliances Dishwasher 80.1%443 355 23
Appliances Refrigerator 100.0%826 826 54
Appliances Freezer 66.3%660 438 29
Appliances Second Refrigerator 29.4%962 283 18
Appliances Stove 58.4%474 277 18
Appliances Microwave 93.1%138 129 8
Electronics Personal Computers 63.3%208 131 9
Electronics Monitor 77.3%88 68 4
Electronics Laptops 85.7%55 47 3
Electronics TVs 199.0%245 487 32
Electronics Printer/Fax/Copier 76.9%63 49 3
Electronics Set top Boxes/DVRs 105.8%124 131 9
Electronics Devices and Gadgets 100.0%54 54 3
Miscellaneous Pool Pump 2.6% 2,350 61 4
Miscellaneous Pool Heater 0.6% 3,763 24 2
Miscellaneous Furnace Fan 70.2%279 196 13
Miscellaneous Well pump 20.0%600 120 8
Miscellaneous Miscellaneous 100.0%389 389 25
12,902 843
Average Market Profiles - Electricity
Total
End Use Technology Saturation
2015 Electric IRP Appendix C
759
Energy Efficiency Potential Study
Applied Energy Group, Inc. 106
Table A-18 Residential Multifamily Electric Market Profile, Idaho

UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 22.3%373 83 0
Cooling Room AC 31.6%296 94 0
Cooling Air-Source Heat Pump 1.9%373 7 0
Cooling Geothermal Heat Pump 0.0%329 0 0
Cooling Evaporative AC 1.9%307 6 0
Space Heating Electric Room Heat 59.5% 2,937 1,748 9
Space Heating Electric Furnace 16.7% 3,343 557 3
Space Heating Air-Source Heat Pump 1.9% 1,831 34 0
Space Heating Geothermal Heat Pump 0.0%807 0 0
Water Heating Water Heater (<= 55 Gal)57.4% 2,205 1,266 7
Water Heating Water Heater (55 to 75 Gal)7.6% 2,319 176 1
Water Heating Water Heater (> 75 Gal)0.0% 2,430 0 0
Interior Lighting Screw-in/Hard-wire 100.0%639 639 3
Interior Lighting Linear Fluorescent 100.0%40 40 0
Interior Lighting Specialty Lighting 100.0%37 37 0
Exterior Lighting Screw-in/Hard-wire 100.0% 0 0 0
Appliances Clothes Washer 59.6%96 57 0
Appliances Clothes Dryer 42.3%593 251 1
Appliances Dishwasher 73.1%413 302 2
Appliances Refrigerator 100.0%771 771 4
Appliances Freezer 23.1%620 143 1
Appliances Second Refrigerator 3.0%898 27 0
Appliances Stove 69.2%357 247 1
Appliances Microwave 86.5%129 112 1
Electronics Personal Computers 46.3%194 90 0
Electronics Monitor 56.6%82 47 0
Electronics Laptops 74.1%52 38 0
Electronics TVs 140.7%269 379 2
Electronics Printer/Fax/Copier 51.9%59 31 0
Electronics Set top Boxes/DVRs 64.8%116 75 0
Electronics Devices and Gadgets 100.0%50 50 0
Miscellaneous Pool Pump 0.0% 2,197 0 0
Miscellaneous Pool Heater 0.0% 3,517 0 0
Miscellaneous Furnace Fan 33.3%98 33 0
Miscellaneous Well pump 0.0%556 0 0
Miscellaneous Miscellaneous 100.0%395 395 2
7,733 41
Average Market Profiles - Electricity
Total
End Use Technology Saturation
2015 Electric IRP Appendix C
760
Energy Efficiency Potential Study
Applied Energy Group, Inc. 107
Table A-19 Residential Manufactured Home Electric Market Profile, Idaho

UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 35.9%500 180 1
Cooling Room AC 20.5%395 81 0
Cooling Air-Source Heat Pump 5.1%500 26 0
Cooling Geothermal Heat Pump 0.0%441 0 0
Cooling Evaporative AC 0.0%319 0 0
Space Heating Electric Room Heat 10.7% 6,758 724 4
Space Heating Electric Furnace 42.9% 7,694 3,297 16
Space Heating Air-Source Heat Pump 5.1% 6,330 325 2
Space Heating Geothermal Heat Pump 0.0% 2,900 0 0
Water Heating Water Heater (<= 55 Gal)66.2% 2,370 1,570 8
Water Heating Water Heater (55 to 75 Gal)8.8% 2,492 219 1
Water Heating Water Heater (> 75 Gal)0.0% 2,612 0 0
Interior Lighting Screw-in/Hard-wire 100.0%750 750 4
Interior Lighting Linear Fluorescent 100.0%61 61 0
Interior Lighting Specialty Lighting 100.0%158 158 1
Exterior Lighting Screw-in/Hard-wire 100.0%184 184 1
Appliances Clothes Washer 94.9%91 87 0
Appliances Clothes Dryer 82.1%888 729 4
Appliances Dishwasher 74.4%394 293 1
Appliances Refrigerator 100.0%732 732 4
Appliances Freezer 48.7%586 286 1
Appliances Second Refrigerator 21.0%852 179 1
Appliances Stove 82.1%510 419 2
Appliances Microwave 92.3%123 113 1
Electronics Personal Computers 46.4%184 86 0
Electronics Monitor 56.8%78 44 0
Electronics Laptops 50.0%49 25 0
Electronics TVs 110.7%273 302 1
Electronics Printer/Fax/Copier 42.9%56 24 0
Electronics Set top Boxes/DVRs 89.3%110 99 0
Electronics Devices and Gadgets 100.0%48 48 0
Miscellaneous Pool Pump 0.0% 2,087 0 0
Miscellaneous Pool Heater 0.0% 3,341 0 0
Miscellaneous Furnace Fan 71.4%205 146 1
Miscellaneous Well pump 0.0%428 0 0
Miscellaneous Miscellaneous 100.0%415 415 2
11,599 56
Average Market Profiles - Electricity
Total
End Use Technology Saturation
2015 Electric IRP Appendix C
761
Energy Efficiency Potential Study
Applied Energy Group, Inc. 108
Table A-20 Residential Low Income Electric Market Profile, Idaho

UEC Intensity Usage
(kWh)(kWh/HH)(GWh)
Cooling Central AC 25.1%481 121 4
Cooling Room AC 29.0%351 102 3
Cooling Air-Source Heat Pump 2.6%485 13 0
Cooling Geothermal Heat Pump 0.0%428 0 0
Cooling Evaporative AC 1.6%363 6 0
Space Heating Electric Room Heat 50.0% 3,842 1,920 61
Space Heating Electric Furnace 19.6% 4,374 859 28
Space Heating Air-Source Heat Pump 2.6% 2,951 77 2
Space Heating Geothermal Heat Pump 0.0% 1,319 0 0
Water Heating Water Heater (<= 55 Gal)57.7% 2,155 1,244 40
Water Heating Water Heater (55 to 75 Gal)7.6% 2,266 173 6
Water Heating Water Heater (> 75 Gal)0.0% 2,374 1 0
Interior Lighting Screw-in/Hard-wire 100.0%692 692 22
Interior Lighting Linear Fluorescent 100.0%51 51 2
Interior Lighting Specialty Lighting 100.0%72 72 2
Exterior Lighting Screw-in/Hard-wire 100.0%54 54 2
Appliances Clothes Washer 66.5%90 60 2
Appliances Clothes Dryer 49.1%610 299 10
Appliances Dishwasher 73.7%389 286 9
Appliances Refrigerator 100.0%725 725 23
Appliances Freezer 29.1%583 170 5
Appliances Second Refrigerator 7.0%844 59 2
Appliances Stove 70.3%363 255 8
Appliances Microwave 87.7%121 106 3
Electronics Personal Computers 47.3%182 86 3
Electronics Monitor 57.9%77 45 1
Electronics Laptops 71.5%49 35 1
Electronics TVs 140.2%253 354 11
Electronics Printer/Fax/Copier 52.1%55 29 1
Electronics Set top Boxes/DVRs 70.6%109 77 2
Electronics Devices and Gadgets 100.0%47 47 2
Miscellaneous Pool Pump 0.2% 2,065 3 0
Miscellaneous Pool Heater 0.0% 3,306 1 0
Miscellaneous Furnace Fan 40.7%123 50 2
Miscellaneous Well pump 1.2%510 6 0
Miscellaneous Miscellaneous 100.0%272 272 9
8,349 267
Average Market Profiles - Electricity
Total
End Use Technology Saturation
2015 Electric IRP Appendix C
762
Energy Efficiency Potential Study
Applied Energy Group, Inc. 109
Table A-21 Small Office Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 0.5%4.68 0.02 0.2
Cooling Water-Cooled Chiller 0.0%5.30 0.00 0.0
Cooling RTU 77.9%3.86 3.01 26.2
Cooling Room AC 3.6%3.97 0.14 1.3
Cooling Air-Source Heat Pump 8.2%3.86 0.32 2.7
Cooling Geothermal Heat Pump 3.2%2.36 0.08 0.7
Heating Electric Furnace 16.0%6.76 1.08 9.4
Heating Electric Room Heat 14.5%6.44 0.93 8.1
Heating Air-Source Heat Pump 8.2%5.71 0.47 4.1
Heating Geothermal Heat Pump 3.2%4.34 0.14 1.2
Ventilation Ventilation 100.0%1.40 1.40 12.1
Water Heating Water Heater 69.8%1.05 0.73 6.4
Interior Lighting Screw-in/Hard-wire 100.0%0.62 0.62 5.4
Interior Lighting High-Bay Fixtures 100.0%0.34 0.34 3.0
Interior Lighting Linear Fluorescent 100.0%2.05 2.05 17.8
Exterior Lighting Screw-in/Hard-wire 100.0%0.14 0.14 1.2
Exterior Lighting HID 100.0%0.19 0.19 1.7
Exterior Lighting Linear Fluorescent 100.0%0.07 0.07 0.6
Refrigeration Walk-in Refrigerator/Freezer 0.2%2.34 0.01 0.0
Refrigeration Reach-in Refrigerator/Freezer 1.6%0.52 0.01 0.1
Refrigeration Glass Door Display 0.5%0.54 0.00 0.0
Refrigeration Open Display Case 0.5%3.19 0.01 0.1
Refrigeration Icemaker 0.5%0.88 0.00 0.0
Refrigeration Vending Machine 0.2%0.41 0.00 0.0
Food Preparation Oven 0.8%1.50 0.01 0.1
Food Preparation Fryer 0.1%2.17 0.00 0.0
Food Preparation Dishwasher 1.0%2.99 0.03 0.3
Food Preparation Steamer 0.1%2.19 0.00 0.0
Food Preparation Hot Food Container 0.1%0.41 0.00 0.0
Office Equipment Desktop Computer 100.0%1.55 1.55 13.5
Office Equipment Laptop 100.0%0.24 0.24 2.1
Office Equipment Server 100.0%0.46 0.46 4.0
Office Equipment Monitor 100.0%0.27 0.27 2.4
Office Equipment Printer/Copier/Fax 100.0%0.21 0.21 1.8
Office Equipment POS Terminal 40.0%0.12 0.05 0.4
Miscellaneous Non-HVAC Motors 22.0%0.19 0.04 0.4
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.82 0.82 7.1
Total 15.44 134.4
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
763
Energy Efficiency Potential Study
Applied Energy Group, Inc. 110
Table A-22 Large Office Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 23.5%2.74 0.64 0.6
Cooling Water-Cooled Chiller 23.5%3.03 0.71 0.7
Cooling RTU 33.4%3.35 1.12 1.1
Cooling Room AC 0.6%3.44 0.02 0.0
Cooling Air-Source Heat Pump 7.5%3.35 0.25 0.2
Cooling Geothermal Heat Pump 6.5%2.04 0.13 0.1
Heating Electric Furnace 15.7%4.99 0.78 0.8
Heating Electric Room Heat 14.3%4.75 0.68 0.7
Heating Air-Source Heat Pump 7.5%4.57 0.34 0.3
Heating Geothermal Heat Pump 6.5%3.62 0.24 0.2
Ventilation Ventilation 100.0%2.96 2.96 2.9
Water Heating Water Heater 68.0%0.99 0.67 0.6
Interior Lighting Screw-in/Hard-wire 100.0%0.62 0.62 0.6
Interior Lighting High-Bay Fixtures 100.0%0.37 0.37 0.4
Interior Lighting Linear Fluorescent 100.0%2.74 2.74 2.7
Exterior Lighting Screw-in/Hard-wire 100.0%0.14 0.14 0.1
Exterior Lighting HID 100.0%0.37 0.37 0.4
Exterior Lighting Linear Fluorescent 100.0%0.23 0.23 0.2
Refrigeration Walk-in Refrigerator/Freezer 2.0%1.62 0.03 0.0
Refrigeration Reach-in Refrigerator/Freezer 14.0%0.36 0.05 0.0
Refrigeration Glass Door Display 4.0%0.37 0.01 0.0
Refrigeration Open Display Case 4.0%2.22 0.09 0.1
Refrigeration Icemaker 4.0%0.61 0.02 0.0
Refrigeration Vending Machine 2.1%0.29 0.01 0.0
Food Preparation Oven 10.0%0.76 0.08 0.1
Food Preparation Fryer 1.0%1.10 0.01 0.0
Food Preparation Dishwasher 12.0%1.52 0.18 0.2
Food Preparation Steamer 1.0%1.11 0.01 0.0
Food Preparation Hot Food Container 1.0%0.21 0.00 0.0
Office Equipment Desktop Computer 100.0%1.96 1.96 1.9
Office Equipment Laptop 100.0%0.30 0.30 0.3
Office Equipment Server 100.0%0.19 0.19 0.2
Office Equipment Monitor 100.0%0.35 0.35 0.3
Office Equipment Printer/Copier/Fax 100.0%0.18 0.18 0.2
Office Equipment POS Terminal 40.0%0.03 0.01 0.0
Miscellaneous Non-HVAC Motors 89.6%0.21 0.19 0.2
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.83 0.83 0.8
Total 17.54 17.0
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
764
Energy Efficiency Potential Study
Applied Energy Group, Inc. 111
Table A-23 Restaurant Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 0.3%3.65 0.01 0.0
Cooling Water-Cooled Chiller 0.0%4.03 0.00 0.0
Cooling RTU 76.3%4.58 3.49 1.0
Cooling Room AC 6.6%4.71 0.31 0.1
Cooling Air-Source Heat Pump 6.6%4.58 0.30 0.1
Cooling Geothermal Heat Pump 3.3%2.79 0.09 0.0
Heating Electric Furnace 5.1%6.99 0.36 0.1
Heating Electric Room Heat 0.1%6.66 0.01 0.0
Heating Air-Source Heat Pump 6.6%4.94 0.32 0.1
Heating Geothermal Heat Pump 3.3%3.48 0.11 0.0
Ventilation Ventilation 100.0%2.48 2.48 0.7
Water Heating Water Heater 35.2%8.81 3.10 0.9
Interior Lighting Screw-in/Hard-wire 100.0%2.09 2.09 0.6
Interior Lighting High-Bay Fixtures 100.0%0.40 0.40 0.1
Interior Lighting Linear Fluorescent 100.0%3.62 3.62 1.1
Exterior Lighting Screw-in/Hard-wire 100.0%0.23 0.23 0.1
Exterior Lighting HID 100.0%1.61 1.61 0.5
Exterior Lighting Linear Fluorescent 100.0%0.47 0.47 0.1
Refrigeration Walk-in Refrigerator/Freezer 74.0%6.56 4.85 1.4
Refrigeration Reach-in Refrigerator/Freezer 7.0%2.94 0.21 0.1
Refrigeration Glass Door Display 77.6%1.51 1.17 0.3
Refrigeration Open Display Case 26.0%8.95 2.33 0.7
Refrigeration Icemaker 75.9%2.47 1.88 0.5
Refrigeration Vending Machine 0.0%1.16 0.00 0.0
Food Preparation Oven 16.0%9.79 1.57 0.5
Food Preparation Fryer 14.0%14.16 1.98 0.6
Food Preparation Dishwasher 48.0%9.75 4.68 1.4
Food Preparation Steamer 14.0%7.15 1.00 0.3
Food Preparation Hot Food Container 31.0%1.33 0.41 0.1
Office Equipment Desktop Computer 100.0%0.29 0.29 0.1
Office Equipment Laptop 100.0%0.04 0.04 0.0
Office Equipment Server 50.0%0.34 0.17 0.0
Office Equipment Monitor 100.0%0.05 0.05 0.0
Office Equipment Printer/Copier/Fax 100.0%0.06 0.06 0.0
Office Equipment POS Terminal 100.0%0.09 0.09 0.0
Miscellaneous Non-HVAC Motors 20.0%0.56 0.11 0.0
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%2.52 2.52 0.7
Total 42.40 12.4
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
765
Energy Efficiency Potential Study
Applied Energy Group, Inc. 112
Table A-24 Retail Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 9.5%2.80 0.27 3.2
Cooling Water-Cooled Chiller 2.4%3.17 0.08 0.9
Cooling RTU 54.2%2.31 1.25 15.2
Cooling Room AC 2.8%2.53 0.07 0.9
Cooling Air-Source Heat Pump 1.7%2.31 0.04 0.5
Cooling Geothermal Heat Pump 1.4%1.41 0.02 0.2
Heating Electric Furnace 5.8%4.81 0.28 3.4
Heating Electric Room Heat 2.1%4.58 0.10 1.2
Heating Air-Source Heat Pump 1.7%3.85 0.07 0.8
Heating Geothermal Heat Pump 1.4%2.62 0.04 0.4
Ventilation Ventilation 100.0%0.98 0.98 11.9
Water Heating Water Heater 63.0%0.79 0.50 6.1
Interior Lighting Screw-in/Hard-wire 100.0%0.85 0.85 10.3
Interior Lighting High-Bay Fixtures 100.0%1.02 1.02 12.4
Interior Lighting Linear Fluorescent 100.0%3.43 3.43 41.7
Exterior Lighting Screw-in/Hard-wire 100.0%0.36 0.36 4.3
Exterior Lighting HID 100.0%1.30 1.30 15.8
Exterior Lighting Linear Fluorescent 100.0%0.87 0.87 10.6
Refrigeration Walk-in Refrigerator/Freezer 2.0%2.04 0.04 0.5
Refrigeration Reach-in Refrigerator/Freezer 0.0%0.46 0.00 0.0
Refrigeration Glass Door Display 16.3%0.47 0.08 0.9
Refrigeration Open Display Case 14.0%2.79 0.39 4.7
Refrigeration Icemaker 7.1%0.77 0.05 0.7
Refrigeration Vending Machine 22.8%0.36 0.08 1.0
Food Preparation Oven 8.0%2.43 0.19 2.4
Food Preparation Fryer 1.6%3.51 0.06 0.7
Food Preparation Dishwasher 2.0%4.84 0.10 1.2
Food Preparation Steamer 1.6%3.55 0.06 0.7
Food Preparation Hot Food Container 1.0%0.66 0.01 0.1
Office Equipment Desktop Computer 100.0%0.34 0.34 4.1
Office Equipment Laptop 100.0%0.05 0.05 0.6
Office Equipment Server 82.0%0.06 0.05 0.6
Office Equipment Monitor 100.0%0.06 0.06 0.7
Office Equipment Printer/Copier/Fax 100.0%0.05 0.05 0.6
Office Equipment POS Terminal 100.0%0.01 0.01 0.2
Miscellaneous Non-HVAC Motors 40.2%0.16 0.07 0.8
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.61 0.61 7.5
Total 13.80 167.6
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
766
Energy Efficiency Potential Study
Applied Energy Group, Inc. 113
Table A-25 Grocery Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 5.3%5.20 0.28 0.5
Cooling Water-Cooled Chiller 0.0%5.89 0.00 0.0
Cooling RTU 69.6%4.30 2.99 5.8
Cooling Room AC 0.0%4.42 0.00 0.0
Cooling Air-Source Heat Pump 3.1%3.80 0.12 0.2
Cooling Geothermal Heat Pump 0.0%1.60 0.00 0.0
Heating Electric Furnace 15.4%5.62 0.86 1.7
Heating Electric Room Heat 1.5%5.35 0.08 0.2
Heating Air-Source Heat Pump 3.1%3.01 0.09 0.2
Heating Geothermal Heat Pump 0.0%1.93 0.00 0.0
Ventilation Ventilation 100.0%2.07 2.07 4.0
Water Heating Water Heater 38.2%2.18 0.83 1.6
Interior Lighting Screw-in/Hard-wire 100.0%1.93 1.93 3.7
Interior Lighting High-Bay Fixtures 100.0%1.70 1.70 3.3
Interior Lighting Linear Fluorescent 100.0%5.83 5.83 11.3
Exterior Lighting Screw-in/Hard-wire 100.0%0.19 0.19 0.4
Exterior Lighting HID 100.0%1.16 1.16 2.2
Exterior Lighting Linear Fluorescent 100.0%0.48 0.48 0.9
Refrigeration Walk-in Refrigerator/Freezer 16.0%5.13 0.82 1.6
Refrigeration Reach-in Refrigerator/Freezer 83.1%0.33 0.27 0.5
Refrigeration Glass Door Display 95.6%3.37 3.23 6.3
Refrigeration Open Display Case 95.6%19.99 19.12 37.1
Refrigeration Icemaker 66.6%0.28 0.18 0.4
Refrigeration Vending Machine 36.5%0.26 0.09 0.2
Food Preparation Oven 17.0%2.44 0.42 0.8
Food Preparation Fryer 13.0%3.53 0.46 0.9
Food Preparation Dishwasher 7.0%4.86 0.34 0.7
Food Preparation Steamer 13.0%3.57 0.46 0.9
Food Preparation Hot Food Container 16.0%0.67 0.11 0.2
Office Equipment Desktop Computer 100.0%0.25 0.25 0.5
Office Equipment Laptop 64.0%0.04 0.03 0.0
Office Equipment Server 100.0%0.15 0.15 0.3
Office Equipment Monitor 100.0%0.04 0.04 0.1
Office Equipment Printer/Copier/Fax 100.0%0.03 0.03 0.1
Office Equipment POS Terminal 100.0%0.10 0.10 0.2
Miscellaneous Non-HVAC Motors 34.6%0.56 0.19 0.4
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%2.35 2.35 4.6
Total 47.25 91.7
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
767
Energy Efficiency Potential Study
Applied Energy Group, Inc. 114
Table A-26 College Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 34.8%3.14 1.09 5.7
Cooling Water-Cooled Chiller 8.7%4.66 0.41 2.1
Cooling RTU 15.6%2.04 0.32 1.7
Cooling Room AC 5.0%2.09 0.10 0.5
Cooling Air-Source Heat Pump 3.6%2.03 0.07 0.4
Cooling Geothermal Heat Pump 0.0%1.24 0.00 0.0
Heating Electric Furnace 10.5%8.67 0.91 4.8
Heating Electric Room Heat 29.7%8.26 2.45 12.8
Heating Air-Source Heat Pump 3.6%6.15 0.22 1.2
Heating Geothermal Heat Pump 0.0%4.76 0.00 0.0
Ventilation Ventilation 100.0%1.48 1.48 7.7
Water Heating Water Heater 26.3%2.02 0.53 2.8
Interior Lighting Screw-in/Hard-wire 100.0%0.83 0.83 4.3
Interior Lighting High-Bay Fixtures 100.0%0.30 0.30 1.6
Interior Lighting Linear Fluorescent 100.0%2.04 2.04 10.7
Exterior Lighting Screw-in/Hard-wire 100.0%0.01 0.01 0.0
Exterior Lighting HID 100.0%0.27 0.27 1.4
Exterior Lighting Linear Fluorescent 100.0%0.97 0.97 5.1
Refrigeration Walk-in Refrigerator/Freezer 7.7%0.29 0.02 0.1
Refrigeration Reach-in Refrigerator/Freezer 13.4%0.13 0.02 0.1
Refrigeration Glass Door Display 8.0%0.07 0.01 0.0
Refrigeration Open Display Case 4.8%0.40 0.02 0.1
Refrigeration Icemaker 28.2%0.22 0.06 0.3
Refrigeration Vending Machine 8.8%0.10 0.01 0.0
Food Preparation Oven 13.7%0.68 0.09 0.5
Food Preparation Fryer 1.6%0.98 0.02 0.1
Food Preparation Dishwasher 11.7%1.35 0.16 0.8
Food Preparation Steamer 1.6%0.99 0.02 0.1
Food Preparation Hot Food Container 8.4%0.19 0.02 0.1
Office Equipment Desktop Computer 100.0%0.51 0.51 2.7
Office Equipment Laptop 100.0%0.02 0.02 0.1
Office Equipment Server 100.0%0.06 0.06 0.3
Office Equipment Monitor 100.0%0.09 0.09 0.5
Office Equipment Printer/Copier/Fax 100.0%0.07 0.07 0.4
Office Equipment POS Terminal 36.0%0.02 0.01 0.0
Miscellaneous Non-HVAC Motors 88.8%0.14 0.12 0.6
Miscellaneous Pool Pump 6.0%0.01 0.00 0.0
Miscellaneous Pool Heater 1.0%0.01 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.61 0.61 3.2
Total 13.93 72.9
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
768
Energy Efficiency Potential Study
Applied Energy Group, Inc. 115
Table A-27 School Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 24.5%2.59 0.63 7.0
Cooling Water-Cooled Chiller 6.1%3.83 0.23 2.6
Cooling RTU 11.9%1.68 0.20 2.2
Cooling Room AC 5.0%1.72 0.09 1.0
Cooling Air-Source Heat Pump 8.6%1.67 0.14 1.6
Cooling Geothermal Heat Pump 3.9%1.02 0.04 0.4
Heating Electric Furnace 3.7%9.33 0.35 3.9
Heating Electric Room Heat 1.8%8.88 0.16 1.8
Heating Air-Source Heat Pump 8.6%6.62 0.57 6.3
Heating Geothermal Heat Pump 3.9%5.13 0.20 2.2
Ventilation Ventilation 100.0%1.17 1.17 13.0
Water Heating Water Heater 38.1%1.63 0.62 6.9
Interior Lighting Screw-in/Hard-wire 100.0%0.55 0.55 6.1
Interior Lighting High-Bay Fixtures 100.0%0.13 0.13 1.4
Interior Lighting Linear Fluorescent 100.0%1.10 1.10 12.2
Exterior Lighting Screw-in/Hard-wire 100.0%0.00 0.00 0.0
Exterior Lighting HID 100.0%0.17 0.17 1.9
Exterior Lighting Linear Fluorescent 100.0%0.96 0.96 10.7
Refrigeration Walk-in Refrigerator/Freezer 19.0%0.51 0.10 1.1
Refrigeration Reach-in Refrigerator/Freezer 33.0%0.23 0.08 0.8
Refrigeration Glass Door Display 19.7%0.12 0.02 0.3
Refrigeration Open Display Case 11.9%0.69 0.08 0.9
Refrigeration Icemaker 69.7%0.38 0.27 3.0
Refrigeration Vending Machine 21.8%0.18 0.04 0.4
Food Preparation Oven 34.0%0.58 0.20 2.2
Food Preparation Fryer 4.0%0.84 0.03 0.4
Food Preparation Dishwasher 29.0%1.15 0.33 3.7
Food Preparation Steamer 4.0%0.84 0.03 0.4
Food Preparation Hot Food Container 21.0%0.16 0.03 0.4
Office Equipment Desktop Computer 100.0%0.45 0.45 5.0
Office Equipment Laptop 100.0%0.03 0.03 0.3
Office Equipment Server 100.0%0.11 0.11 1.2
Office Equipment Monitor 100.0%0.08 0.08 0.9
Office Equipment Printer/Copier/Fax 100.0%0.05 0.05 0.6
Office Equipment POS Terminal 36.0%0.01 0.01 0.1
Miscellaneous Non-HVAC Motors 43.7%0.11 0.05 0.5
Miscellaneous Pool Pump 6.0%0.01 0.00 0.0
Miscellaneous Pool Heater 1.0%0.01 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.54 0.54 6.0
Total 9.85 109.4
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
769
Energy Efficiency Potential Study
Applied Energy Group, Inc. 116
Table A-28 Health Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 16.5%5.72 0.94 3.4
Cooling Water-Cooled Chiller 65.9%7.50 4.94 18.0
Cooling RTU 10.8%5.49 0.59 2.2
Cooling Room AC 0.4%5.64 0.02 0.1
Cooling Air-Source Heat Pump 1.1%5.48 0.06 0.2
Cooling Geothermal Heat Pump 0.4%3.34 0.01 0.0
Heating Electric Furnace 0.3%13.21 0.04 0.1
Heating Electric Room Heat 9.3%12.58 1.17 4.3
Heating Air-Source Heat Pump 1.1%9.03 0.10 0.4
Heating Geothermal Heat Pump 0.4%6.62 0.02 0.1
Ventilation Ventilation 100.0%4.96 4.96 18.1
Water Heating Water Heater 22.3%4.64 1.03 3.8
Interior Lighting Screw-in/Hard-wire 100.0%1.54 1.54 5.6
Interior Lighting High-Bay Fixtures 100.0%0.35 0.35 1.3
Interior Lighting Linear Fluorescent 100.0%3.92 3.92 14.3
Exterior Lighting Screw-in/Hard-wire 100.0%0.04 0.04 0.1
Exterior Lighting HID 100.0%0.46 0.46 1.7
Exterior Lighting Linear Fluorescent 100.0%0.16 0.16 0.6
Refrigeration Walk-in Refrigerator/Freezer 33.0%1.05 0.35 1.3
Refrigeration Reach-in Refrigerator/Freezer 50.0%0.23 0.12 0.4
Refrigeration Glass Door Display 8.6%0.24 0.02 0.1
Refrigeration Open Display Case 6.7%1.43 0.10 0.3
Refrigeration Icemaker 21.1%0.79 0.17 0.6
Refrigeration Vending Machine 27.9%0.37 0.10 0.4
Food Preparation Oven 13.0%2.58 0.34 1.2
Food Preparation Fryer 10.0%3.73 0.37 1.4
Food Preparation Dishwasher 25.0%5.14 1.28 4.7
Food Preparation Steamer 10.0%3.77 0.38 1.4
Food Preparation Hot Food Container 10.0%0.70 0.07 0.3
Office Equipment Desktop Computer 100.0%0.91 0.91 3.3
Office Equipment Laptop 100.0%0.06 0.06 0.2
Office Equipment Server 100.0%0.11 0.11 0.4
Office Equipment Monitor 100.0%0.16 0.16 0.6
Office Equipment Printer/Copier/Fax 100.0%0.10 0.10 0.4
Office Equipment POS Terminal 100.0%0.07 0.07 0.3
Miscellaneous Non-HVAC Motors 74.1%0.36 0.27 1.0
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%3.75 3.75 13.6
Total 29.06 105.8
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
770
Energy Efficiency Potential Study
Applied Energy Group, Inc. 117
Table A-29 Lodging Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 4.4%1.20 0.05 0.2
Cooling Water-Cooled Chiller 17.8%1.56 0.28 0.8
Cooling RTU 8.1%2.65 0.21 0.7
Cooling Room AC 27.5%2.72 0.75 2.3
Cooling Air-Source Heat Pump 17.6%2.65 0.47 1.4
Cooling Geothermal Heat Pump 2.5%2.29 0.06 0.2
Heating Electric Furnace 60.2%4.18 2.52 7.6
Heating Electric Room Heat 3.6%3.98 0.14 0.4
Heating Air-Source Heat Pump 17.6%3.83 0.67 2.0
Heating Geothermal Heat Pump 2.5%2.48 0.06 0.2
Ventilation Ventilation 100.0%1.42 1.42 4.3
Water Heating Water Heater 31.5%4.81 1.51 4.6
Interior Lighting Screw-in/Hard-wire 100.0%3.31 3.31 10.0
Interior Lighting High-Bay Fixtures 100.0%0.27 0.27 0.8
Interior Lighting Linear Fluorescent 100.0%0.87 0.87 2.6
Exterior Lighting Screw-in/Hard-wire 100.0%0.13 0.13 0.4
Exterior Lighting HID 100.0%0.51 0.51 1.6
Exterior Lighting Linear Fluorescent 100.0%0.03 0.03 0.1
Refrigeration Walk-in Refrigerator/Freezer 3.0%0.82 0.02 0.1
Refrigeration Reach-in Refrigerator/Freezer 19.0%0.18 0.03 0.1
Refrigeration Glass Door Display 40.0%0.19 0.08 0.2
Refrigeration Open Display Case 0.0%1.12 0.00 0.0
Refrigeration Icemaker 88.9%0.62 0.55 1.7
Refrigeration Vending Machine 57.8%0.29 0.17 0.5
Food Preparation Oven 24.0%0.83 0.20 0.6
Food Preparation Fryer 4.0%1.20 0.05 0.1
Food Preparation Dishwasher 39.0%0.82 0.32 1.0
Food Preparation Steamer 4.0%0.60 0.02 0.1
Food Preparation Hot Food Container 10.0%0.11 0.01 0.0
Office Equipment Desktop Computer 100.0%0.20 0.20 0.6
Office Equipment Laptop 100.0%0.03 0.03 0.1
Office Equipment Server 100.0%0.12 0.12 0.4
Office Equipment Monitor 100.0%0.04 0.04 0.1
Office Equipment Printer/Copier/Fax 100.0%0.02 0.02 0.1
Office Equipment POS Terminal 58.0%0.03 0.02 0.1
Miscellaneous Non-HVAC Motors 91.3%0.15 0.14 0.4
Miscellaneous Pool Pump 76.0%0.02 0.02 0.1
Miscellaneous Pool Heater 27.0%0.03 0.01 0.0
Miscellaneous Other Miscellaneous 100.0%0.76 0.76 2.3
Total 16.08 48.7
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
771
Energy Efficiency Potential Study
Applied Energy Group, Inc. 118
Table A-30 Warehouse Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 13.0%4.17 0.54 3.4
Cooling Water-Cooled Chiller 1.4%4.78 0.07 0.4
Cooling RTU 17.0%4.11 0.70 4.4
Cooling Room AC 1.1%4.22 0.05 0.3
Cooling Air-Source Heat Pump 1.6%4.10 0.07 0.4
Cooling Geothermal Heat Pump 0.0%2.50 0.00 0.0
Heating Electric Furnace 4.9%7.82 0.38 2.4
Heating Electric Room Heat 1.7%7.45 0.13 0.8
Heating Air-Source Heat Pump 1.6%5.85 0.09 0.6
Heating Geothermal Heat Pump 0.0%4.46 0.00 0.0
Ventilation Ventilation 100.0%0.60 0.60 3.8
Water Heating Water Heater 76.9%0.61 0.47 2.9
Interior Lighting Screw-in/Hard-wire 100.0%0.23 0.23 1.5
Interior Lighting High-Bay Fixtures 100.0%0.96 0.96 6.1
Interior Lighting Linear Fluorescent 100.0%1.12 1.12 7.1
Exterior Lighting Screw-in/Hard-wire 100.0%0.18 0.18 1.1
Exterior Lighting HID 100.0%0.15 0.15 0.9
Exterior Lighting Linear Fluorescent 100.0%0.15 0.15 1.0
Refrigeration Walk-in Refrigerator/Freezer 1.1%4.49 0.05 0.3
Refrigeration Reach-in Refrigerator/Freezer 2.0%1.01 0.02 0.1
Refrigeration Glass Door Display 0.0%1.03 0.00 0.0
Refrigeration Open Display Case 0.0%6.13 0.00 0.0
Refrigeration Icemaker 8.3%1.69 0.14 0.9
Refrigeration Vending Machine 6.9%0.80 0.05 0.3
Food Preparation Oven 0.0%0.28 0.00 0.0
Food Preparation Fryer 0.0%0.41 0.00 0.0
Food Preparation Dishwasher 2.0%0.56 0.01 0.1
Food Preparation Steamer 0.0%0.41 0.00 0.0
Food Preparation Hot Food Container 0.0%0.08 0.00 0.0
Office Equipment Desktop Computer 100.0%0.23 0.23 1.5
Office Equipment Laptop 100.0%0.03 0.03 0.2
Office Equipment Server 89.0%0.27 0.24 1.5
Office Equipment Monitor 100.0%0.04 0.04 0.3
Office Equipment Printer/Copier/Fax 100.0%0.03 0.03 0.2
Office Equipment POS Terminal 77.0%0.07 0.06 0.4
Miscellaneous Non-HVAC Motors 49.9%0.14 0.07 0.4
Miscellaneous Pool Pump 0.0%0.00 0.00 0.0
Miscellaneous Pool Heater 0.0%0.00 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.65 0.65 4.1
Total 7.50 47.4
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
772
Energy Efficiency Potential Study
Applied Energy Group, Inc. 119
Table A-31 Miscellaneous Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Sqft)(GWh)
Cooling Air-Cooled Chiller 4.2%3.89 0.16 2.0
Cooling Water-Cooled Chiller 16.7%4.41 0.73 9.0
Cooling RTU 34.5%3.22 1.11 13.6
Cooling Room AC 4.9%3.30 0.16 2.0
Cooling Air-Source Heat Pump 6.2%3.22 0.20 2.4
Cooling Geothermal Heat Pump 1.1%1.96 0.02 0.3
Heating Electric Furnace 15.2%8.92 1.36 16.6
Heating Electric Room Heat 8.4%8.49 0.71 8.7
Heating Air-Source Heat Pump 6.2%7.40 0.46 5.6
Heating Geothermal Heat Pump 1.1%5.74 0.07 0.8
Ventilation Ventilation 100.0%1.39 1.39 17.0
Water Heating Water Heater 51.3%2.64 1.35 16.6
Interior Lighting Screw-in/Hard-wire 100.0%0.75 0.75 9.2
Interior Lighting High-Bay Fixtures 100.0%0.25 0.25 3.0
Interior Lighting Linear Fluorescent 100.0%1.42 1.42 17.3
Exterior Lighting Screw-in/Hard-wire 100.0%0.43 0.43 5.3
Exterior Lighting HID 100.0%0.91 0.91 11.1
Exterior Lighting Linear Fluorescent 100.0%0.07 0.07 0.8
Refrigeration Walk-in Refrigerator/Freezer 9.0%0.98 0.09 1.1
Refrigeration Reach-in Refrigerator/Freezer 0.0%0.22 0.00 0.0
Refrigeration Glass Door Display 15.0%0.23 0.03 0.4
Refrigeration Open Display Case 0.0%1.34 0.00 0.0
Refrigeration Icemaker 41.6%0.37 0.15 1.9
Refrigeration Vending Machine 28.6%0.35 0.10 1.2
Food Preparation Oven 28.0%0.24 0.07 0.8
Food Preparation Fryer 4.0%0.35 0.01 0.2
Food Preparation Dishwasher 31.0%0.49 0.15 1.8
Food Preparation Steamer 4.0%0.36 0.01 0.2
Food Preparation Hot Food Container 7.0%0.07 0.00 0.1
Office Equipment Desktop Computer 100.0%0.37 0.37 4.6
Office Equipment Laptop 100.0%0.06 0.06 0.7
Office Equipment Server 66.0%0.22 0.15 1.8
Office Equipment Monitor 100.0%0.07 0.07 0.8
Office Equipment Printer/Copier/Fax 100.0%0.04 0.04 0.5
Office Equipment POS Terminal 28.0%0.06 0.02 0.2
Miscellaneous Non-HVAC Motors 59.9%0.15 0.09 1.1
Miscellaneous Pool Pump 4.0%0.02 0.00 0.0
Miscellaneous Pool Heater 1.0%0.03 0.00 0.0
Miscellaneous Other Miscellaneous 100.0%0.78 0.78 9.6
Total 13.75 168.1
Average Market Profiles - Electricity
End Use Technology Saturation
2015 Electric IRP Appendix C
773
Energy Efficiency Potential Study
Applied Energy Group, Inc. 120
Table A-32 Industrial Electric Market Profile, Idaho

EUI Intensity Usage
(kWh)(kWh/Employee)(GWh)
Cooling Air-Cooled Chiller 13.0% 5,652 734 6.51
Cooling Water-Cooled Chiller 1.4% 6,479 94 0.83
Cooling RTU 17.0% 5,559 947 8.40
Cooling Room AC 1.1% 5,714 64 0.57
Cooling Air-Source Heat Pump 1.6% 5,557 89 0.79
Cooling Geothermal Heat Pump 0.0% 3,706 0 0.00
Heating Electric Furnace 4.9% 10,593 516 4.58
Heating Electric Room Heat 1.7% 10,088 173 1.54
Heating Air-Source Heat Pump 1.6% 7,918 127 1.13
Heating Geothermal Heat Pump 0.0% 5,281 0 0.00
Ventilation Ventilation 100.0%807 807 7.16
Interior Lighting Screw-in/Hard-wire 100.0%205 205 1.82
Interior Lighting High-Bay Fixtures 100.0%854 854 7.58
Interior Lighting Linear Fluorescent 100.0%997 997 8.84
Exterior Lighting Screw-in/Hard-wire 100.0%162 162 1.44
Exterior Lighting HID 100.0%134 134 1.18
Exterior Lighting Linear Fluorescent 100.0%134 134 1.19
Motors Pumps 100.0% 3,640 3,640 32.29
Motors Fans & Blowers 100.0% 2,850 2,850 25.28
Motors Compressed Air 100.0% 2,275 2,275 20.18
Motors Conveyors 100.0% 10,272 10,272 91.13
Motors Other Motors 100.0% 1,593 1,593 14.13
Process Process Heating 100.0% 4,159 4,159 36.90
Process Process Cooling 100.0% 1,364 1,364 12.10
Process Process Refrigeration 100.0% 1,364 1,364 12.10
Process Process Electro-Chemical 100.0% 2,702 2,702 23.97
Process Process Other 100.0%915 915 8.12
Miscellaneous Miscellaneous 100.0% 1,494 1,494 13.26
38,668 343.03
Average Market Profiles - Electricity
End Use Technology Saturation
Total
2015 Electric IRP Appendix C
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Applied Energy Group, Inc. 121
APPENDIX B
Market Adoption (Ramp) Rates
This appendix presents the market adoption rates we applied to economic potential to estimate
achievable potential.
Avista Appendix - Market Adoption Rates.xlsx

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Applied Energy Group, Inc. 122
APPENDIX C
Equipment Measure Data
Please see measure-level assumptions and details in the file “Avista Appendix- Equipment
Measure Data.xlsx”

Avista Appendix - Equipment Measure Data.xlsx

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Applied Energy Group, Inc. 123
APPENDIX D
Non-Equipment Measure Data
Please see measure-level assumptions and details in the file “Avista Appendix- Non-Equipment
Measure Data.xlsx”

Avista Appendix - Non-Equipment Measure Data.xlsx

2015 Electric IRP Appendix C
777

Applied Energy Group, Inc.
500 Ygnacio Valley Road, Suite 250
Walnut Creek, CA 94596
P: 510.982.3525 F: 925.284.3147
2015 Electric IRP Appendix C
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2015 Electric Integrated
Resource Plan

Appendix D – Avista Generation
Energy Efficiency Studies

2015 Electric IRP Appendix D
779

Energy Efficiency Improvements
Audit Report

Prepared for
Boulder Park Generating Facility

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

January 16, 2015

2015 Electric IRP Appendix D
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Overview

Facility: Boul
Audited by:, Andy Paul PE
Onsite Staff:
Facility Audited on: January 8th,

Figure 1

and Levi Westra PE

Google Earth Images of the Boulder Park Generation Facility

he Boulder Park Generation Facility
Avista’s DSM Engineering staff visited the Boulder Park generating facility to review their current building
systems and discuss several concerns that the user’s encountered during typical operation. Specifically,
2015 Electric IRP Appendix D
781

this audit was conducted to identify all possible energy efficiency improvements not related to the power
generation process.
After completing a tour of the facility, potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
The facility consists of an office, network room, and large high bay warehouse which houses (6) sound
isolated natural gas burning compression-ignition 4-stroke engine generator sets; with a 7th unit available
for parts.
Shell
There are several areas around the facility where additional weatherization work can be conducted.
1. The roll up doors could use new weather stripping along the outside edges of the doors and along
the bottom. A noticeable draft can be felt when you stand next to the doors.

2. The man doors would also benefit from additional weather stripping.

3. There are several areas along where the foundation and exterior walls meet that daylight can be
seen from the inside. These gaps in the wall construction should be sealed; a closed cell foam
product would work well here.

While these measures will conserve energy, those savings will be negligible in comparison to the
measures listed further in this report.

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Lighting
The site employs T12, T8 and T5 linear fluorescent lighting as well as 400 Watt Metal Halide (MH) high-
bay and 250 Watt MH exterior lighting on dusk to dawn sensors. No parking lot lighting was observed.

Table 1 Capital Project Lighting Opportunity Summary
Brief EEM*
Description
EEM
Cost
Measure
Life
Electric
kWh
Savings
1 Control Room
Lighting $13,850 20 yrs 3,931
2
Generating
Floor High
Bays
$16,848 20 yrs 16,099
3
Replacing
Engine Bay
Lights
$17,976 20 yrs 6,739
4
Replace
Exterior Wall
Packs $10,702 20 yrs 16,054
*EEM – Energy Efficiency Measure

1. Proposed Project #1: The facility currently has (x40) two lamp F32T8 fluorescent fixtures lighting
the control room, break room, and restroom. The fixtures average 2,600 hrs of operation a year.
The proposed project looks at replacing these fixtures with (x40) 40W linear LED fixtures. A
simple lumen calculation shows that the overall lumens for the job were decreased by 7%.
o The provided project is $13,850, this cost was calculated using fixture and install costs for
these fixtures at Noxon Rapids HED.
2. Proposed Project #2: The facility currently has (x24) single lamp 400W Metal Halide fixtures
lighting the main generation facility. The fixtures average 2,080 hrs of operation a year. The
proposed project looks at replacing these fixtures with (x24) 200W linear LED high bay fixtures. A
simple lumen calculation shows that the overall lumens for the job were decreased by 23%.
o The provided project is $16,484, this cost was calculated using fixture and install costs for
these fixtures at Noxon Rapids HED.
3. Proposed Project #3: The facility has six engine bays; each bay is lit by (x8) two lamp F96T12
fixtures. The fixtures average 2,080 hrs of operation a year. The proposed project looks at
replacing all (x48) fixtures with 50W linear LED fixtures. A simple lumen calculation shows that
the overall lumens for the job were decreased by 59%.
o The provided project is $17,976, this cost was calculated using fixture and install costs for
these fixtures at Noxon Rapids HED.
4. Proposed Project #4: The facility currently has (x16) single lamp 250W Metal Halide wall packs
on the exterior of the plant. The fixtures average 4,288 hrs (dusk to dawn) of operation a year.
The proposed project looks at replacing these fixtures with (x16) 52W LED wall packs. A simple
lumen calculation shows that the overall lumens for the job were decreased by 66%.
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o The provided project is $10,702, this cost was calculated using fixture and install costs for
these fixtures at Noxon Rapids HED.
5. It should be noted that while the total system lumens decrease for each of these projects, the
actual lumens that reach the working space will more the likely increase. LED fixtures are very
directional in the way they deliver lighting lumens. We recommend replacing a few light fixtures to
make sure that they will meet your lighting needs. If you would like to see the fixtures in operation
we recommend a trip to Noxon Rapids HED.
Low Cost No Cost Opportunities
In addition to the lighting replacement projects listed above we discussed a few re-circuiting projects
that would help further reduce the electric load.
1. The three rows of lights on the generating floor are currently controlled by one switch. We
recommend separating them out to one switch per row. This would allow the operators to leave
the center row of lights off except during maintenance above the engine rooms.
2. The lights in the engine rooms are turned on when the engines are running and remain on for the
duration. We recommend that these lights be put on bi-level switching. When the engines are
running half the lights would come on, an occupancy sensor would turn the other half on when an
operator entered a room.
HVAC
1. The control room, restroom, break room, and the MCC room are conditioned by two heat pump
roof top units mounted on grade outside the building. Each of these units appears to be original to
the building, based on the age they are in the 13 SEER (seasonal energy efficiency rating) range.
While there are newer units available that have efficiencies closer to SEER 19, the cost to
purchase and install these units outweighs the potential energy savings. Our recommendation is
to replace these units when they have reached their end of life. When you do replace these units
purchase the most efficient units that can be afforded.
You may also consider replacing these units with gas fired units. When these units were
purchased and installed the price of gas was high enough that it made heat pumps the more
economical choice for heating. Now the price of gas is low enough that gas furnaces and roof top
units, down to 80% efficient, is the more economical option. Currently the most efficient roof top
unit on the market is around 82%. A few companies are working on 90+% efficient models, but
none have come to market.
2. The generation floor has two 80% efficient natural gas fired unit heaters to provide supplemental
heat in the winter. Currently Reznor makes a 90% efficient unit heater. While replacing the
existing heaters with a new higher efficiency unit would generate gas savings, the price of these
units is high enough that the project would more than likely not make financial sense. In addition
the staff stated that these units do not operate all that often. In the future when these units are at
end of life we recommend purchasing and installing the most efficient units that can be afforded.

3. The low speed/high volume destratification fan on the east end of the generating floor was
making a rattling noise during our site visit. We recommend having the fan and motor be serviced
before more serious damage is incurred.

2015 Electric IRP Appendix D
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Process

• Compressed Air System

Brief EEM
Description
EEM
Cost
Electric
kWh
Savings
Residential
energy retail
value
Simple
Payback

Instrument Air
Cycling Air-
Dryers
$6,600 10,074 $891/yr 14.8 yr

Scope of Work:

• Proposed Project - Boulder Park Generating facility employs a single Kaeser SM 15 (15 hp, 53
scfm @ 100psi) rotary screw air-compressor supplying air to instruments and controls. The air is
dried using two non-cycling Zeks NC 75 (75 cfm) refrigeration dryers. The EEM replaces those
units with one appropriately sized Hankison HES90 (90 cfm) cycling refrigeration dryer. The
analysis is based upon observed air-compressor operation (run time during audit) manufacturer’s
specifications and assumed annual hours of operation (24/7/365). A copy of the analysis is
appended to this document in a SMath Studio Worksheet.
• Mitch Johnson, of Rogers Machinery, provided a cost estimate of $3,300 for a non-cycling unit.
This does not include install costs; the facility’s excellent maintenance staff will have no problem
installing this unit.
• Oil reservoir heaters
• Currently the facility uses 5 kW thermal elements for the engine oil heating system. There are
two elements per tank and six engines for a total of 60 kW. This is a purely resistive load that
operates continuously to maintain a tank oil temperature of 120 ºF. The estimated annual energy
consumed by this system is approximately 525,600 kWh (this type of system is nearly 100%
efficient). The cost associated with this type of heating is about $36,800 (using Avista WA rate
schedule 21 and $0.07/kWh). The opportunity here is to investigate the possibility of replacing
the electric resistive elements with an NG hydronic system that would circulate heated water
2015 Electric IRP Appendix D
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through the tank via some type of finned tube arrangement. On a strictly “per BTU” basis, the
cost savings would approximately be as follows:
• 525,600 kWh*(3412 BTU/kWh) = 1,800 MMBTU*(therms/1E5BTU) = 17,933 therms
• Assuming a heating (tube) efficiency effectiveness of about 75%, the final NG consumption is
expected to be 23,911 therms per year. Using a per therm cost of $0.69 (WA natural gas
schedule 111) this translates to an operating cost of approximately $16,500 per year, giving a
reduction of 55% in operating costs. Depending on the final system, piping, materials, and
circulation pump sizing, the final energy cost reduction could be expected to be 50%. The 5%
“conservative” factor also includes the initial energy required to raise the water temp from 52oF to
120oF and standby losses. There may (and probably will) also be some additional maintenance
costs associated with regular tube inspections and cleaning. Obviously, whether or not this is a
prudent investment depends largely on the equipment, installation, and commissioning costs
associated with the project. Once estimates are provided, project simple paybacks and return on
investments can be calculated.
We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.
Respectfully,
Andy Paul, Bryce Eschenbacher, and Levi Westra - January 19, 2015

2015 Electric IRP Appendix D
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Acct#
Existing Annual Consumption: (kilowatt hours)7,706.40
Lighting Energy Savings:(kilowatt hours)3,650.40
Lighting Demand Savings: (kilowatt demand)1.15
Cooling System Savings: (kilowatt hours)281.08
Cooling System Demand Savings: (kW demand) 0.09
Lumen Comparison New/Existing 93.03%
Total Energy Savings: (kilowatt hours)3,931.48
Total Demand Savings: (kilowatt demand)1.24
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)(31.76)
Maintenance Savings:($30.69)
Name: Boulder Park Generating Facility - Control Room Lighting
BoulderPark_ControlRoom_Lighting_011415 Report Pg 1 - 1 01-14-20152015 Electric IRP Appendix D
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Acct#
Existing Annual Consumption: (kilowatt hours) 28,392.00
Lighting Energy Savings:(kilowatt hours)16,099.20
Lighting Demand Savings: (kilowatt demand)4.95
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 76.92%
Total Energy Savings: (kilowatt hours)16,099.20
Total Demand Savings: (kilowatt demand)4.95
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:$238.60
Name: Boulder Park Generating Facility - Generating Floor
BoulderPark_GeneratingFloor_Lighting_011415 Report Pg 1 - 1 01-16-20152015 Electric IRP Appendix D
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Acct#
Existing Annual Consumption: (kilowatt hours)9,859.20
Lighting Energy Savings:(kilowatt hours)6,739.20
Lighting Demand Savings: (kilowatt demand)4.15
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 41.29%
Total Energy Savings: (kilowatt hours)6,739.20
Total Demand Savings: (kilowatt demand)4.15
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:$117.10
Name: Boulder Park Generating Facility -Engine Room
BoulderPark_EngineRoom_Lighting_011415 Report Pg 1 - 1 01-16-20152015 Electric IRP Appendix D
789
Acct#
Existing Annual Consumption: (kilowatt hours) 19,621.89
Lighting Energy Savings:(kilowatt hours)16,054.27
Lighting Demand Savings: (kilowatt demand)3.00
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 33.69%
Total Energy Savings: (kilowatt hours)16,054.27
Total Demand Savings: (kilowatt demand)3.00
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:$306.46
Name: Boulder Park Generating Facility - Wall Packs
BoulderPark_WallPacks_Lighting_011415 Report Pg 1 - 1 01-16-20152015 Electric IRP Appendix D
790
Customer: Avista Generation; Boulder Park Internal Combustion Topping Plant
Project State: EEM Evaluation
Date: 01/08/15
Analysis Description: The facility employs a single Kaeser SM 15 rotary screw
compressor operating with on/off controls with (2) Zeks NC 75 non-cycling
refrigeration air-dryers for the facility's controls.
100
1pct input: assign "percent" to SMath Studio
Figure 1. Explanation of cycling air-dryer technology
19 Jan 2015 09:20:54 - SMath - Boulder Park Compressed Air EEM eval 010815.sm
1 / 3
2015 Electric IRP Appendix D
791
Table 1. Technical specifications for existing non-cycling refrigeration air-dryers
Table 2. Technical specifications for proposed cycling refrigeration air-dryers
Inputs:
kW0.67Pbase_nom input: basline power consumption; manufacturer specified, see Table 1.
input: number of baseline 75 scfm air dryers; assume two needed for n+1 redundancy2Qty
kW0.95PEEM_nom input: EEM power consumption; manufacturer specified, see Table 2.
pct10Uave input: assumed utilization rate; based on air-compressor operation observed during
site audit; air compressor cycled on once for a few minutes during the hour long visit.
yr
hr8760top
input: assumed annual hours of operation
19 Jan 2015 09:20:54 - SMath - Boulder Park Compressed Air EEM eval 010815.sm
2 / 3
2015 Electric IRP Appendix D
792
Calculations:
topPbase_nomQtyEbase calc: energy consumed annually by the baseline non-cycling units
yr
hrkW11738.4Ebase
UavetopPEEM_nomQtyEEEM calc: energy consumed annually by the EEM cycling units
yr
hrkW1664.4EEEM
EEEMEbaseEsavings_annual calc: energy saved annually converting to the EEM units
yr
hrkW10074Esavings_annual
Contacted Mitch at Rogers' Machinery and he gave me a rough estimate for a Hankinson HES90 cycling compressor
of ~$3,300/unit.
1dollar input: assign "dollar" to SMath Studio
dollar33002Cost input: cost estimate for one EEM
hrkW
dollar0.08848Rate input: assumed average energy sales rate based upon blended 3 tiers of residential
RateEsavings_annualCsavings calc: annual revenue from EEM
yr
dollar891.3Csavings
Csavings
QtyCostSPB
calc: average energy simple payback
yr14.8SPB
Non-Energy Benefits (NEBs):
- Life (years of operation before failure) of the dryer(s) will be increased due to reduced hours of compressor operation.
This is even more evident when the (2) units are operated in an N+1 redundancy configuration.
19 Jan 2015 09:20:54 - SMath - Boulder Park Compressed Air EEM eval 010815.sm
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Energy Efficiency Improvements
Audit Report

Prepared for
Cabinet Gorge Hydro Electric Dam

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

April 13, 2015

2015 Electric IRP Appendix D
794

Overview

Facility: Cabinet Gorge Hydro Electric Dam
Audited by: Andy Paul PE, Bryce Eschenbacher PE
Onsite Staff: Alan Lackner
Facility Audited on: March 30th, 2015

Figure 1 Google Images of the Cabinet Gorge Hydro Electric Dam

2015 Electric IRP Appendix D
795

Avista’s DSM Engineering staff visited the Cabinet Gorge Hydro Electric Dam to review their current
building systems and discuss several concerns that the user’s encountered during typical operation.
Specifically, this audit was conducted to identify all possible energy efficiency improvements not related to
the power generation process.
After completing a tour of the facility potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation, and its estimated cost, is based
upon historical experience and costing projections. Equipment life and performance will vary and a
Statement of Work (SOW) for the capital project will determine the actual project costs and performance.
The facility consists of a control room, office space, break area and generation specific process areas
including but not limited to generation floor and breaker floor.
Shell
Due to the design of the facility there are no real shell measures that can be undertaken that would
benefit the facility or save energy.

Lighting
The lighting system is the largest inefficiency in the facility.
Cabinet Gorge is slated to have its lighting system completely replaced similarly to Noxon Rapids HED.
The majority of the new system will be linear LED’s with some screw in LED lamps where necessary.
Based on the number of fixtures present in the facility it will reduce that plant electric load by a similar
amount to Noxon Rapids load decrease, ~300,000 kWh.
HVAC
The facility is currently conditioned by several 480v electric unit heaters. These unit heaters have to run
24/7 in the winter to keep the temperature in the facility above 50ºF. In addition to the heaters there is a
fresh air intake system, this system brings in outside air (OSA) and ducts it all around the facility. The
OSA system will do a nightly flush of the facility during the warmer months in an attempt to keep the
internal temperature low during the day. Currently there are no active heating and cooling elements in the
system.
It is recommended that a water source heat pump system, similar to Noxon Rapids, be considered to
condition the facility. The major costs of adding an HVAC system is the duct work and cooling/heating
coils, the facility is already completely ducted and several cooling/heating coils are in place.
We recommend that the most efficient equipment that can be afforded be installed. This will be an
expensive project to take on, but it will reduce the extreme temperature swings that happen inside the
facility throughout the year and would provide protection for some of the sensitive equipment.
The relay tech room and the break room currently have window style AC units and small electric heaters
to keep the space conditioned. It is recommended that stand alone ductless heat pump systems be
installed to serve these spaces. Certain Mitsubishi and Daikin units can have multiple inside units,
cassettes, paired with one condensing unit.
Compressed air

The facility’s pneumatic systems consisted of several small (~25HP) reciprocating compressors along
with two large oil-free rotary screw units. No recommendations will be made at this time with regards to
the reciprocating units as they are near-perfect part-load machines. However, the two 250HP Kobelco
compressors may represent an energy saving opportunity. The specifications for the machines are as
follows:
2015 Electric IRP Appendix D
796

TWO-STAGE, HEAVY-DUTY, OIL-FREE, WATER-COOLED, ROTARY SCREW AIR COMPRESSOR
MOUNTED ON A FABRICATED STEEL BASE AND DRIVEN BY A 250 HP, 3/60/460 VOLT, PREMIUM
EFFICIENCY, OPEN DRIPPROOF MOTOR.
.
SOLID-STATE (SOFT-START) MOTOR STARTER, 250 HP, 3/60/460 VOLT, IN NEMA 1 ENCLOSURE,
MOUNTED, WIRED AND TESTED ON THE ASSEMBLY.
.
CUSTOM ENGINEERING AND FABRICATION.
SPECIAL ENGINEERING AND FACTORY FABRICATION TO DESIGN COMPRESSORS SO THEY
CAN BE BROKEN DOWN AT THE JOBSITE, TRANSPORTED, AND REASSEMBLED IN THE
COMPRESSOR ROOM.

The system is a serves a common header and the two units are controlled on a lead/lag fashion.
Depending on the hours of operation and the actual cfm demand, a bolt-on variable frequency drive
(VFD) on one of the units (the one providing the trim load) might be a good option. VFDs will modulate
the compressor down so that the input power nearly matches the cfm demand with very little waste in the
form of heat and blown off (unloaded) air. The system should be configured in such a way that the VFD-
equipped machine responds to the base cfm demand below (100%) until it reaches near 100%. At that
time the fixed-speed unit should cycle on to meet that full base load and the VFD unit trims. Again the
cost-effectiveness depends on cfm demand and run-hours. We estimate the VFD cost for one
compressor to be approximately $50,000 including installation and programming.

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.
Respectfully,
Andy Paul, Bryce Eschenbacher, and Levi Westra – April 13th, 2015

2015 Electric IRP Appendix D
797

Energy Efficiency Improvements
Audit Report

Prepared for
Coyote Springs Thermal Generating Facility

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

June 22, 2015

2015 Electric IRP Appendix D
798

Overview

Facility: Coyote Springs
Audited by: Andy Paul PE
Onsite Staff: Dan Turley, PGE
Facility Audited on: June 18th, 2015

Figure 1

the power generation process.

and Levi Westra PE

Google Earth Images of the Coyote Springs
Avista’s DSM Engineering staff visited the Coyote Springs

Generation Facility
generating facility to review their current
ser’s encountered during typical operation.
Specifically, this audit was conducted to identify all possible energy efficiency improvements not related to
2015 Electric IRP Appendix D
799

After completing a tour of the facility, potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
The facility consists of an office, network room, and large high bay warehouse which houses two combine
cycle steam turbines. Unit #2 belongs to Avista Utilities.
Shell
The majority of the facility houses the generating equipment, and associated process loads. The waste
heat coming off of the equipment is the main source of heat during the winter months and the plant is not
conditioned during the summer months. This reduces the amount of shell measure projects; insulation,
weather sealing, windows, etc, that can be undertaken in this part of the facility. There are several areas;
control room, MCC enclosures, switch gear, office areas, that may benefit from upgraded insulation and
at the very least routine inspection and maintenance. Below are some suggestions for areas that should
be checked.
1. Any man door leading to an area that is mechanically conditioned should have its weather
stripping checked a couple of times a year and replaced as necessary.
2. If the roof insulation area above the office area is less than R19 additional insulation should be
added. The office space has a drop ceiling throughout; un-faced batt insulation could easily be
added above the ceiling panels.
3. The remainder of the facility is well insulated and does not have any weatherization or shell
improvements required at this time. It is recommended that the roll up and man doors be checked
periodically and maintenance be done as necessary.

While these measures will conserve energy, those savings will be negligible in comparison to the
measures listed further in this report.

Lighting
The site employs T12 and T8 linear fluorescent lighting as well as 400 Watt high pressure sodium (HPS)
high-bay and 250 Watt MH exterior lighting on dusk to dawn sensors. No parking lot lighting was
observed.

Table 1 Capital Project Lighting Opportunity Summary
Brief EEM*
Description
EEM
Cost
Measure
Life
Electric
kWh
Savings
1 Control Room
Lighting $5,194 20 yrs 6,368
2
Generating
Floor High
Bays
$44,646 20 yrs 85,778
3 Roadway
Lighting $225 20 yrs 1,085
*EEM – Energy Efficiency Measure
2015 Electric IRP Appendix D
800

1. Proposed Project #1: The facility currently has (x15) three lamp F32T8 fluorescent fixtures
lighting the control room. The fixtures average 8,760 hrs of operation a year. The proposed
project looks at replacing these fixtures with (x15) 40W linear LED fixtures. A simple lumen
calculation shows that the overall lumens for the job were decreased by 34%.
o The provided project is $5,194, this cost was calculated using fixture and install costs for
these fixtures at Noxon Rapids HED.
2. Proposed Project #2: The facility currently has (x32) single lamp 400W High Pressure Sodium
fixtures lighting the main generation facility. The fixtures average 8,760 hrs of operation a year.
The proposed project looks at replacing these fixtures with (x32) 144W LED high bay fixtures
(HEGRC4KN-SNG Dialight). A simple lumen calculation shows that the overall lumens for the job
were increased by 50%.
o The provided project is $44,646, this cost was calculated using fixture and install costs for
a project at a local paper mill.
During our conversation with facility staff it was mentioned that any fixture that would be installed
on the generating floor would need to be able to operate in extreme temperatures. The ceiling on
is upwards of 120 feet and the temperature can easily get over 120ºF. The proposed Dialight
fixture has an operating temperature range of -40ºF to 149ºF. These fixtures should be able to
handle the conditions at Coyote Springs. It is recommended that a couple of test fixtures be
purchased and installed, this will allow the facility staff to see how the lights perform in the
extreme temperatures present and evaluate how the like the quality of the light produced.
3. Proposed Project #3: The roadway is lit by single Lamp 250W metal halide cobra heads. This
project would replace these with Cree 42W LED cobra heads. It is assumed that these fixtures
have an average of 4,288 hrs/yr (dusk to dawn) annual operating hours. A simple lumen
calculation shows that the overall lumens for the job were decreased by 71%. This analysis looks
at the cost and energy savings for replacing one of these fixtures.
o The provided project is $225, this cost was calculated using fixture and install costs for
one of these fixtures at Noxon Rapids HED.
4. It should be noted that while the total system lumens decrease for projects 1 and 3, the actual
lumens that reach the working space will more the likely increase. LED fixtures are very
directional in the way they deliver lighting lumens. We recommend replacing a few light fixtures to
make sure that they will meet your lighting needs. If you would like to see the fixtures in operation
we recommend a trip to Noxon Rapids HED.
HVAC
1. The control room, office, restroom, break room, and the switch gear rooms are conditioned by two
gas fired roof top units mounted on grade outside the building. One unit belongs to Avista and
only serves Avista’s switch gear; the other unit handles the control room, office, and PGE’s switch
gear. These units appear to have been recently replaced. The units have a cooling efficiency of
11.6 EER; energy code minimum efficiency is 11 EER. It is recommended that when these units
come up for replacement in the future they are replaced with the most efficient piece of
equipment that can be afforded.
The supply and return ductwork for these units is un-insulated, it is recommended that insulation
be added. There is a significant length of ductwork, 10 to 20 feet, exposed to the elements before
turning into the building.
2. The generation floor has several 80% efficient natural gas fired unit heaters to provide
supplemental heat in the winter. Currently Reznor makes a 90% efficient unit heater. While
2015 Electric IRP Appendix D
801

replacing the existing heaters with a new higher efficiency unit would generate gas savings, the
price of these units is high enough that the project would more than likely not make financial
sense. In addition the staff stated that these units do not operate all that often. In the future when
these units are at end of life we recommend purchasing and installing the most efficient units that
can be afforded.

Process
Compressed Air System

The facility instrumentation and control air is provided by two Ingersol-Rand SSR-HP75 75kW rotary-
screw load/unload compressors in an N+1 failsafe configuration. The compressors feed an Ingersoll-
Rand TZ300 desiccant air-dryer and a large dry receiver. The air-dryer is a heatless unit and uses a timer
to control regeneration cycles. There are several opportunities for reducing energy consumption of these
devices, including adding VFDs to the compressors and upgrading the dryer to a heated/demand
controlled unit.

Figure 2 Comparison of rotary-screw air compressor controls (% load vs % flowrate)

A comparison of the existing load/unload controls to a VFD controlled air-compressor operating at 60%
load 8760 hr/yr results in a 20% energy savings or around 130,000 kWh/yr. The 60% load is an
assumption; this value may be higher or lower and will affect the annual energy savings. The $15,000
EEM cost assumes only one of the compressors is converted or replaced.

Table 2 Possible savings and roughly estimated costs for compressed air system EEMs.
Brief EEM*
Description
EEM
Cost
Measure
Life
Electric
kWh
Savings
1
Air-
Compressor
VFD
$15,000 12 yrs 130,000
2
Retrofit Air-
Dryer with
Dew-Point
Controls
$5,000 12 yrs 25,000
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
110%
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
%
O
F

F
U
L
L

L
O
A
D

P
O
W
E
R
% CAPACITY
TYPICAL PERFORMANCE OF ROTARY SCREW COMPRESSORS
Basic Inlet Modulation
Load/Unload Variable Speed
2015 Electric IRP Appendix D
802

The existing timer controlled compressed air-dryer operates on a 10 minute regeneration cycle regardless
of the dew point of the treated air. The EEM would retrofit this unit with dew-point controls which would
initiate a regeneration cycle only as required. The number of cycles will be reduced; they will become
dependent on the amount of moisture in the ambient air and the amount of air being consumed by the
facility. On average dew-point controls will reduce energy consumption about 40%, however, in central
Oregon, where the average humidity levels are quite low, the savings will likely be greater. If the decision
is made to replace the entire dryer, please consider replacing the unit with a heated unit for even more
energy savings.

Boiler feed water pumps

The facility is presently equipped with two 2500HP boiler feedwater pumps, one with variable speed
control (estimated installation, 2008). It is assumed that the pump operation is alternated with only one
running at any given time. It is unclear as to why both pumps were not originally equipped with VFDs
(budgetary concerns, no available changeover downtime, etc.?) unless the fixed-speed pump serves only
as an installed backup. If they do in fact alternate duty, installing a bolt-on VFD to the remaining fixed
speed pump should be a good option in terms of economics. Tremendous energy savings can be
achieved by controlling flow rates by pump speed control as opposed to modulating the flow rates with
control valves. Another option would be to control both feedwater pumps with only one VFD. The
technology exists such that multiple motors can be controlled with one drive provided that the motor sizes
are the same and that the speed reductions are the same, i.e. if one motor runs are 45Hz the other
running motors must also run at 45Hz. This option might be worth looking into if both pumps are running
at 30Hz (I assume that this is the minimum motor speed even though the Toshiba performance reports go
down to 25% or 15Hz) and can deliver enough pressure to inject water into the high-pressure drum.

The above suggestion applies also to other process pumps such as the 700HP cooling tower pumps as
well as other smaller process pumps. Pumps that; operate for a high percentage of time, have their flow
rates varied via controls valves, and do not necessarily need to provide full flow/pressure to a process,
are good candidates for variable frequency drives. Control valves (or any other fittings) represent an
obstruction in the flow path. This obstruction creates a head loss and pressure drop that the pump/motor
must overcome in order to meet pressure/flow requirements. As mentioned in the boiler feedwater
paragraph above, removing (or adjusting control valve(s) to 100% open) these pipe components and
controlling flow via motor speed, significant energy savings and process flexibility/longevity can be
achieved.

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.
Respectfully,
Andy Paul, Bryce Eschenbacher, and Levi Westra – June 22nd 2015

2015 Electric IRP Appendix D
803
Acct#
Existing Annual Consumption: (kilowatt hours) 11,169.00
Lighting Energy Savings:(kilowatt hours)5,913.00
Lighting Demand Savings: (kilowatt demand)0.54
Cooling System Savings: (kilowatt hours)455.30
Cooling System Demand Savings: (kW demand) 0.04
Lumen Comparison New/Existing 66.15%
Total Energy Savings: (kilowatt hours)6,368.30
Total Demand Savings: (kilowatt demand)0.58
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)(51.44)
Maintenance Savings:($373.22)
Name: Coyote Springs Generating Facility - Control Room Lighting
CoyoteSprings_ControlRoom_Lighting_061915 Report Pg 1 - 1 6/19/20152015 Electric IRP Appendix D
804
Acct#
Existing Annual Consumption: (kilowatt hours) 126,144.00
Lighting Energy Savings:(kilowatt hours)85,777.92
Lighting Demand Savings: (kilowatt demand)7.83
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 150.00%
Total Energy Savings: (kilowatt hours)85,777.92
Total Demand Savings: (kilowatt demand)7.83
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:$518.36
Name: Coyote Springs Generating Facility - Generating Floor
CoyoteSprings_GeneratingFloor_Lighting_061915Report Pg 1 - 1 6/19/20152015 Electric IRP Appendix D
805
Acct#
Existing Annual Consumption: (kilowatt hours)1,264.96
Lighting Energy Savings:(kilowatt hours)1,084.86
Lighting Demand Savings: (kilowatt demand)0.20
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 18.59%
Total Energy Savings: (kilowatt hours)1,084.86
Total Demand Savings: (kilowatt demand)0.20
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:$8.30
Name: Coyote Springs - Pole Lights
CoyoteSprings_Street_Lighting_061915 Report Pg 1 - 1 6/19/20152015 Electric IRP Appendix D
806
Vigilant® LED High Bay
for Indoor and Outdoor Industrial Applications
2015 Electric IRP Appendix D
807
Complete your own Return on Investment calculation at:www.dialight.com/tcoCalculator/Vigilant_HighBay
About Dialight
Dialight (LSE: DIA.L) is leading the energy efficient LED lighting revolution around the world for industrial and hazardous areas as well as transportation and
infrastructure applications. For 40 years it has been committed to the development of LED lighting solutions that enable organizations to vastly reduce energy
use and maintenance needs, improve safety, ease disposal and reduce CO2 emissions.
History at a Glance
1938 →Dialight founded in Brooklyn, NY
1971 →LED Circuit Board Indicator
1994 →LED Transit Vehicle Signals
1995 →LED Traffic Signals
2000 →FAA certified LED Obstruction Lights
2007 →LED Lighting for Hazardous Locations
2009 →LED High Bay Fixtures
2012 →Full performance 10-year warranty
2013 →Controls for LED Lighting
2014 →125lm/W High Bay
Typical Applications
• Oil, Gas & Petrochemical
• Power Generation
• Mining
• Chemical
• Pharmaceutical
• Water & Sewage
• Food & Beverage
• Manufacturing
• Warehousing
• Cold Storage
Dialight also offers their products for Hazardous Locations
Vigilant® LED High Bay
for Indoor and Outdoor Industrial Applications
www.dialight.com
View the full case studies at:
G.S. Dunn Limited - www.dialight.com/news/details/gsdunn_case_study
Rockline Industries - www.dialight.com/news/details/rockline_case_study
MedSafe - www.dialight.com/news/details/medsafe_case_study
Kuehne + Nagel - www.dialight.com/news/details/kuehne_nagel_case_study
2015 Electric IRP Appendix D
808
Mechanical Information
Fixture weight:18 lbs
Shipping weight:24 lbs
Mounting:(1) 3/4” NPT - top
(2) 5/16”-18 x .75” UNC - side
Cabling:10' (3.5m) STOOW Power Cord
Electrical Specifications
Operating Voltage:
24,250-26,500lm: 110 - 277V AC
16,500-18,000lm: 100 – 277V AC
(For 347 - 480V AC application, consult
factory)
Total system power
consumption:See Table
Operating Temp:-40°F to +149°F (-40°C to +65°C)
Harmonics:IEC 61000-3-2
Noise requirement /
EMC:FCC Title 47, Subpart B, Section 15, class A
device. RF Immunity; 10V/m, 80MHz-1GHz
Transient protection:Protection devices capable of handling up
to 6kV. Tested at independent laboratory
for 6kV/2 ohm combination wave, as per
IEEE C62.41, line-line and line-ground
Power Factor:> 0.9
Construction:
Housing: Copper free aluminum
Finish: Polyester powder coated gray RAL 7040
Lens: Tempered glass
Photometric Information
CRI:75
CCT:5,000K (cool white)
4,000K (neutral white)
All values typical unless otherwise stated
Lumen values are typical (tolerance +/- 10%)
Certifications & Ratings
•UL 1598/A
•CSA 22 #250
•CE
•NEMA 4X
•IP 66
•Dark Sky Compliant
Features & Benefits
•L70 rated for >100,000 hours @ 25°C
•10 year full performance warranty
•Up to 125 LPW
•Dual Mounting option available
•For 347-480V AC applications, consult factory
•Significantly reduced glare
•Instant on/off
•Maintenance free
•Mercury free
•No UV or IR
•Resistant to shock and vibration
Application:
At 125 lumens per Watt, Dialight’s new ultra-efficient industrial LED High
Bay revolutionizes the world of LED lighting and is by far the most
innovative LED fixture available today. With a market-leading 10 year full
performance warranty, the new 26,500 lumen high bay utilizes
cutting-edge optical and electrical design to provide for significantly
reduced glare and superior light distribution.
In its compact and lightweight structure, Dialight’s new 125 lumen per
Watt LED High Bay is designed to meet the most demanding
specifications and is perfect for any industrial application where
improved light levels are needed at minimum energy consumption for
more than a decade.
Vigilant® LED High Bay
125 LPW
Dual Bracket
Dimensions in inches [mm]
1.88
[47.75]
6.88
[174.75]
16.00
[406.40]
1.95
[49.53]
3.00
[76.20]
16.00
[406.40]5/16’’-18x.75’’
THREADED (2)
Dimensions in inches [mm]
10’
[3.05m]
cord
www.dialight.com
2015 Electric IRP Appendix D
809
Part
Number
Initial Fixture
Lumens Watt
Lumens
Per
Watt
CCT
UL-1598, IP-66, NEMA 4X
CSA 22.2 #250,
Marine Wet Locations
Safety
Bracket
External
Fuse Lens
Optical
Pattern
Circular Wide
110 - 277V AC Models
HEGMC4PN-SNG 26,500 212W 125 5,000K •Tempered Glass •
HEGRC4PN-SNG 26,500 212W 125 5,000K •Tempered Glass •
HEGMN4PN-SNG 24,250 212W 114 4,000K •Tempered Glass •
HEGRN4PN-SNG 24,250 212W 114 4,000K •Tempered Glass •
HEGMC4PN-SSG 26,500 212W 125 5,000K ••Tempered Glass •
HEGRC4PN-SSG 26,500 212W 125 5,000K ••Tempered Glass •
HEGMN4PN-SSG 24,250 212W 114 4,000K ••Tempered Glass •
HEGRN4PN-SSG 24,250 212W 114 4,000K ••Tempered Glass •
HEGMC4PN-SFG 26,500 212W 125 5,000K •Tempered Glass •
HEGRC4PN-SFG 26,500 212W 125 5,000K •Tempered Glass •
HEGMN4PN-SFG 24,250 212W 114 4,000K •Tempered Glass •
HEGRN4PN-SFG 24,250 212W 114 4,000K •Tempered Glass •
HEGMC4PN-SGG 26,500 212W 125 5,000K ••Tempered Glass •
HEGRC4PN-SGG 26,500 212W 125 5,000K ••Tempered Glass •
HEGMN4PN-SGG 24,250 212W 114 4,000K ••Tempered Glass •
HEGRN4PN-SGG 24,250 212W 114 4,000K ••Tempered Glass •
100 - 277V AC Models
HEGMC4KN-SNG 18,000 144W 125 5,000K •Tempered Glass •
HEGRC4KN-SNG 18,000 144W 125 5,000K •Tempered Glass •
HEGMN4KN-SNG 16,500 144W 114 4,000K •Tempered Glass •
HEGRN4KN-SNG 16,500 144W 114 4,000K •Tempered Glass •
HEGMC4KN-SSG 18,000 144W 125 5,000K ••Tempered Glass •
HEGRC4KN-SSG 18,000 144W 125 5,000K ••Tempered Glass •
HEGMN4KN-SSG 16,500 144W 114 4,000K ••Tempered Glass •
HEGRN4KN-SSG 16,500 144W 114 4,000K ••Tempered Glass •
HEGMC4KN-SFG 18,000 144W 125 5,000K •Tempered Glass •
HEGRC4KN-SFG 18,000 144W 125 5,000K •Tempered Glass •
HEGMN4KN-SFG 16,500 144W 114 4,000K •Tempered Glass •
HEGRN4KN-SFG 16,500 144W 114 4,000K •Tempered Glass •
HEGMC4KN-SGG 18,000 144W 125 5,000K ••Tempered Glass •
HEGRC4KN-SGG 18,000 144W 125 5,000K ••Tempered Glass •
HEGMN4KN-SGG 16,500 144W 114 4,000K ••Tempered Glass •
HEGRN4KN-SGG 16,500 144W 114 4,000K ••Tempered Glass •
For 347 - 480V AC applications, consult factory
Vigilant® LED High Bay - Ordering Information
Circular Pattern Wide Pattern
www.dialight.com
Optical Patterns
2015 Electric IRP Appendix D
810
Part Number Description Kit Includes
HBXDUALBRCKT Dual Bracket Junction Box
No Part Number Pendant Mount
(conduit supplied by installer)Conduit supplied by installer
HBXW2 Swivel Bracket and Cable Gland
Swivel Bracket
Bracket to fixture hardware
Cable Gland (1/2”), Reducer (3/4” to 1/2”)
HBXW3 Swivel Bracket Swivel Bracket
Bracket to Fixture Hardware
HBXCU Ceiling Mount Swivel Hanger Cover
3" Conduit Nipple
HBXCG Cable Gland Cable Gland (1/2”)
Reducer (3/4” to 1/2”)
HBXL
Loop
(consult factory when
using with occupancy sensor models)
Hanger Loop
(GE LOOPM353)
HBXH
Hook
(consult factory when
using with occupancy sensor models)
Hanger Hook
(GE HOOKM353)
HBXCAB48 48” Long Stainless Steel Safety Rope 5/32” Diameter Stainless rope
with locking spring clip
HBXTH3474801
Top hat with 347-480V isolated
step down transformer
(consult factory when using with hook or loop)
Top and bottom clam shell
Conduit nipple
6’ STOOW cable
347-480V step down transformer
Fuse holder, 2 Fuses
HBXLENGC Tempered Glass Lens, replacement clips, screws, gasket
HBXREF22 22” Acrylic Reflector (must be ordered with High
Bay, not a retrofit option)Reflector, brackets, screws
HBXDC Dust Cover Dust cover, clamp, spacer
www.dialight.com
Vigilant® LED High Bay
Options and Accessories
1Top hat cannot be used with a mounting bracket
2015 Electric IRP Appendix D
811
www.dialight.com
Vigilant® LED High Bay
Options and Accessories
Dimensions in Inches [mm]
CUSTOMER SUPPLIED 4" SQUARE BOX AND CONDUIT
SWIVEL MOUNT
3/4"X3" RIGID CONDUIT
16.00
[406.40]
8.50
[215.90]
16.00
[406.40]
2.00
[50.80]
10’ [3.05m] cord
CABLE GLAND
5.00
[127.00]
Dimensions in Inches [mm]
Dimensions in Inches [mm]
HBXCU - Ceiling Mount HBXCG - Cable Gland
HBXTH347480 - Top Hat (fixture sold separately)
HBXDUALBRCKT - Dual BracketHBXW2 - Swivel Bracket and Cable Gland
HEGMxxxx-SGG - Safety Bracket and Fuse Options
Dimensions in Inches [mm]
Dimensions in Inches [mm]
2015 Electric IRP Appendix D
812
Dialight reserves the right to make changes at any time in order to supply the best product possible. The most current version of this
document will always be available at: www.dialight.com/Assets/Brochures_And_Catalogs/Illumination/MDEXHB125X001.pdf
Warranty Statement: EXCEPT FOR THE WARRANTY EXPRESSLY PROVIDED FOR [HEREIN/ABOVE/BELOW], DIALIGHT DISCLAIMS ANY AND ALL OTHER WARRANTIES, EXPRESS OR IMPLIED,
INCLUDING, WITHOUT LIMITATION, ANY WARRANTIES OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, TITLE, AND NONINFRINGEMENT.
MDEXHB125X001_Cwww.dialight.com
Dimensions in Inches [mm]
HBXREF22 - 22” Acrylic ReflectorHBXDC - Dust Cover
Dimensions in Inches [mm]
Vigilant® LED High Bay
Options and Accessories
2015 Electric IRP Appendix D
813

Energy Efficiency Improvements
Audit Report

Prepared for
Kettle Falls Generating Facility

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

March 24, 2015

2015 Electric IRP Appendix D
814

Overview

Facility: Kettle Falls
Audited by: Andy Paul PE
Onsite Staff: Mike Floener and
Facility Audited on: March 5th, 2015

Figure 1

this audit wa
generation process.
including capital projects as well a

and Levi Westra PE

Google Earth Images of the Kettle Falls Generation Facility
Avista’s DSM Engineering staff visited the Kettle Falls
-cost no-

generating facility to review their current building
systems and discuss several concerns that the user’s encountered during typical operation. Specifically,
s conducted to identify all possible energy efficiency improvements not related to the power
After completing a tour of the facility potential improvement measures were identified for consideration
cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
2015 Electric IRP Appendix D
815

historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
The facility consists of office space, network room, shop areas, and 7 story high bay warehouse which
contains the hog fuel boiler and steam turbine. In addition there are several outbuildings that house the
water treatment facility, and other generating equipment.
Shell
There are several areas around the facility where additional weatherization work can be conducted.
1. The roll up doors could use new weather stripping along the outside edges of the doors and along
the bottom. A noticeable draft can be felt when you stand next to the doors.

2. The man doors would also benefit from additional weather stripping.

These measures are applicable to the main plant area; this area is conditioned by waste heat off the
boiler. The measures would apply to the support buildings, machine shop, and office space. While these
measures will conserve energy, those savings will be negligible in comparison to the measure listed
further in this report.
Lighting
The site employs T12 and T8 linear fluorescent lighting as well as 250 Watt High Pressure Sodium (HPS)
high-bay, 70 Watt mercury vapor (MV) yard light and 1000W MV yard lights. The lights in the plant
operate 24/7, yard lights operate dusk to dawn (4,288 hrs/yr), and it is assumed that the office lights
operate 2,080 hrs/yr.

Table 1 Capital Project Lighting Opportunity Summary
Brief EEM*
Description
EEM
Cost
Measure
Life
Electric
kWh
Savings
1 Plant Lighting $56,515 20 yrs 150,190
2 Plant Lighting
Controls $66,515 20 yrs 183,058
3 Yard Lighting $19,099 20 yrs 48,180
*EEM – Energy Efficiency Measure

1. Proposed Project #1: The facility currently has (x127) single lamp 250W high pressure sodium
fixtures in the main plant area. The main plant is seven floors; the lighting count includes each
floor and the stairwell lighting. The fixtures operate 24/7, 8,760 hrs/yr. The proposed project looks
at replacing these fixtures with (x127) single lamp 160W LED low bay fixtures, CREE CXB. A
simple lumen calculation shows that the overall lumens for the job were decreased by 18.5%.
o The provided project is $56,515, this cost was calculated using fixture costs, $370 per
fixture, off the internet and estimated labor costs, $75 per fixture.
2015 Electric IRP Appendix D
816

o It should be noted that the fixture count used for this analysis is as close as could be
done while on site. If more fixtures are found the kWh savings and project cost will go up.
2. Proposed Project #2: This project looks at the additional savings that could be seen by installing
occupancy sensors to the main generating facility. The controls proposed would leave 67 of the
fixtures on 24/7 and the remaining 60 would only come on when someone is present in the
space. This would reduce the operating hours for the 60 fixture by an estimated 35%.
o The provided project is an additional $10,000 over the straight replacement project. This
cost is purely an estimate and should be verified by a lighting professional. A high cost
was estimated due to the complexity of the controls required for the space. Since the
flooring in the plant is all metal grate there is a potential the lights on floor 6, for example,
may come on when someone walks by on floor 5. To operate properly the sensors would
need to be calibrated to only pick up on motion on the floor that they are located on.
3. Proposed Project #3: The facility currently has (x27) single lamp 70W mercury vapor fixtures and
(x13) 1000W mercury vapor fixtures lighting up the yard. The fixtures operate dusk to dawn,
4,288 hrs/yr. The proposed project looks at replacing these fixtures with (x27) single lamp 52W
RAB LED pole fixtures and (x13) single lamp 300W LED street lights, MaxLite Merek Series. A
simple lumen calculation shows that the overall lumens for the job were decreased by 30%.
o The provided project is $19,099, this cost was calculated using fixture costs, $499 per
300W fixture and $356 per 52W fixture, off the internet and estimated labor costs, $75
per fixture.
o It should be noted that the fixture count used for this analysis is as close as could be
done while on site. If more fixtures are found the kWh savings and project cost will go up.
4. It should be noted that while the total system lumens decrease for each of these projects, the
actual lumens that reach the working space will more the likely increase. LED fixtures are very
directional in the way they deliver lighting lumens. We recommend replacing a few light fixtures to
make sure that they will meet your lighting needs. If you would like to see the fixtures in operation
we recommend a trip to Noxon Rapids HED.
HVAC
1. The control room, restrooms, break room, and office space are conditioned by several gas fired
roof top units. Some of these units have been replaced recently and the remaining units have
been in service for a while. We were unable to determine the efficiency of the existing units. While
there are newer units available that have efficiencies closer to SEER 19, the cost to purchase and
install these units outweighs the potential energy savings. Our recommendation is to replace
these units when they have reached their end of life. When you do replace these units purchase
the most efficient units that can be afforded. It should also be noted the units use R-22
refrigerant, this refrigerant is no longer being manufactured. Should a unit need to be recharged
you should consider replacing it with a high efficient unit at that point.

2. The generation floor has several natural gas unit heaters on each floor to provide supplemental
heat. These units are only used during shutdowns. Due to the low annual usage it would not be a
cost effective project to replace them. In the future when these units are at end of life we
recommend purchasing and installing the most efficient units that can be afforded.

3. The machine shop has several natural gas radiant tubes to provide space heat. This type of
heating in a shop area is an efficient option since it focuses on heating the occupants and not the
surrounding area. It is important to have the thermostats set appropriately for this type of heat
though. You want to set the temperature around 55º and have the thermostat closer to the ground
than a typical installation. This will insure that the units are not heating the airspace to 55º and
are instead only providing occupant comfort.
2015 Electric IRP Appendix D
817

Boiler Forced Draft Blower System

The site employs a wood fired boiler to generate steam to drive a turbine. The boiler relies on a Forced
Draft (FD) and Induced Draft (ID) fans driven by single-speed motors to provide combustion air. Currently
combustion air flow-rates through the FD are regulated using inlet dampers which are open/closed
depending on desired plant output and combustion performance. There is an opportunity to reduce
average blower power draw and energy consumption using a Variable Frequency Drive (VFD).

Brief EEM*
Description
Roughly
Estimated
EEM
Cost
Measure
Life
Electric
kWh
Savings
1 FD Fan
VSD $510,000 15 yrs 700,000

1. Adjusting blower speed is the most efficient way to vary airflow rates. Based on SCADA, from a
2012 analysis, which documents plant gross output, FD fan current draw, and FD damper
position, an estimated 700,000 kW*hr of energy could be “saved” using a VFD. A summary of the
analysis, assumptions and results is appended to this document.
Please note that during the 2015 site audit, the operations staff indicated that some processes
and equipment had been changed since 2012 that reduced the average damper position from
~65% to ~50%. This has a noticeable impact on estimated energy savings. The value presented
above is the average of the two configurations.

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.
Respectfully,
Andy Paul, Bryce Eschenbacher, and Levi Westra – March 24th, 2015

2015 Electric IRP Appendix D
818
Acct#
Existing Annual Consumption: (kilowatt hours) 328,193.40
Lighting Energy Savings:(kilowatt hours)150,190.20
Lighting Demand Savings: (kilowatt demand)13.72
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 81.45%
Total Energy Savings: (kilowatt hours)150,190.20
Total Demand Savings: (kilowatt demand)13.72
Estimated Project Cost: (Rough Estimate)$73,152.00
Customer Supplied Cost $0.00
Heating System Penalty: (therms)0.00
Maintenance Savings:$549.75
Costs updated on 1/0/1900
Use Short Form Report
AE
Name: Kettle Falls Generating Facility - Main Plant Lighting
Jayson Hunnel
Main_Plant_Lighting_032315 Report Pg 1 - 1 6/9/20152015 Electric IRP Appendix D
819
Acct#
Existing Annual Consumption: (kilowatt hours) 328,193.40
Lighting Energy Savings:(kilowatt hours)183,057.72
Lighting Demand Savings: (kilowatt demand)13.72
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 81.45%
Total Energy Savings: (kilowatt hours)183,057.72
Total Demand Savings: (kilowatt demand)13.72
Estimated Project Cost: (Rough Estimate)$83,152.00
Customer Supplied Cost $83,152.00
Heating System Penalty: (therms)0.00
Maintenance Savings:#DIV/0!
Costs updated on 01-00-1900
Use Short Form Report
AE
Name: Kettle Falls Generating Facility - Main Plant Lightign w/ controls
Jayson Hunnel
Main_Plant_LightingControls_032315 Report Pg 1 - 1 03-23-20152015 Electric IRP Appendix D
820
Acct#
Existing Annual Consumption: (kilowatt hours) 70,923.52
Lighting Energy Savings:(kilowatt hours)48,179.97
Lighting Demand Savings: (kilowatt demand)8.99
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 69.68%
Total Energy Savings: (kilowatt hours)48,179.97
Total Demand Savings: (kilowatt demand)8.99
Estimated Project Cost: (Rough Estimate)$19,099.00
Customer Supplied Cost $0.00
Heating System Penalty: (therms)0.00
Maintenance Savings:$453.66
Costs updated on 1/0/1900
Use Short Form Report
AE
Name: Kettle Falls Generating Facility - Yard Lights
Jayson Hunnel
Yard_Lighting_032315 Report Pg 1 - 1 6/9/20152015 Electric IRP Appendix D
821
Customer: Avista Generation; Kettle Falls Generation station ID/FD Fan VSD evaluation
Project State: EEM Evaluation
Date: 05/14/15
Analysis Description:
-Estimate the possible energy savings of converting the facility's ID/FD combustion blower to variable
speed control.
-Assume that air-flow rates are proportional to generation rate.
-Assume the EEM will open the damper to 100%, combustion air flow-rate controlled via blower speed.
-Assume 4180 VAC nominal voltage and 0.7 power factor.
Inputs:
Table 1. Binned operational data from
2012 SCADA data. See excel worksheet
"KF GS FD ID Fan VSD eval 101712.xlsm"
Figure A. Image of the FD damper actuator during 2015
audit. Note the position ~50%.
15 May 2015 09:21:19 - KF Blower Analysis 0581415.sm
1 / 4
2015 Electric IRP Appendix D
822
Figure 1. Graph of FD damper position versus averaged
fan current draw. Sourced from SCADA data. Note the
R2 value which indicates fan current is directly effected
by damper position. Note the blower motor is 4180 volt.
Figure 3. Typical damper performance from HVAC
handbook. Assumes closed damper is ~25% of duct system
total pressure drop
Figure 2. Graph of Station's power output vs damper positon.
Note that the R2 value is somewhat low, this indicates that
there are other variable effecting the output; likely fuel
type, humidity, moisture content, air temperature.
15 May 2015 09:21:19 - KF Blower Analysis 0581415.sm
2 / 4
2015 Electric IRP Appendix D
823
Table 2. Example of baseline and EEM FD fan analysis, based upon 2012 SCADA data
and typical performance of dampered and VSD controlled blowers. See Excel worksheet
"KF GS FD ID Fan VSD eval 101712.xlsm" for actual calculations.
Table 3. Summary of FD EEM performance based upon
2012 SCADA data.Table 4. Summary of FD EEM performance based on
operator input that due to recent facility
equipment changes that the FD blower has been
operating with damper ~50% open.
15 May 2015 09:21:19 - KF Blower Analysis 0581415.sm
3 / 4
2015 Electric IRP Appendix D
824
Simple Payback Analysis
1dollar
hrkW
dollar0.07rateele
input: assumed average value of the energy commodity.
2
yr
hrkW850000
yr
hrkW600000
Esavings calc: estimated annual energy savings of the VFD.
yr
hrkW725000Esavings
rateeleEsavingsSales
calc: estimated increase in energy sales.
yr
150750Sales
hp
dollar1000rateVFD_MV input: estimate of typical medium voltage VFD installation cost.
hp300PVFD input: estimated VFD size.
PVFDrateVFD_MVCostproject
calc: rough estimate project cost.dollar300000Costproject
Sales
CostprojectSPB
calc: energy simple payback of the EEM.
yr5.9SPB
15 May 2015 09:21:19 - KF Blower Analysis 0581415.sm
4 / 4
2015 Electric IRP Appendix D
825

Energy Efficiency Improvements
Audit Report

Prepared for
Little Falls Generating Facility

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

February 13, 2015

2015 Electric IRP Appendix D
826

Overview

Facility: Little Falls Hydro Electric Dam
Audited by: Andy Paul PE
Onsite Staff:
Facility Audited on: February 10th
Figure 1

PE, and Levi Westra PE
th, 2015

Google Images of Little Falls Hydro Electric Dam
Avista’s DSM Engineering staff visited the Little Falls Hydro Electric Dam

to review their current building
systems and discuss several concerns that the user’s encountered during typical operation.
2015 Electric IRP Appendix D
827

Specifically, this audit was conducted to identify all possible energy efficiency improvements not related to
the power generation process.
After completing a tour of the facility potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
It should be noted that this facility is currently undergoing a complete overhaul. Due to this there
are very few projects that can be suggested that are not already going to be implemented.
The facility consists of a control room and generation specific process areas including but not limited to
generation floor and breaker floor.
Shell
There are several areas around the facility where additional weatherization work can be conducted:
All exterior entry doors should have their weather stripping checked and replaced if necessary.
All windows that are not required to remain historically accurate should be replaced with energy efficient
double pane windows.
Any portion of the plant that is going to have cooling installed; control room, battery room etc, should have
the walls and ceiling insulated. The insulation will help thermally isolate it from the rest of the plant and
reduce the amount of cooling required in the summer time.
There is currently little to no insulation above or below the roof deck in the plant. It is recommended that
insulation, R-19 at the very least, be added below the deck. This insulation will aid in reducing the amount
of time a unit has to be motored during the winter months to maintain space temperature.

Lighting
The facility currently employs T12 fluorescent lighting in the control room and surrounding areas and 400
Watt Metal Halide (MH) high-bay fixtures on the generating floor. The facility will have a brand new all
LED lighting system installed during the overhaul. The DSM group at Avista made suggestions on what
LED fixtures would be appropriate. Nathan Fletcher in the Generation Dept was in charge of the lighting
design.
While there will be energy savings for this project, specifically with the generating floor lighting as well as
the control room lighting, there will also be an additional lighting load installed. There are portions of the
plant that were under lit and needed additional lighting fixtures installed. Regardless of the additional
lighting fixtures, the new system will be as efficient as possible due to the installation of the LED fixtures
in lieu of more traditional linear fluorescent and HID fixtures.

HVAC
The control room and few other areas in the plant will be getting new HVAC units installed to heat and
cool the spaces. When selecting equipment considered installing the most efficient units that can be
afforded. It is also recommended that heat pump units be installed instead of standard condensing units
with electric resistive heat. New heat pumps are capable of working efficiently down to temperatures
below zero. Since no natural gas is available at the Dam a heat pump is by far the most efficient way to
provide space heat.
The main generating floor has no dedicated HVAC units. The heat from the generators keeps the space
conditioned during the winter months. A generator will be motored to maintain heat if no generation is
going on. It is recommended that dedicated HVAC units be installed to maintain the space temperature
2015 Electric IRP Appendix D
828

when the units are not running. This would reduce unnecessary wear and tear on the generating
equipment as well as provide a known dedicated source of heat.
Installing two (possibly three) low speed/high volume destratification fans to help de-stratify the air within
in the facility is recommended. With 40’ ceilings the majority of buildings heated air will stack at the top,
the fans would push that heated air back towards the floor and create a homogenous air temperature.
This would reduce the amount of time that the space heat would need to run.
In addition these fans could be run in reverse during the summer months to help pull warm air off the floor
and exhaust it out of the exhaust louvers located in the roof.

Process
Brief EEM*
Description
Rough
EEM
Cost
Est.
Measure
Life
Electric
kWh
Savings
1
Speed Controls
Cooling/Exhaust
Fans
$10,000 16 yr 247,909

The facility employs (4) exhaust fans, for ventilating the generator room, and (4) cooling fans for cooling
the generation equipment. Currently the fans are controlled manually, turning fans on and off as needed;
fans are operated independently, with units powered on as ventilation/cooling is required. There are
some energy savings if the fans were each controlled automatically using Variable Frequency Drives
(VFDs). The estimated savings is based upon switching from a manual control system to one that relies
on indoor air temperature and equipment temperatures to power on and vary fan speeds to maintain
temperatures. Reducing fan speeds reduces power requirements exponentially, resulting in the energy
savings. A copy of the SMath Studio model and analysis is appended to the end of this document.

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.

Respectfully,

Andy Paul, Bryce Eschenbacher, Levi Westra, February 13th, 2015
2015 Electric IRP Appendix D
829
Customer: Avista Generation; Little Falls Hydro Generation Station
Project State: Scoping Audit
Date: 03/04/15
Analysis Description: Evaluate the possible energy savings of retrofitting generation floor cooling and exhaust fans with
variable speed drives.
Assumptions:
1. System is 3 ph 480VAC (nominal)
2. Units sized for 60% of their service
3. Baseline fan units operate 24/7/365
4. EEM operation is dependent on outside air temperature
5. Power factor nominal 0.80
Inputs:
100
1pct input- assign percentage
V480Vnom input- assign nominal supplied voltage
input - assign assumed operational power factor0.80PF
input - number of exhaust fans4Qtyexhaustinput - number of cooling fans4Qtycooling
input - exhaust fan breaker/circuit sizeA15Abreaker_exh
input - cooling fan breaker/circuit sizeA50Abreaker_cooling
input - assumed sizing factor; percent power draw based on circuit sizepct60Fservice
input - assumed generator annual duty cycle; based on long lake
VFD project notes.pct69Dutycycle
2.5n input - exponent for affinity law power calculations
9 Jun 2015 14:09:37 - Little Falls Dam_EEM Eval_Exhaust Cooling Fan_030415.sm
1 / 3
2015 Electric IRP Appendix D
830
Calculations:
3PFFserviceVnomAbreaker_exhPexhaust
kW6Pexhaust
3PFFserviceVnomAbreaker_coolingPcooling
kW20Pcooling
Savings based on Spokane bin data
Table 1. Results from Excel Worksheet Bin analysis.
9 Jun 2015 14:09:37 - Little Falls Dam_EEM Eval_Exhaust Cooling Fan_030415.sm
2 / 3
2015 Electric IRP Appendix D
831
calc - total annual baseline nergy consumption of the exhaust and
cooling fans; assumes 69% duty cycle, 60% sizing factor and
linear reduction in # of fans operated based on binned
outside temperature data for Spokane area. Reference Excel worsheet
"Little Falls DAm_EEM Eval_Exhaust Cooling Fan_030415.xls" for
details. A copy of the worksheets results is above in table 1.
hrkW345345hrkW103604Ebaseline
calc - total annual EEM energy consumption of the exhaust and
cooling fans; assumes 69% duty cycle, 60% sizing factor and
linear reduction in fan speeds based on binned
outside temperature data for Spokane area.
see excel worksheet "Little Falls DAm_EEM Eval_Exhaust Cooling
Fan_030415.xls" for details.
hrkW154646hrkW46394EEEM
EEEMEbaselineEsavings
hrkW247909Esavings
Double check of above model
9 Jun 2015 14:09:37 - Little Falls Dam_EEM Eval_Exhaust Cooling Fan_030415.sm
3 / 3
2015 Electric IRP Appendix D
832

Energy Efficiency Improvements
Audit Report

Prepared for
Long Lake Hydro Electric Dam

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

February 13, 2015

2015 Electric IRP Appendix D
833

Overview

Facility: Long Lake Hydro Electric Dam
Audited by: Andy Paul PE, Bryce Eschenbacher PE, and Levi Westra PE
Onsite Staff:
Facility Audited on: February 10th, 2015

Figure 1 Google Images of the Long Lake Hydro Electric Dam

Avista’s DSM Engineering staff visited the Long Lake Hydro Electric Dam to review their current building
systems and discuss several concerns that the user’s encountered during typical operation. Specifically,
this audit was conducted to identify all possible energy efficiency improvements not related to the power
generation process.
2015 Electric IRP Appendix D
834

After completing a tour of the facility potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
The facility consists of a control room, office space, break area and generation specific process areas
including but not limited to generation floor and breaker floor.
Shell
There are several areas around the facility where additional weatherization work can be conducted.
1. All exterior entry doors should have their weather stripping checked and replaced if necessary.

2. All windows that are not required to remain historically accurate should be replaced with energy
efficient double pane windows.

3. Any portion of the plant that currently has heating or cooling installed should have the walls and
ceiling insulated. The insulation will help thermally isolate it from the rest of the plant and reduce
the amount of cooling required in the summer time.

4. There is currently little to no insulation above or below the roof deck in the plant. It is
recommended that insulation, R-19 at the very least, be added below the deck. This insulation will
aid in reducing the amount of time a unit has to be motored during the winter months to maintain
space temperature.

Lighting
The site employs T12, T8 and T5 linear fluorescent lighting as well as 400 Watt Metal Halide (MH) high-
bay and 250 Watt MH exterior lighting on dusk to dawn sensors. No parking lot lighting was observed.

Table 1 Capital Project Lighting Opportunity Summary
Brief EEM*
Description
EEM
Cost
Measure
Life
Electric
kWh
Savings
1 Generating
Floor High
Bays
$18,252 20 yr 17,441
2 Exterior Wall
Packs $1,339 20 yr 2,084
*EEM – Energy Efficiency Measure

1. Proposed Project #1: The facility currently has (x11) single lamp 400W Metal Halide fixtures and
(x8) single lamp 1000W incandescent fixtures lighting the main generation facility. It is assumed
that the lights are on for an average 3,600 hrs a year. The proposed project looks at replacing
these fixtures with (x30) 200W linear LED high bay fixtures. A simple lumen calculation shows
that the overall lumens for the job were decreased by 43%.
o The provided project is $18,252, this cost was calculated using fixture and install costs for
these fixtures at Noxon Rapids HED.
2. Proposed Project #2: The facility currently has (x2) single lamp 250W high pressure sodium
cobra head fixtures outside the main entry door. The fixtures average 4,288 hrs (dusk to dawn) of
2015 Electric IRP Appendix D
835

operation a year. The proposed project looks at replacing these fixtures with (x2) 52W LED wall
packs. A simple lumen calculation shows that the overall lumens for the job were decreased by
73%.
o The provided project cost is $1,336, this cost was calculated using fixture and install
costs for these fixtures at Noxon Rapids HED.
3. It should be noted that while the total system lumens decrease for each of these projects, the
actual lumens that reach the working space will more the likely increase. LED fixtures are very
directional in the way they deliver lighting lumens. We recommend replacing a few light fixtures to
make sure that they will meet your lighting needs. If you would like to see the fixtures in operation
we recommend a trip to Noxon Rapids HED.
4. In addition to the projects listed above there are several other areas that would benefit from
installing new lighting fixtures.
• The control room and machine shop both have 2L T12 fluorescent fixtures that should
be replaced with the new LED fixtures or at the very least 2L T8 fluorescent fixtures.
• The breaker floor is severely under lit and would greatly benefit from additional lighting
fixtures being installed. There is no chance of energy savings in this case since there
are only 5 light fixtures in the entire area. The greater benefit would be the increased
worker safety and having more light to perform work.
• The generator floor entry hallway is lit by 100W incandescent fixtures. It is
recommended that these be replace with a comparable 20W LED screw in lamp or at
the very least a 23W compact fluorescent lamp.
HVAC
1. During the walk through it was mentioned that the control room has a dedicated cooling system
but no heating, the generators provide heat for the facility. It is recommended that some type of
supplemental electric heat be installed to heat the control room.
2. The main generating floor has no dedicated HVAC units. The heat from the generators keeps the
space conditioned during the winter months. A generator will be motored to maintain heat if no
generating is going on. It is recommended that dedicated HVAC units be installed to maintain the
space temperature when the units are not running. This would reduce unnecessary wear and tear
on the generating equipment as well as provide a known dedicated source of heat.
3. Installing two (possibly three) low speed/high volume destratification fans to help de-stratify the
air within in the facility is recommended. With 40’ ceilings the majority of buildings heated air will
stack at the top, the fans would push that heated air back towards the floor and create a
homogenous air temperature. This would reduce the amount of time that the space heat would
need to run.
In addition these fans could be run in reverse during the summer months to help pull warm air off
the floor and exhaust it out of the exhaust louvers located in the roof.

2015 Electric IRP Appendix D
836

Process
Brief EEM Description
Annual
Electric kWh
Savings
Variable Speed Stator
Cooling Blowers 135,000

 Generator cooling fan controls- The (4) hydro-turbine power generators require cooling to operate
reliably. Currently the operators operate (4) 100 hp blowers to circulate air from a plenum located
below the generators. The blowers operate at a fixed speed forcing outside air to maintain stator
temperatures. In the winter the outside air temperature is too low, louvers/baffles are manually
opened to re-circulate pre-heated air from within the generator room to keep stator temps from
dropping. The EEM would automatically adjust blower speed to reduce flow of the colder outside
air across the stators instead of re-circulating pre-heated air eliminating the baffle/louver
operation. Because blowers are variable torque devices power consumption is exponentially
related to blower speed. The above estimated savings is the annual estimated energy savings
based on average yearly temperatures, one time measured power draw, stator temperature
goals, and affinity laws for four stators. A copy of the analysis is appended to this document.

Figure 2 Long Lake generator.
2015 Electric IRP Appendix D
837

Figure 3
Figure 4

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.
Respectfully,

Long Lake dam generator passage for cooling air.

Long Lake stator cooling blower (left) and motor (right).
We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
Andy Paul, Bryce Eschenbacher, and Levi Westra – February 13th, 2015

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
2015 Electric IRP Appendix D
838
Created by:
Levi Westra, DSM Engineer
last saved: 02-03-2010
C:\Documents and Settings\lww6153\Desktop\temp
\Long Lake Power Generation VFD\Avista Long
Lake Power Gen VFD Fans rev 02 123009.xmcd
1 of 26
Customer: Long Lake Dam;
Project: Cooling Fan VFD Drive Evaluation
Date: 01/07/10
Define the Situation:
Randy Gnaedinger contacted Tom about having the team evaluate the possible benefits of installing VFD drives on the (4) ~100hp
generator cooling fans at the Long Lake Dam. Tom, Andy and I visited the site on 12/30/09. We met with Bill Maltby, the
facility's chief operator. He gave us a tour. We took air temperature, air speed, air flow rate, plenum, and power measurements
of the (4) operating fan units.
Goals:
1. Determine fan speeds required maintain stator temperature at 60°C (ideal operational temp)
2. Evaluate power draw of fans at required fan speeds
3. Compare power draw with EEM to power draw without EEM
Assumptions:
-system is steady state, no accounting for stator/generator mass
-air temperature measured supplying fan #5 was 74°F, while air temp supplying fan #1 was 53°F. It is assumed that this is
attributed to the team leaving the access door open to the plenum during the tour. For this analysis I will use 53°F as the
baseline for all of the fans.
-this analysis does not account for the effect VFDs will have on the air temperature within the generator room.
-assume that the louvers in the room will no longer be used to control fan supply air temp. fans will draw only outside air,
temperature will be purely ambient.
-assume the dry bulb temperaure equals the wet bulb temperature of air coming out of air washers which will assume is equal to
the dew point temp pluse 2°F (conservative); unless the water temperature exceeds the dew point, at which point employ the
water temperature.
-assume the dry bulb temp is equal to the ambient temperature when the air washer is not being used (winter months).
-apply infinity fan laws to estimate fan speed and power based on air flow needs
-assumed that the air washers would be employed shortly after the last freezing potential in the spring, and discontinued once
freezing temperatures were encountered in the fall. Reviewed 1987 data, and it appears assuming air washers come on line
begining in May and taken offline begining in October is appropriate. Currently there is no schedule for air washers. The
2015 Electric IRP Appendix D
839
Avista Long Lake Power Gen VFD Fans rev 02
123009.xmcd
2 of 26
electrician enables the system sometime in the spring when it seems like it won't freeze, and disables the system in the fall
when it starts to get cold. The operators start washing the air once they are unable to maintain stator temps at or below the 60°C
optimal temperature.
-applied a website generated excel equation to calculate wet bulb temp based on dry bulb and releative humidity:
http://www.the-snowman.com/wetbulb2.html
I verified the relative accuracy of the calculation using the pychrometric chart located in the MERM appendix 38.C
-assumed that a VFD turndown ratio at a minimum of 20% did not hinder or cause problems for fan operation
-assumed all four fans are delivering the same air flow to each generator
Inputs:Supporting Results/Comments:
measured 74°F air coming through the access door to the plenum, for a conservative
estimate I added a fudge factor. tempair_exit_stator 76°F 297.6 K=:=
tempstator 60°C 333.1 K=:=this is the target stator temperature. facilities team adjusts internal louvers and air washer
operation in order to maintain this temperature at 60°C
tempfan1_air 60°F 288.7 K=:=measured temperature of air supplied to fan #1 during visit on 12/30/09
air_speedfan1 1900 ft
min:=measured average air speed using the kestrel
air_speedfan5 2500 ft
min:=measured average air speed using the kestrel
Xareaplenum_fan5 39in 81⋅in 21.9 ft2⋅=:=measured plenum cross-secitonal area, note plenum 5 does not share the same
dimensions with 1-4.
Xareaplenum_fan1to4 48in 96⋅in 32 ft2⋅=:=measured plenum cross-sectional area, note fans 1-4 all share the same plenum size
air_flowfan5 44000 ft3
min:=measured air flow rate using kestrel hand held meter using plenum dimensions inputted into
unit.
2015 Electric IRP Appendix D
840
Avista Long Lake Power Gen VFD Fans rev 02
123009.xmcd
3 of 26
powerfan1 75kW:=measured power draw by fan #1 during tour
powerfan2 7kW:=
powerfan4 19kW:=
powerfan5 36kW:=
average_duty 69%:=typical duty cycle of each of the (4) generators per year.
sanity check on kestrel air
flow measurementηsat_air_washer 90%:=air_flow_calcfan5 air_speedfan5 Xareaplenum_fan5⋅54843.7 ft3
min⋅=:=
ηVFD 98%:=
Cpair_290K 1.0048 103⋅J
kg K⋅:=specific heat of air at a mixing cup temperature of 290K ref. MERM ap.35.D
density of air at a mixing cup temp of 290K ref MERM ap.35.Dρair_290K 1.246 kg
m3 0.1 lbm
ft3⋅=:=
Calculations:
Goal #1
Estimating Power rejected by Gen 1 as heat
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tempair_mixing_cup
tempair_exit_stator tempfan1_air+
2 293.1 K=:=1000kW
20 106W⋅
5 %=
air_flow_calcfan1 air_speedfan1 Xareaplenum_fan1to4⋅60800 ft3
min⋅=:=
mdot_fan1 air_flow_calcfan1 ρair_290K⋅4729.3 lbm
min⋅=:=
heat_transferstator mdot_fan1 Cpair_290K⋅tempair_exit_stator tempfan1_air−( )⋅319.3 kW⋅=:=estimated amount of heat being
rejected to air by generator #1
after a discussion with Randy, to be better represent actual generator
efficiency (~95%) I assigned 1 MW to be rejected via forced convection.
Overroad my heat calculation and forced 1MW rejection into model
heat_transferstator 1MW:=
Estimating Power rejected by Gen 1 as heat
Generator 1 - Final Analysis with weather and gen schedule data
Data Imports from GEG Bin data 1987
Tempdrybulb_hourly C:\Documents and Settings\lww6153\Desktop\temp\Long Lake Power Generation VFD\typical year hourly weather GEG.xls:=
Tempest_wetbulb_hourly C:\Documents and Settings\lww6153\Desktop\temp\Long Lake Power Generation VFD\typical year hourly weather GEG.xls:=
schedulegenerator_1 C:\Documents and Settings\lww6153\Desktop\temp\Long Lake Power Generation VFD\long lake generator schedule reduced data.xls:=
factor of safety to approximate some building air recirculation back into the plenum to maintain building air temp above
50F
tempFS 0:=tempdrybulb_out_airwasher Tempdrybulb_hourly tempFS+( )ηsat_air_washer Tempdrybulb_hourly Tempest_wetbulb_hourly−( )⋅−°F:=
calculation of predicted dry bulb air temp leaving the air washers,
calculation referenced from MERM eq 38.34 assumed air washer saturation
efficiency of 90% (conservative value)
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Tempest_wetbulb_hourly
0
98
99
100
101
102
103
104
30
28.9
28.9
28.9
28
28.9
...
=schedulegenerator_1
0
0
1
2
3
4
0
0
0
0
...
=
tempdrybulb_out_airwasher
0
0
1
2
3
4
30
30
30
30
...
°F⋅=results of calculating dry bulb temperature; includes air washer scheduled
operation
assigned a value to the exit air temperature from the
stator; based on best estimate of ideal exit temperature to
maintain stator temperature
tempair__EEM_exit_stator 92°F:=
heat_transferstator 1000kW=
mdot_generator_1
heat_transferstator
Cpair_290K tempair__EEM_exit_stator tempdrybulb_out_airwasher−( )⋅:=
0
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n 8759:=
i 0 n..:=mdot_generator_1
0
0
1
2
3
28.9
28.9
28.9
...
kg
s=
mdot_schedule_generator1i mdot_generator_1i schedulegenerator_1i⋅:=
mdot_schedule_generator1
0
0
1
2
0
0
...
kg
s=adjusting air requirements for when generator is operating. Based on data
obtained from Rodney Picket for hourly generator operation for 2009
air_flowgenerator_1
mdot_schedule_generator1
ρair_290K
:=air_flowgenerator_1
0
5
6
7
8
9
49150.7
49150.7
49874.9
50772.7
...
ft3
min⋅=
air_flow_calcfan1 60800 ft3
min⋅=max air_flowgenerator_1( )189450.2 ft3
min⋅=
fan_speed_percentageEEM_generator_1
air_flowgenerator_1
air_flow_calcfan1
:=fan_speed_percentageEEM_generator_1
0
2029
2030
2031
2032
2033
122.4
122.4
119.3
119.3
...
%⋅=
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need an adjusted fan speed. when fan speed requirements exceed 100% the fan can only deliver that 100%
adjusted_fan_speed fan_speed( ) if fan_speed 1>1, fan_speed, ( ):=
adjusted_fan_speedgen1i adjusted_fan_speed fan_speed_percentageEEM_generator_1i⎛⎝⎞⎠:=
adjusted_fan_speedgen1
0
0
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
0
0
0
0
0.8
0.8
0.8
0.8
0.8
0.9
0.9
0.9
0.9
0.9
0.9
...
=
max adjusted_fan_speedgen1( )100 %⋅=
note from Randy: every year, for approximately 1 week, the sytem's needs exceed flow rate needs
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powerEEM_generator_1
powerfan1
ηVFD
adjusted_fan_speedgen1( )3⋅:=powerEEM_generator_1
0
0
1
2
3
0
0
0
...
kW⋅=
powergenerator_1 schedulegenerator_1 powerfan1⋅:=
powergenerator_1
0
0
1
2
0
0
...
kW⋅=
annual_fan_energyEEM_generator_1 powerEEM_generator_1∑hr⋅380508.9 kW hr⋅⋅=:=estimated power used by generator 1's cooling fan if a
VFD were installed during 2009 operating year
annual_fan_energygenerator_1 powergenerator_1∑hr⋅452925 kW hr⋅⋅=:=estimated power used by generator 1's cooling fan
during 2009 operating year
Generator 1 - Final Analysis with weather and gen schedule data
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Generator 2 - Final Analysis with weather and gen schedule data
schedulegenerator_2 C:\Documents and Settings\lww6153\Desktop\temp\Long Lake Power Generation VFD\long lake generator schedule reduced data.xls:=
mdot_generator_2
heat_transferstator
Cpair_290K tempair__EEM_exit_stator tempdrybulb_out_airwasher−( )⋅:=
mdot_generator_2
0
0
1
2
3
28.9
28.9
28.9
...
kg
s=
mdot_schedule_generator2i mdot_generator_2i schedulegenerator_2i⋅:=
mdot_schedule_generator2
0
0
1
2
3
0
0
0
...
kg
s=
adjusting air requirements for when generator is operating. Based on data
obtained from Rodney Picket for hourly generator operation for 2009
air_flow_calcfan2 air_flow_calcfan1:=
air_flowgenerator_2
mdot_schedule_generator2
ρair_290K
:=air_flowgenerator_2
0
0
1
2
0
0
...
ft3
min⋅=
air_flowgenerator_2
0
0
1
2
3
0
0
0
...
ft3
min⋅=
max air_flowgenerator_2( )189450.2 ft3
min⋅=
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fan_speed_percentageEEM_generator_2
air_flowgenerator_2
air_flow_calcfan2
:=fan_speed_percentageEEM_generator_2
0
0
1
2
3
0
0
0
...
%⋅=
adjusted_fan_speedgen2i adjusted_fan_speed fan_speed_percentageEEM_generator_2i⎛⎝⎞⎠:=
adjusted_fan_speedgen2
0
0
1
2
3
4
5
6
7
0
0
0
0
80.8
80.8
80.8
...
%=
max adjusted_fan_speedgen2( )100 %⋅=
powerEEM_generator_2
powerfan2
ηVFD
adjusted_fan_speedgen2( )3⋅:=powerEEM_generator_2
0
4
5
6
3.8
3.8
...
kW⋅=
powergenerator_2 schedulegenerator_2 powerfan2⋅:=
powergenerator_2
0
0
1
0
0 kW⋅=
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2 ...
annual_fan_energyEEM_generator_2 powerEEM_generator_2∑hr⋅35196 kW hr⋅⋅=:=estimated power used by generator 1's cooling fan if a
VFD were installed during 2009 operating year
annual_fan_energygenerator_2 powergenerator_2∑hr⋅42490 kW hr⋅⋅=:=estimated power used by generator 1's cooling fan
during 2009 operating year
Generator 2 - Final Analysis with weather and gen schedule data
Generator 3 - Final Analysis with weather and gen schedule data
schedulegenerator_3 C:\Documents and Settings\lww6153\Desktop\temp\Long Lake Power Generation VFD\long lake generator schedule reduced data.xls:=
schedulegenerator_3
0
0
1
2
3
1
1
1
...
=
mdot_generator_3
heat_transferstator
Cpair_290K tempair__EEM_exit_stator tempdrybulb_out_airwasher−( )⋅:=
mdot_generator_3
0
0
1
2
28.9
28.9
...
kg
s=
2015 Electric IRP Appendix D
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mdot_schedule_generator3i mdot_generator_3i schedulegenerator_3i⋅:=
mdot_schedule_generator3
0
0
1
2
3
28.9
28.9
28.9
...
kg
s=
adjusting air requirements for when generator is operating. Based on data
obtained from Rodney Picket for hourly generator operation for 2009
air_flow_calcfan3 air_flow_calcfan1:=
air_flowgenerator_3
mdot_schedule_generator3
ρair_290K
:=air_flowgenerator_3
0
0
1
2
49150.7
49150.7
...
ft3
min⋅=
air_flowgenerator_3
0
0
1
2
49150.7
49150.7
...
ft3
min⋅=
max air_flowgenerator_2( )189450.2 ft3
min⋅=
fan_speed_percentageEEM_generator_3
air_flowgenerator_3
air_flow_calcfan3
:=fan_speed_percentageEEM_generator_3
0
0
1
2
3
80.8
80.8
80.8
...
%⋅=
adjusted_fan_speedgen3i adjusted_fan_speed fan_speed_percentageEEM_generator_3i⎛⎝⎞⎠:=
2015 Electric IRP Appendix D
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adjusted_fan_speedgen3
0
0
1
2
3
4
80.8
80.8
80.8
80.8
...
%=
max adjusted_fan_speedgen3( )100 %⋅=
*Note: Fan #3 is used as a backup; I assumed fan #4 is supplying ~100% of the flow to gen 3
powerEEM_generator_3
powerfan4
ηVFD
adjusted_fan_speedgen3( )3⋅:=
powerEEM_generator_3
0
0
1
2
10.2
10.2
...
kW⋅=
powergenerator_3 schedulegenerator_3 powerfan4⋅:=
powergenerator_3
0
0
1
2
19
19
...
kW⋅=
2015 Electric IRP Appendix D
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annual_fan_energyEEM_generator_3 powerEEM_generator_3∑hr⋅95546.3 kW hr⋅⋅=:=estimated power used by generator 1's cooling fan if a
VFD were installed during 2009 operating year
annual_fan_energygenerator_3 powergenerator_3∑hr⋅114019 kW hr⋅⋅=:=estimated power used by generator 1's cooling fan
during 2009 operating year
Generator 3 - Final Analysis with weather and gen schedule data
Generator 4 - Final Analysis with weather and gen schedule data
schedulegenerator_4 C:\Documents and Settings\lww6153\Desktop\temp\Long Lake Power Generation VFD\long lake generator schedule reduced data.xls:=
schedulegenerator_4
0
0
1
1
...
=
mdot_generator_4
heat_transferstator
Cpair_290K tempair__EEM_exit_stator tempdrybulb_out_airwasher−( )⋅:=
mdot_generator_4
0
0
1
2
28.9
28.9
...
kg
s=
2015 Electric IRP Appendix D
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mdot_schedule_generator4i mdot_generator_4i schedulegenerator_4i⋅:=
mdot_schedule_generator4
0
0
1
2
28.9
28.9
...
kg
s=
adjusting air requirements for when generator is operating. Based on data
obtained from Rodney Picket for hourly generator operation for 2009
air_flow_calcfan4 air_flow_calcfan1:=
air_flowgenerator_4
mdot_schedule_generator4
ρair_290K
:=air_flowgenerator_4
0
0
1
2
49150.7
49150.7
...
ft3
min⋅=
air_flowgenerator_4
0
0
1
2
49150.7
49150.7
...
ft3
min⋅=
max air_flowgenerator_2( )189450.2 ft3
min⋅=
fan_speed_percentageEEM_generator_4
air_flowgenerator_4
air_flow_calcfan4
:=fan_speed_percentageEEM_generator_4
0
0
1
80.8
...
%⋅=
adjusted_fan_speedgen4i adjusted_fan_speed fan_speed_percentageEEM_generator_4i⎛⎝⎞⎠:=
2015 Electric IRP Appendix D
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adjusted_fan_speedgen4
0
0
1
2
3
80.8
80.8
80.8
...
%=
max adjusted_fan_speedgen4( )100 %⋅=
*Note: Fan #3 is used as a backup; I assumed fan #5 is supplying ~100% of the flow to gen 4
powerEEM_generator_4
powerfan5
ηVFD
adjusted_fan_speedgen4( )3⋅:=
powerEEM_generator_4
0
0
1
2
3
4
19.4
19.4
19.4
19.4
...
kW⋅=
powergenerator_4 schedulegenerator_4 powerfan5⋅:=
powergenerator_4
0
0
1
2
36
36
...
kW⋅=
annual_fan_energyEEM_generator_4 powerEEM_generator_4∑hr⋅176804.6 kW hr⋅⋅=:=estimated power used by generator 1's cooling fan if a
VFD were installed during 2009 operating year
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annual_fan_energygenerator_4 powergenerator_4∑hr⋅214380 kW hr⋅⋅=:=estimated power used by generator 1's cooling fan
during 2009 operating year
Generator 4 - Final Analysis with weather and gen schedule data
Summary of Results:
total_energy_annualno_VFD annual_fan_energygenerator_1 annual_fan_energygenerator_2+annual_fan_energygenerator_3+
annual_fan_energygenerator_4+
...:=
total_energy_annualno_VFD 823814 kW hr⋅⋅=
typically the dam personel see ~4-6 aMW*hr/daytotal_energy_annualno_VFD
365day 2257kW hr
day⋅=
total_energy_annualVFD annual_fan_energyEEM_generator_1 annual_fan_energyEEM_generator_2+
annual_fan_energyEEM_generator_3 annual_fan_energyEEM_generator_4++
...:=
total_energy_annualVFD 688055.8 kW hr⋅⋅=
energy_savings total_energy_annualno_VFD total_energy_annualVFD−135758.2 kW hr⋅⋅=:=
energy_rate 100$
1MW hr⋅:=
savings energy_savings energy_rate⋅13575.8 $=:=
savings
12%113131.9 $=
2015 Electric IRP Appendix D
855

Energy Efficiency Improvements
Audit Report

Prepared for
Nine Mile Hydro Electric Dam

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

February 13, 2015

2015 Electric IRP Appendix D
856

Overview

Facility: Nine Mile Hydro Electric Dam
Audited by: Andy Paul PE, Bryce Eschenbacher PE, and Levi Westra PE
Onsite Staff:
Facility Audited on: February 10th, 2015

Figure 1 Google Images of Nine Mile Hydro Electric Dam

Avista’s DSM Engineering staff visited the Nine Mile Hydro Electric Dam to review their current building
systems and discuss several concerns that the user’s encountered during typical operation.
2015 Electric IRP Appendix D
857

Specifically, this audit was conducted to identify all possible energy efficiency improvements not related to
the power generation process.
After completing a tour of the facility potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
It should be noted that this facility is currently undergoing a complete overhaul. Due to this there
are very few projects that can be suggested that are not already going to be implemented.
The facility consists of a control room and generation specific process areas including but not limited to
generation floor and breaker floor.
Shell
There are several areas around the facility where additional weatherization work can be conducted.
1. All exterior entry doors should have their weather stripping checked and replaced if necessary.

2. All windows that are not required to remain historically accurate should be replaced with energy
efficient double pane windows.

3. Any portion of the plant that is going to have cooling installed; control room, battery room etc,
should have the walls and ceiling insulated. The insulation will help thermally isolate it from the
rest of the plant and reduce the amount of cooling required in the summer time.

4. There is currently little to no insulation above or below the roof deck in the plant. It is
recommended that insulation, R-19 at the very least, be added below the deck. This insulation will
aid in reducing the amount of time a unit has to be motored during the winter months to maintain
space temperature.

Lighting
The facility currently employs T12 fluorescent lighting in the control room and surrounding areas and 400
Watt Metal Halide (MH) high-bay fixtures on the generating floor. The facility will have a brand new all
LED lighting system installed during the overhaul. The DSM group at Avista made suggestions on what
LED fixtures would be appropriate. Quinton Snead in the Generation Dept was in charge of the lighting
design.

While there will be energy savings for this project, specifically with the generating floor lighting as well as
the control room lighting, there will also be an additional lighting load installed. There are portions of the
plant that were under lit and needed additional lighting fixtures installed. Regardless of the additional
lighting fixtures, the new system will be as efficient as possible due to the installation of the LED fixtures
in lieu of more traditional linear fluorescent and HID fixtures.

HVAC
1. The control room and few other areas in the plant will be getting new HVAC units installed to heat
and cool the spaces. When selecting equipment considered installing the most efficient units that
can be afforded. It is also recommended that heat pump units be installed instead of standard
condensing units with electric resistive heat. New heat pumps are capable of working efficient
down to temperatures below zero. Since no natural gas is available at the Dam a heat pump is by
far the most efficient way to provide space heat.

2015 Electric IRP Appendix D
858

2. The main generating floor has no dedicated HVAC units. The heat from the generators keeps the
space conditioned during the winter months. A generator will be motored to maintain heat if no
generating is going on. It is recommended that dedicated HVAC units be installed to maintain the
space temperature when the units are not running. This would reduce unnecessary wear and tear
on the generating equipment as well as provide a known dedicated source of heat.
3. Installing two (possibly three) low speed/high volume destratification fans to help de-stratify the
air within in the facility is recommended. With 40’ ceilings the majority of buildings heated air will
stack at the top, the fans would push that heated air back towards the floor and create a
homogenous air temperature. This would reduce the amount of time that the space heat would
need to run.
In addition these fans could be run in reverse during the summer months to help pull warm air off
the floor and exhaust it out of the exhaust louvers located in the roof.

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.
Respectfully,
Andy Paul, Bryce Eschenbacher, and Levi Westra – February 13th, 2015

2015 Electric IRP Appendix D
859

Energy Efficiency Improvements
Audit Report

Prepared for
North East Combustion Turbine
Thermal Facility

Prepared by
Bryce Eschenbacher, PE
Energy Solutions Engineer

June 19, 2015

2015 Electric IRP Appendix D
860

Overview

Facility: North East Combustion Turbine
Audited by: Bryce Eschenbacher PE
Onsite Staff: Dwayne Wright
Facility Audited on: June 16th, 2015

Figure 1 Google Image of the North East Combustion Turbine Thermal Facility

Avista’s DSM Engineering staff visited the North East CT to review their current building systems and
discuss several concerns that the user’s encountered during typical operation. Specifically, this audit was
conducted to identify all possible energy efficiency improvements not related to the power generation
process.
After completing a tour of the facility potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
Shell
The main warehouse at the facility was completed recently and is well insulated with good exterior doors.
No improvements need to be made at this point in time. Below are some recommendations of the few
other buildings that may benefit from insulation or weatherization:
1. The MCC building has a through wall AC unit and small electric heater. The weather stripping for
the exterior door should be checked and replaced if it’s found to be faulty. This will aid in reducing
the AC load in the summer and the heating load in the winter.
2. The pump house and tool crib are similar to the MCC and should have their exterior door weather
stripping checked.

2015 Electric IRP Appendix D
861

Lighting
The new warehouse employs T8 linear fluorescent fixtures; the remainder of the facility is a mix of T12
linear fluorescents and screw in incandescent fixtures. The yard lights are quartz halogen fixtures. The
majority of these fixtures only operate a couple of hours a day and would not generate enough energy
savings to justify their replacement on those grounds. The increase in efficiency and longevity of the
fixtures on the other hand should be consider and replacement based on this planned. Below is a list of
potential lighting projects to consider.

Table 1 Capital Project Lighting Opportunity Summary
Brief EEM*
Description
EEM
Cost
Measure
Life
Electric
kWh
Savings
1 Halogen Pole
Lights $1,350 20 yr 5,145.6
*EEM – Energy Efficiency Measure

1. Proposed Project #1: There are currently (x6) quartz halogen yard lights. For this analysis it is
assumed that they are 250W lamps. These lights only operate when work is being down at the
facility. It was stated that the lights should be on dusk to dawn to provide some security lighting
as well. This analysis looks at the potential savings that would be seen if the existing lights were
on dusk to dawn. The proposed project looks at replacing these fixtures with 50W LED spot
lights. A simple lumen calculation shows that the overall lumens for the job were increased by
43%.
o The provided project cost is $3,600; this cost was calculated using fixture cost found
online and an estimated $75 per fixture for install.
2. The two lamp F48T12 linear fluorescent fixtures in the MCC room, tool crib, pump house, and
generator room, should be replaced with new linear LED fixtures. The 50W linear fixtures that
were used at Noxon Rapids are recommended for these areas. The cost to purchase and install
these fixtures is $347.50 (based on invoiced costs from Noxon).
HVAC
1. The main warehouse is conditioned by a gas fired unit hearer in the work area and a Mitsubishi
ductless heat pump serves the office area. The unit heater should be replaced with a 90%+ unit
when the current unit has reached its end of life. The ductless heat pump is a compact and
efficient means of condition the office space.
2. There are several small through the wall air conditioning units at some of the smaller outbuildings.
It is recommended that these be replaced with the most efficient units available when the existing
units fail.
3. The engine compartments are conditioned by two 1.5 ton York roof top unit mounted on grade
outside of the units. These units keep the engine compartment above freezing in the winter and
cool it down when maintenance needs to be done in the summer. The existing units are aged and
use R-22 refrigerant, which is no longer manufactured. At some point it will be necessary to
replace these units as parts and refrigerant become scarce. It is recommended that they be
replaced with the most efficient units that can be afforded.

2015 Electric IRP Appendix D
862

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.

Respectfully,
Bryce Eschenbacher – June 19, 2015
2015 Electric IRP Appendix D
863
Acct#
Existing Annual Consumption: (kilowatt hours)6,432.00
Lighting Energy Savings:(kilowatt hours)5,145.60
Lighting Demand Savings: (kilowatt demand)0.96
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 142.86%
Total Energy Savings: (kilowatt hours)5,145.60
Total Demand Savings: (kilowatt demand)0.96
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:$50.76
Name: North East CT - Halogen to LED
NECT_Halogen_Lighting_061915 Report Pg 1 - 1 6/19/20152015 Electric IRP Appendix D
864

Energy Efficiency Improvements
Audit Report

Prepared for
Noxon Rapids Hydro Electric Dam

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

February 10, 2015

2015 Electric IRP Appendix D
865

Overview

Facility: Noxon Rapids Hydro Electric Dam
Audited by: Andy Paul PE, Bryce Eschenbacher PE
Onsite Staff:
Facility Audited on: January 15th, 2015

Figure 1 Google Images of the Noxon Rapids Hydro Electric Dam

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Avista’s DSM Engineering staff visited the Noxon Rapids Hydro Electric Dam to review their current
building systems and discuss several concerns that the user’s encountered during typical operation.
Specifically, this audit was conducted to identify all possible energy efficiency improvements not related to
the power generation process.
After completing a tour of the facility potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
The facility consists of a control room, office space, break area and generation specific process areas
including but not limited to generation floor and breaker floor.
Shell
Due to the design of the facility there are no real shell measures that can be undertaken that would
benefit the facility or save energy.

Lighting
The site recently completed a full lighting system replacement. The old system was made up of old two
lamp 48W T12 fluorescent fixtures, incandescent screw in lamps of varying wattages, and metal halide
fixtures. The system is entirely made up of LED fixtures. The Majority being linear LED fixtures with some
screw in lamps throughout. This lighting project reduced the annual lighting load by 382,115 kWh. The
lighting system was the largest inefficiency in this facility.
In addition to the new lighting fixtures the entire lighting system was re-wired. New lighting panels were
installed as well.
HVAC
1. The facility employs a water source heat pump, along with a couple of air handlers and several
unit heaters, to condition the generating floor and all rooms on that same level. The access and
observation galleries are unconditioned.
During the audit we were not able to determine the size or efficiency of the unit because the
name plate was in-accessible. Based on the equipments vintage, and a statement from facility
staff that the equipment needs regular maintenance, we recommend that this equipment be
replace with a modern efficient water source heat pump. It is recommended that the most efficient
equipment that can be afforded be installed.

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.
Respectfully,
Andy Paul, Bryce Eschenbacher – February 10th, 2015

2015 Electric IRP Appendix D
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Energy Efficiency Improvements
Audit Report

Prepared for
Post Falls Hydro Electric Dam

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

May 28, 2015

2015 Electric IRP Appendix D
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Overview

Facility: Post Falls
Audited by: Andy Paul PE
Onsite Staff: Laroy Dowd
Facility Audited on: May 20th, 2015

Figure 1

PE, and Levi Westra PE

Google Images of the Post Falls Hydro Electric Dam
Avista’s DSM Engineering staff visited the Post Falls Hydro Electric Dam

to review their current building
systems and discuss several concerns that the user’s encountered during typical operation. Specifically,
2015 Electric IRP Appendix D
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this audit was conducted to identify all possible energy efficiency improvements not related to the power
generation process.
After completing a tour of the facility potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
The facility consists of a control room, office space, break area and generation specific process areas
including but not limited to generation floor and breaker floor.
Shell
There are several areas around the facility where additional weatherization work can be conducted. It
should be noted that this facility has no dedicated heating source due to an almost constant operation of
at least one unit, which provides enough heat for generating floor and control room. The control room
area has a couple of window style air conditioning units for the summer months. The recommendations
made below should only be acted on if there are future plans to provide this facility with a dedicated
heating and cooling source. As the facility operates now, these measures are not necessary and will not
reduce the electric load.
1. All exterior entry doors should have their weather stripping checked and replaced if necessary.

2. All windows that are not required to remain historically accurate should be replaced with energy
efficient double pane windows.

3. Any portion of the plant that currently has heating or cooling installed should have the walls and
ceiling insulated. The insulation will help thermally isolate it from the rest of the plant and reduce
the amount of cooling required in the summer time.

4. There is currently little to no insulation above or below the roof deck in the plant. It is
recommended that insulation, R-19 at the very least, be added below the deck.

Lighting
The site employs T12 and T8 linear fluorescent lighting, linear LED fixtures, as well as 150 Watt High
Pressure sodium high-bay fixtures. No parking lot lighting was observed.

Table 1 Capital Project Lighting Opportunity Summary
Brief EEM*
Description
EEM
Cost
Measure
Life
Electric
kWh
Savings
1 Control
Room T12s $3,462.50 20 yr 1,776
2 Generating
Floor HPS $2,423.75 20 yr 3,312
*EEM – Energy Efficiency Measure

1. Proposed Project #1: The control room currently has (x4) Two lamp F48T12 and (x3) Two lamp
F96T12 fluorescent fixtures serving the break room and storage areas. The proposed project
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looks at replacing these fixtures with (x10) 40W linear LED fixtures. A simple lumen calculation
shows that the overall lumens for the job were decreased by 11%.
o The provided project is $3,462.50, this cost was calculated using fixture and install costs
for these fixtures at Noxon Rapids HED.
2. Proposed Project #2: The facility currently has (x7) single lamp 150W high pressure sodium
fixtures located above the units on the generating floor. It is assumed that the fixtures average
3,600 hrs of operation a year. The proposed project looks at replacing these fixtures with 40W
linear LED fixtures. A simple lumen calculation shows that the overall lumens for the job were
increased by 28%.
o The provided project cost is $2,423.75; this cost was calculated using fixture and install
costs for these fixtures at Noxon Rapids HED.
3. It should be noted that while the total system lumens decrease for project #1, the actual lumens
that reach the working space will more the likely increase. LED fixtures are very directional in the
way they deliver lighting lumens. We recommend replacing a few light fixtures to make sure that
they will meet your lighting needs. If you would like to see the fixtures in operation we recommend
a trip to Noxon Rapids HED.
HVAC
1. The main generating floor has no dedicated HVAC units. The heat from the generators keeps the
space conditioned during the winter months. A generator will be motored to maintain heat if no
generating is going on, which is rare at this plant. During the summer months the heat from the
generators is exhausted from the space via several exhausts fans mounted in the upper windows
of the power house. These exhaust fans are controlled manually are on 24/7 during the warmer
months. It is recommended that thermostats be installed to control these exhaust fans. The
thermostats will reduce the run time of the fans during spring and fall when the fans are more
than likely left on when they may not be necessary.
2. It is recommended that the control room have a dedicated HVAC unit installed. The space is
currently heated by residual heat from the generators and controls cabinets, and is cooled by a
couple of window style air conditioners. A dedicated system would provide a more comfortable
environment for the operators as well as the controls equipment present in the space. If this is a
project that is going to be implemented, moving forward with shell recommendation number 3 is
advised.

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.
Respectfully,
Andy Paul, Bryce Eschenbacher, and Levi Westra – May 28, 2015

2015 Electric IRP Appendix D
871
Acct#
Existing Annual Consumption: (kilowatt hours)3,088.80
Lighting Energy Savings:(kilowatt hours)1,648.80
Lighting Demand Savings: (kilowatt demand)0.37
Cooling System Savings: (kilowatt hours)126.96
Cooling System Demand Savings: (kW demand) 0.03
Lumen Comparison New/Existing 88.53%
Total Energy Savings: (kilowatt hours)1,775.76
Total Demand Savings: (kilowatt demand)0.39
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:($30.72)
Name: Post Falls Hydro Electric Dam - T12 to LED
PostFalls_T12_Lighting_052815 Report Pg 1 - 1 5/28/20152015 Electric IRP Appendix D
872
Acct#
Existing Annual Consumption: (kilowatt hours)5,472.00
Lighting Energy Savings:(kilowatt hours)3,312.00
Lighting Demand Savings: (kilowatt demand)0.74
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 128.04%
Total Energy Savings: (kilowatt hours)3,312.00
Total Demand Savings: (kilowatt demand)0.74
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:($311.14)
Name: Post Falls Hydro Electric Dam - Generating Floor
PostFalls_GeneratingFloor_Lighting_052815 Report Pg 1 - 1 5/28/20152015 Electric IRP Appendix D
873

Energy Efficiency Improvements
Audit Report

Prepared for
Post Street Hydro Electric Facility
Upper Falls Hydro Electric Facility

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

June 19th, 2015

2015 Electric IRP Appendix D
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Overview

Facility: Post Street
Audited by: Andy Paul PE
Onsite Staff: Josh Stringfellow
Facility Audited on: June 10th, 2015

Figure 1

Facility/Upper Falls Hydro Electric Facility
PE, and Levi Westra PE

Google Images of the Post St/Monroe Hydro Electric Dam

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Figure 2 Google Images of the Upper Falls Hydro Electric

Figure 2 Google Images of the Upper Falls Hydro Electric Project

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Avista’s DSM Engineering staff visited the Post St. / Monroe St. Hydro Electric facility to review their
current building systems and discuss several concerns that the user’s encountered during typical
operation. We were unable to visit the Upper falls facility due a time constraint and limited access due to
their being no operator on site currently. We did discuss the systems at Upper Falls and have
recommendations for improvements listed below. Specifically, this audit was conducted to identify all
possible energy efficiency improvements not related to the power generation process.
After completing a tour of the facility potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
The facility consists of a control room, office space, break area and generation specific process areas
including but not limited to generation floor and breaker floor.
Shell
There are several areas around the facility where additional weatherization work can be conducted.
1. All exterior entry doors should have their weather stripping checked and replaced if necessary.

2. The control room should have insulation installed above the ceiling and in the walls if possible.
The insulation will help thermally isolate it from the rest of the plant, which is only maintained at
above freezing in the winter and is unconditioned otherwise.

3. There is currently little to no insulation above or below the roof deck above the substation. During
the winter four Reznor natural gas unit heaters keep the space above freezing. It is
recommended that insulation, R-19 at the very least, be added below the deck. This insulation will
aid in reducing the amount of time the unit heaters have to run to maintain the space
temperature.

Lighting
The site employs T12, induction fluorescent high bays as well as various wattages of incandescent and
compact fluorescent screw in lamps.

Table 1 Capital Project Lighting Opportunity Summary
Brief EEM*
Description
EEM
Cost
Measure
Life
Electric
kWh
Savings
1 Utility men
break room $1,498 20 yr 2,151
2 Control room $3,745 20 yr 4,340
3 Network
Feeder tunnel $5,718 20 yr 8,344
*EEM – Energy Efficiency Measure

1. Proposed Project #1: The Utility Men break room currently has (x4) four lamp F48T12 fluorescent
fixtures that operate 2,080 hrs a year (40hrs/wk). The proposed project looks at replacing these
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fixtures with (x4) 50W linear LED fixtures. A simple lumen calculation shows that the overall
lumens for the job were decreased by 60%.
o The provided project is $1,498, this cost was calculated using fixture and install costs for
these fixtures at Noxon Rapids HED.
2. Proposed Project #2: The facility currently has (x10) two lamp fluorescent fixtures that operate
8,760 hrs a year (40hrs/wk). The proposed project looks at replacing these fixtures with (x10)
50W linear LED fixtures. A simple lumen calculation shows that the overall lumens for the job
were decreased by 20%.
o The provided project cost is $3,745, this cost was calculated using fixture and install
costs for these fixtures at Noxon Rapids HED.
3. Proposed Project #3: The facility currently has (x15) two lamp fluorescent fixtures that operate
8,760 hrs a year (40hrs/wk). The proposed project looks at replacing these fixtures with (x15)
50W linear LED fixtures. A simple lumen calculation shows that the overall lumens for the job
were decreased by 20%. In addition to switching out the lights it is proposed that an occupancy
sensor be installed to control these lights. This is an area of the facility that is only checked once
or twice a day, unless maintenance is being performed. A properly located occupancy sensor will
be able to turn the lights on before an operator reaches the space and will keep the lights on
during the time that they are present. Otherwise they will go off.
o The provided project cost is $5,717.50; this cost was calculated using fixture and install
costs for these fixtures at Noxon Rapids HED. An additional $100 was added for the
occupancy sensor.
4. It should be noted that while the total system lumens decrease for each of these projects, the
actual lumens that reach the working space will more the likely increase. LED fixtures are very
directional in the way they deliver lighting lumens. We recommend replacing a few light fixtures to
make sure that they will meet your lighting needs. If you would like to see the fixtures in operation
we recommend a trip to Noxon Rapids HED.
5. In addition to the projects listed above there are several other areas that would benefit from
installing new lighting fixtures.
• Most of the lower levels are lit with incandescent screw in lamps which remain on 24/7.
It is recommended that these lamps be switch out for comparable LED screw in lamps
and that the fixtures are placed on occupancy sensors. The sensors for these lights
would need to be placed in the stairwells coming down to the space. This would ensure
that the lights are on when the operator enters the space. In addition a redundant sensor
(or two) should be placed in the space to provide the control necessary to keep the
lights on when they are working in the space. It is highly recommend that a lighting
design professional be brought in to properly design this system.
• There are (x22) screw in compact fluorescent lamps located along the crane rail. It is
recommended that these are replaced with comparable LED screw in lamps.
6. The lighting in the Monroe St. Turbine pit is all T8 linear fluorescent fixtures. A simple upgrade
would be to change out the existing 32W T8 lamps with 25W T8 lamps. This would also require
the ballasts to be changed. These fixtures could also be converted to linear LED tubes. We
recommend that the lighting in the Post St. Building be upgraded before replacing the lighting at
Monroe St.
7. The lighting at the Upper Falls facility was stated to be high pressure sodium fixtures. It is
assumed that these are 400W lamps. It is recommended that these fixtures be upgraded to high
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bay LED fixtures. Little Falls Dam is upgrading all of the high pressure sodium fixtures these to
LED, Nathan Fletcher was in charge of that design.
HVAC
1. The control room is conditioned by an electric forced air furnace paired with a condensing unit for
cooling. The condensing unit was recently replaced and is fairly efficient. It is recommended that
that the furnace be replaced with a 90%+ efficient gas unit. On average a gas furnace will use ½
of the energy that an electric furnace will to provide the amount of heat. Gas is located nearby for
the Reznor unit heaters.
2. The substation floor is conditioned by (x4) Reznor unit heaters. These heaters are used to keep
the space above freezing during the winter. The units are 80% efficient and appear to be in good
working order. When the time comes to replace them it is recommended that 90%+ unit heaters
be purchased.
3. Installing two (possibly three) low speed/high volume destratification fans to help de-stratify the
air within in the facility is recommended. With 40’ ceilings the majority of buildings heated air will
stack at the top, the fans would push that heated air back towards the floor and create a
homogenous air temperature. This would reduce the amount of time that the space heat would
need to run.

We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to
pursue any of these potential energy savings projects please let the Energy Solutions team know
ahead of the start of the project.

Respectfully,
Andy Paul, Bryce Eschenbacher, and Levi Westra – June 19th 2015

2015 Electric IRP Appendix D
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Acct#
Existing Annual Consumption: (kilowatt hours)2,412.80
Lighting Energy Savings:(kilowatt hours)1,996.80
Lighting Demand Savings: (kilowatt demand)0.77
Cooling System Savings: (kilowatt hours)153.75
Cooling System Demand Savings: (kW demand) 0.06
Lumen Comparison New/Existing 39.79%
Total Energy Savings: (kilowatt hours)2,150.55
Total Demand Savings: (kilowatt demand)0.83
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)(17.37)
Maintenance Savings:$25.63
Name:Post St. Hydro Electric Dam - Utility Men Break Room
PostSt_UtilityMenBreakRoom_Lighting_061915 Report Pg 1 - 1 6/19/20152015 Electric IRP Appendix D
880
Acct#
Existing Annual Consumption: (kilowatt hours)8,409.60
Lighting Energy Savings:(kilowatt hours)4,029.60
Lighting Demand Savings: (kilowatt demand)0.37
Cooling System Savings: (kilowatt hours)310.28
Cooling System Demand Savings: (kW demand) 0.03
Lumen Comparison New/Existing 79.58%
Total Energy Savings: (kilowatt hours)4,339.88
Total Demand Savings: (kilowatt demand)0.40
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)(35.06)
Maintenance Savings:($0.23)
Name: Post St. Hydro Electric Dam - Control Room
PostSt_Operator_Lighting_061915 Report Pg 1 - 1 6/19/20152015 Electric IRP Appendix D
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Acct#
Existing Annual Consumption: (kilowatt hours) 12,614.40
Lighting Energy Savings:(kilowatt hours)8,343.90
Lighting Demand Savings: (kilowatt demand)0.55
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 79.58%
Total Energy Savings: (kilowatt hours)8,343.90
Total Demand Savings: (kilowatt demand)0.55
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:$106.38
Name: Post St. Hydro Electric Dam - Network Feeder Lighting
PostSt_NetWorkFeeder_Lighting_061915 Report Pg 1 - 1 6/19/20152015 Electric IRP Appendix D
882

Energy Efficiency Improvements
Audit Report

Prepared for
Rathdrum Combustion Turbine
Thermal Facility

Prepared by
Andy Paul, PE
Bryce Eschenbacher, PE
Levi Westra, PE
Energy Solutions Engineers

May 28, 2015

2015 Electric IRP Appendix D
883

Overview

Facility: Rathdrum Combustion Turbine
Audited by: Andy Paul PE, Bryce Eschenbacher PE, and Levi Westra PE
Onsite Staff: N/A
Facility Audited on: May 20th, 2015

Figure 1 Google Image of the Rathdrum Combustion Turbine Thermal Facility

Avista’s DSM Engineering staff visited the Rathdrum CT to review their current building systems and
discuss several concerns that the user’s encountered during typical operation. Specifically, this audit was
conducted to identify all possible energy efficiency improvements not related to the power generation
process.
After completing a tour of the facility potential improvement measures were identified for consideration
including capital projects as well as low-cost no-cost measures. This report is intended to provide a
cursory review of possible energy savings. Each listed recommendation and costing is based upon
historical experience and costing projections. Equipment life and performance will vary and a Statement
of Work (SOW) for the capital project will determine the actual project costs and performance.
Shell
There are a couple of areas around the facility where additional weatherization work can be conducted. It
should be noted that this facility is rarely staffed and is generally operated remotely when it is needed.
That being said, it is assumed that shop building is maintained at 55º in the winter (freeze protection) and
below 78º in the summer. We were unable to verify the actual HVAC set point. Even with minimal HVAC
the weatherization recommendations below will save energy.
1. All exterior entry doors should have their weather stripping checked and replaced if necessary.
This includes the 5 man door and 2 roll up doors.
2. There are a couple of exhaust louvers on the backside of the shop building. If these louvers are
not equipped with motorized dampers with proper blade seals, it is recommended that they are
installed. When the louvers are not needed a large amount of outside air may be making its way
back into the building, which would increase the HVAC load.

2015 Electric IRP Appendix D
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Lighting
The site employs metal halide road way light and halogen pole lights around the equipment. We were not
able to get inside of the shop building to inspect the lights present. Based on the age of the facility

Table 1 Capital Project Lighting Opportunity Summary
Brief EEM*
Description
EEM
Cost
Measure
Life
Electric
kWh
Savings
1 Roadway
lighting $10,020 20 yr 16,273
2 Halogen Pole
Lights $3,600 20 yr 3,200
*EEM – Energy Efficiency Measure

1. Proposed Project #1: The roadway is lit by (x15) Single Lamp 250W Metal halide cobra heads.
This project would replace these with (x15) Cree 42W LED cobra heads. It is assumed that these
fixtures have an average of 4,288 hrs/yr (dusk to dawn) annual operating hours. A simple lumen
calculation shows that the overall lumens for the job were decreased by 81%.
o The provided project is $10,020, this cost was calculated using fixture and install costs for
these fixtures at Noxon Rapids HED.
2. Proposed Project #2: The facility currently has (x16) single lamp halogen pole mounted lights.
Wattage could not be confirmed for these lamps. For this analysis it is assumed that they are
250W lamps. It is also assumed that the fixtures average 1,000 hrs of operation a year and are
only used for spot lighting when work is being done. The proposed project looks at replacing
these fixtures with 50W LED spot lights. A simple lumen calculation shows that the overall lumens
for the job were increased by 43%.
o The provided project cost is $3,600; this cost was calculated using fixture cost found
online and an estimated $75 per fixture for install.
3. It should be noted that while the total system lumens decrease for project #1, the actual lumens
that reach the working space will more the likely increase. LED fixtures are very directional in the
way they deliver lighting lumens. In addition the existing high pressure sodium fixtures produce a
yellow light which is not conducive to good visibility while working. We recommend replacing a
few light fixtures to make sure that they will meet your lighting needs. If you would like to see the
fixtures in operation we recommend a trip to Noxon Rapids HED.
HVAC
1. The main facility shop building’s office area is conditioned by a 5 ton air conditioner paired with a
natural gas furnace. Based on the age of the building is assumed that the furnace is around 80%
efficient. Since this facility is rarely manned the payback for installing a new HVAC system is too
long to consider on a financial basis. But when the existing equipment fails it is recommended
that the most efficient equipment be purchased to replace it.
2. There are several small through the wall air conditioning units at some of the smaller outbuildings.
It is recommended that these be replaced with the most efficient units available when the existing
units fail.

2015 Electric IRP Appendix D
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We hope that this report helps to identify some areas that the generating facility can gain some
operational efficiency and reduce the parasitic load that these systems represent. If you decide to pursue
any of these potential energy savings projects please let the Energy Solutions team know ahead of the
start of the project.

Respectfully,
Andy Paul, Bryce Eschenbacher, and Levi Westra – May 28, 2015
2015 Electric IRP Appendix D
886
Acct#
Existing Annual Consumption: (kilowatt hours) 18,974.40
Lighting Energy Savings:(kilowatt hours)16,272.96
Lighting Demand Savings: (kilowatt demand)3.04
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 18.59%
Total Energy Savings: (kilowatt hours)16,272.96
Total Demand Savings: (kilowatt demand)3.04
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:$124.47
Name: Rathdrum CT - Pole Lights
Rathdrum_Street_Lighting_052815 Report Pg 1 - 1 5/29/20152015 Electric IRP Appendix D
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Acct#
Existing Annual Consumption: (kilowatt hours)4,000.00
Lighting Energy Savings:(kilowatt hours)3,200.00
Lighting Demand Savings: (kilowatt demand)2.56
Cooling System Savings: (kilowatt hours)0.00
Cooling System Demand Savings: (kW demand) 0.00
Lumen Comparison New/Existing 142.86%
Total Energy Savings: (kilowatt hours)3,200.00
Total Demand Savings: (kilowatt demand)2.56
Estimated Project Cost: (Rough Estimate)See Report
Heating System Penalty: (therms)0.00
Maintenance Savings:$63.43
Name: Rathdrum CT - Halogen to LED
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2015 Electric Integrated
Resource Plan

Appendix E – 2015 Electric IRP
New Resource Table for
Transmission

2015 Electric IRP Appendix E
889
Resource POR Capacity Year
Resource Note Location or Local Area POD Start Stop MW Total
Nine Mile Nine Mile Falls, WA Nine Mile AVA System 4/1/2016 Indefinite 7.6 7.6
SCCT 1 TBD Mid-C/AVA System AVA System 10/1/2020 Indefinite 102.0 102.0
Northeast Spokane, WA Northeast AVA System 10/1/2023 Indefinite 7.5 7.5
Kettle Falls Kettle Falls, WA Kettle Falls AVA System 10/1/2024 Indefinite 12.0 12.0
Rathdrum Rathdrum, WA Rathdrum AVA System 10/1/2025 Indefinite 18.5 18.5
CCCT 1 TBD Mid-C/AVA System AVA System 10/1/2026 Indefinite 306.0 306.0
SCCT 1 TBD Mid-C/AVA System AVA System 10/1/2027 Indefinite 102.0 102.0
Kettle Falls Kettle Falls, WA Kettle Falls AVA System 10/1/2033 Indefinite 3.0 3.0
SCCT 1 TBD Mid-C/AVA System AVA System 10/1/2034 Indefinite 46.5 46.5
Total 605.1 605.1
Mid-Columbia Anticipated Contract ExtensionsMid-C contract extensions may replace or modify resources named above
Resource POR Capacity Year
Resource Note Location or Local Area POD Start Stop MW TotalRocky Reach Mid-C Mid-C AVA System 1/1/2021 TBD 59.0
Rock Island Mid-C Mid-C AVA System 1/1/2021 TBD 21.0 80.0
Wells Mid-C Mid-C AVA System 8/1/2018 TBD 28.0 28.0
Total 108.0 108.0
1 Modified POR to "Mid-C/AVA System" to reflect possibility of off-system SCCT integrated at Mid-C
2015 Avista Electric IRP
Appendix E
New Resource Table For Transmission
Updated August 25, 2015
2015 Electric IRP Appendix E
890
System Planning Feasibility Study

November 25, 2014 Page 1of 41

Avista System Planning

2014 IRP Interconnection Study

Richard Maguire
Avista System Planning
November 25, 2014

2015 Electric IRP Appendix E
891
System Planning Feasibility Study

November 25, 2014 Page 2of 41

Contents
INTRODUCTION ................................................................................................................................................................... 3
STUDY METHODOLOGY AND ASSUMPTIONS ....................................................................................................................... 4
ANALYSIS ............................................................................................................................................................................. 6
KOOTENAI COUNTY ...................................................................................................................................................................... 6
Kootenai 100 MW Request; $16 to $20.1 million ............................................................................................................... 7
Kootenai 350 MW request; $47.2 million ........................................................................................................................... 9
RATHDRUM STATION .................................................................................................................................................................. 11
Rathdrum 26 MW request; 115 kV option; $2.84 million to $10.9 million ....................................................................... 12
Rathdrum 50 MW request; 115 kV option; $10.7 to $18.7 million .................................................................................. 13
Rathdrum 200 MW request; 115 kV option; $10.3 to $48.5 million ................................................................................ 15
Rathdrum 50 MW Request; 230 kV Option; $7 to $16.8 million ...................................................................................... 17
Rathdrum 200 MW Request; 230 kV option; $15.5 to $21.5 million ................................................................................ 18
THORNTON STATION .................................................................................................................................................................. 20
Thornton 30 MW and 100 MW Request; $400,000 ......................................................................................................... 20
OTHELLO STATION ..................................................................................................................................................................... 22
Othello 25 MW Solar request; $2 million ......................................................................................................................... 22
NORTHEAST STATION .................................................................................................................................................................. 23
Northeast 10 MW; $0 ....................................................................................................................................................... 23
KETTLE FALLS STATION ................................................................................................................................................................ 24
Kettle Falls 10 MW; $0 ..................................................................................................................................................... 24
LONG LAKE DAM ....................................................................................................................................................................... 25
Long Lake 68 MW; $19.7 million ...................................................................................................................................... 25
MONROE STREET ....................................................................................................................................................................... 29
Monroe Street 80 MW; $7 million .................................................................................................................................... 29
POST FALLS ............................................................................................................................................................................... 31
Post Falls 10 to 22 MW; $2.1 to $5.2 million .................................................................................................................... 31
APPENDIX A .............................................................................................................................................................................. 32
APPENDIX B .............................................................................................................................................................................. 34
APPENDIX C .............................................................................................................................................................................. 37

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Introduction
Avista Utilities’ Integrated Resource Planning group requested preliminary estimates for the generation
interconnections listed below. Avista’s System Planning Group conducted studies, and the results of those
studies are summarized below and described in more detail throughout this report.
TABLE 1: SUMMARY ESTIMATES FOR GENERATION INTERCONNECTION REQUESTS
Station Request (MW) POI Voltage Cost Estimate ($ million)1
Kootenai County (New) 100 230 kV 12 - 16.1
Kootenai County (New) 350 230 kV 47.2
Rathdrum 26 115 kV 2.84 - 10.9
Rathdrum 50 115 kV 10.7 – 18.7
Rathdrum 200 115 kV 10.3 - 48.5
Rathdrum 50 230 kV 7 – 16.8
Rathdrum 200 230 kV 15.5 – 21.5
Thornton 30 230 kV .4
Thornton 100 230 kV .4
Othello 25 115 kV 2
Northeast 10 115 kV 0
Kettle Falls 10 115 kV 0
Long Lake 68 115 kV 19.7
Monroe Street 80 115 kV 7
Post Falls 10 115 kV 2.1
Post Falls 20 115 kV 5.2

1 Preliminary estimates are given as -25% to +75%
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Study Methodology and Assumptions
Steady-state power flow analysis was performed for each request under the following conditions:
 Two Avista Planning Cases2 were used for each request:
o 2024 Heavy Summer – based on WECC 2024 HS1-S Base Case
o 2019 High Transfer – rated West of Hatwai flow based on WECC 2014 LS1 Operating Case
 737 contingency events were analyzed using select P1 – P7 3 events
o Important Note: cost estimates could be significantly increased by a more complete study that
includes all P6 contingencies. A System Impact Study is necessary for more accurate cost
estimates.
 Study case topology includes the Avista projects documented in Appendix A
 All existing generation local to each request was enabled at full output
 New generation was modeled using +/- 0.95 power factor
 PowerWorld’s Contingency Analysis tool was used to determine only those facility violations that are
new and caused by the requested generation. This is different from standard assessment presentations
of contingency results, and the reader should keep this in mind when looking at study results.
 PowerWorld’s Available Transfer Capability (ATC) tool, not to be confused with the ‘ATC’ posted on
Avista’s OASIS, was used to provide an indication of next-most-limiting facilities as the studied generator
output was increased and the list of contingencies analyzed. This analysis was conducted for each
request with the following settings:
o Buyer modeled as all WECC generators except those within Avista’s Balancing Authority Area
o Ramping of modeled generation occurred in the pre-contingency state
o Assumed reactive power did not change
o ATC results cross-checked with standard contingency analysis
 Facility performance was measured against NERC Standards4 TPL-001-4 and FAC-010
o Voltage performance not assessed during this study

2 Avista Planning Cases are described in Avista Standards TP-SPP-04 Data Preparation and TP-SPP-06 Contingency Analysis

3 ‘P’ type Performance Planning Events described in NERC TPL-001-4

4 See http://www.nerc.net/standardsreports/standardssummary.aspx

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Analysis
Kootenai County
100 to 350 MW of generation was requested to be studied at a new station in Kootenai County near Post Falls,
Idaho. This request was modeled as a new station approximately 2.5 electrical miles southwest of Rathdrum
station on the Beacon – Rathdrum 230 kV Transmission Line (See Figure 1).

FIGURE 1: KOOTENAI STATION; 2024 HEAVY SUMMER SCENARIO
System performance in this area is dominated by several factors:
1. Inflow from the east on the Lancaster – Noxon and Cabinet – Rathdrum 230 kV transmission lines
2. Outflow to the west on the Bell – Lancaster, Boulder – Lancaster, and Beacon – Rathdrum 230 kV
transmission lines
3. Load in the Coeur d’ Alene area served from Rathdrum Station
4. Generation (426 MW) locally from Lancaster, Rathdrum, Post Falls, and Boulder stations
In general, given the prevailing east-to-west flow of energy in the area under study, mitigating projects tend
toward adding transmission capacity to the west, or to the south, or to both.

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Kootenai 100 MW Request; $16 to $20.1 million
Analysis
For P0 conditions, both study cases received generation up to 100 MW without issue.
For performance during contingencies, Table 2 shows results from the ATC analysis, and Table 3 shows
Contingency Analysis results for new facility violations created by requested generation at 100 MW.
TABLE 2: ATC RESULTS; 100 MW OUTPUT

TABLE 3: CONTINGENCY RESULTS; 100 MW OUTPUT

Case Trans Lim Limiting Element Limiting CTG % OTDF
hs 19.79 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder # 2 115 kV 5.06
ht 25.46 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer -4.9
ht 30.09 Line BOULDERE (48522) TO IRVIN (48165) CKT 1 [115.00 - 115.00 kV]N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder # 1 115kV 4.35
ht 35.85 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-1: Opportunity - Otis Orchards 115 kV Open @ OTI 3.55
ht 36.2 Line EASTFARM (48117) TO POST FLS (48329) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -7.6
hs 45.15 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -9.51
ht 54.6 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-1: Beacon - Boulder 230 kV 4.1
ht 63.74 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer -4.9
ht 64.84 Line BENEWAH (48037) TO PINE CRK (48317) CKT 1 [230.00 - 230.00 kV] BF: A290 Hot Springs 230 kV, Hot Springs-Rattlesnake -3.95
ht 65.04 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] BUS: Beacon North 230 kV 4.69
ht 69.54 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] N-1: Boulder - Lancaster 230 kV -5.08
hs 76.6 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -9.51
ht 78.81 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum -10.49
ht 80.77 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV -7.22
ht 88.71 Line EASTFARM (48117) TO OTIS (48311) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV 7.6
ht 89.08 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer -4.9
hs 105.53 Line IRVIN (48165) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV]BF: R427 Beacon North & South 230 kV -7.56
Element Label Percent Case
PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV 110.24 hs
BELLAN11 (90011) -> BELL S3 (40090) CKT 1 at BELLAN11 N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV 107.47 ht
MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV 106.63 hs
PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT N-1: Boulder - Lancaster 230 kV 105.68 ht
PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer 105.42 ht
POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV 105.08 ht
PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer 104.69 ht
BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at SPKINDPK N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder # 2 115 kV 103.12 hs
BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at SPKINDPK N-2 (ADJ): Beacon - Boulder # 2 115 kV and Beacon - Ninth & Central # 2 115 kV 102.77 hs
MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB N-1: Boulder - Lancaster 230 kV 102.64 ht
BOULDERE (48522) -> IRVIN (48165) CKT 1 at BOULDERE N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder # 1 115kV 102.57 ht
MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer 102.41 ht
BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW N-1: Opportunity - Otis Orchards 115 kV Open @ OTI 102.17 ht
RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV 101.82 hs
BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW N-1: Beacon - Boulder 230 kV 101.75 ht
MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer 101.65 ht
BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW BUS: Beacon North 230 kV 101.53 ht
SPKINDPK (48405) -> IRVIN (48165) CKT 1 at IRVIN BF: R427 Beacon North & South 230 kV 101.47 hs
IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum 101.18 ht
BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV 100.87 ht
EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV 100.58 ht
OPPORTUN (48299) -> CHESTER (48069) CKT 1 at CHESTER BF: A600 Beacon North & South 115 kV 100.2 hs
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Figure 2 shows system performance during the highest overload contingency noted in Table 3. Figure 2 provides
a fairly accurate depiction of issues in the area as power flows on the underlying 115 kV system for some single
or double-circuit outage on the east-west 230 kV system.

FIGURE 2: WORST INCREMENTAL PERFORMANCE DURING CONTINGENCIES; HEAVY SUMMER CASE; 100 MW REQUEST
Project Alternatives
1. Point of Interconnection (POI)
a. New 3 position Double Bus Double Breaker station (Kootenai); $4 million
2. Project options necessary to mitigate new facility violations
a. Back-tripping with transmission line upgrades:
i. Implement the back-tripping scheme currently described in Avista’s 2013 Local Planning
Report5 for an estimated $400,000
ii. Upgrade 27.6 miles of 115 kV transmission lines to a minimum summer rating of 132
MVA for an estimated $11.6 million.
b. Transmission line upgrades without back-tripping:
i. Upgrading 38 miles of 115 kV transmission line to a minimum summer rating of 132
MVA for an estimated $16 million
ii. Upgrade 0.1 miles of the BPA Bell – Lancaster 230 kV Transmission Line to a summer
rating of 800 MVA for an estimated $100,000

5 http://www.oasis.oati.com/AVAT/AVATdocs/2013_Avista_System_Planning_Assessment_-_Rev_0.pdf; Page 108
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Kootenai 350 MW request; $47.2 million
Analysis
For P0 conditions, both study cases received generation up to 350 MW without issue. Table 4 shows results from
the ATC analysis, and Appendix B shows Contingency Analysis results for new facility violations created by the
requested generation.
TABLE 4: ATC RESULTS; 350 MW OUTPUT

ID Case Trans Lim Limiting Element Limiting CTG % OTDF
197 hs 19.79 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder # 2 115 kV 5.06
57 ht 25.46 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer -4.9
56 ht 30.09 Line BOULDERE (48522) TO IRVIN (48165) CKT 1 [115.00 - 115.00 kV]N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder # 1 115kV 4.35
55 ht 35.85 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-1: Opportunity - Otis Orchards 115 kV Open @ OTI 3.55
54 ht 36.2 Line EASTFARM (48117) TO POST FLS (48329) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -7.6
196 hs 45.15 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -9.51
53 ht 54.6 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-1: Beacon - Boulder 230 kV 4.1
52 ht 63.74 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer -4.9
51 ht 64.84 Line BENEWAH (48037) TO PINE CRK (48317) CKT 1 [230.00 - 230.00 kV] BF: A290 Hot Springs 230 kV, Hot Springs-Rattlesnake -3.95
50 ht 65.04 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] BUS: Beacon North 230 kV 4.69
49 ht 69.54 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]N-1: Boulder - Lancaster 230 kV -5.08
195 hs 76.6 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -9.51
48 ht 78.81 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum -10.49
47 ht 80.77 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV -7.22
46 ht 88.71 Line EASTFARM (48117) TO OTIS (48311) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV 7.6
45 ht 89.08 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer -4.9
44 ht 90 Line BENEWAH (48037) TO PINE CRK (48317) CKT 1 [230.00 - 230.00 kV] BF: A286 Hot Springs 230 kV, Flathead-Hot Springs -3.82
194 hs 105.53 Line IRVIN (48165) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV]BF: R427 Beacon North & South 230 kV -7.56
43 ht 113.23 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum -8.68
42 ht 118.15 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: A388 Bell S2 & S3 230 kV 3.9
193 hs 120.3 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2: Beacon - Boulder 230 kV & Boulder - Irvin # 2 115 kV 5.95
41 ht 132.66 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: A1561 Boulder-Lancaster, Lancaster Generator # 1 & # 2 5.08
40 ht 134.68 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-1: Lancaster - Rathdrum 230 kV 10.28
192 hs 135.44 Line CHESTER (48069) TO OPPORTUN (48299) CKT 1 [115.00 - 115.00 kV] BF: A600 Beacon North & South 115 kV -4.01
39 ht 135.9 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]N-2 (ADJ): Bell - Taft 500 kV and Bell - Lancaster 230 kV -3.94
38 ht 137.3 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: A1186 Lancaster-Noxon, Boulder-Lancaster 5.29
37 ht 145.41 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] PSF: Ramsey 115 kV 3.98
36 ht 146.75 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]BF: A1186 Lancaster-Noxon, Boulder-Lancaster -5.29
35 ht 148.64 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum -10.5
191 hs 170.76 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV 8.62
34 ht 173.9 Line PRAIRIEB (40855) TO RAMSEY (48349) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV -6.1
33 ht 180.38 Line BENEWAH (48037) TO PINE CRK (48317) CKT 1 [230.00 - 230.00 kV] BF: A288 Hot Springs 230 kV, Hot Springs-Noxon Rapids # 1 -3.82
32 ht 182.63 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] N-1: Boulder - Lancaster 230 kV -4.14
31 ht 185.51 Line BENEWAH (48037) TO PINE CRK (48317) CKT 1 [230.00 - 230.00 kV] BUS: Hot Springs 230 kV -3.82
30 ht 194.18 Line EASTFARM (48117) TO POST FLS (48329) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV -5.42
29 ht 199.14 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum -10.49
28 ht 204.71 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer -3.99
27 ht 207.05 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer -3.99
190 hs 220.28 Line HUETTER (48159) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BF: A506 Rathdrum 115 kV, Pine Street-Rathdrum -4.11
189 hs 221.52 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer 5.19
188 hs 221.85 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer 5.19
187 hs 224.66 Line HUETTER (48159) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BUS: Rathdrum East 115 kV -4.11
186 hs 229.41 Line PRAIRIEB (40855) TO RAMSEY (48349) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -8
185 hs 250.4 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -8
184 hs 251.35 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-1: Boulder - Lancaster 230 kV 5.37
26 ht 254.81 Line PRAIRIEB (40855) TO RAMSEY (48349) CKT 1 [115.00 - 115.00 kV] BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum -8.68
25 ht 285.24 Line BELL S3 (40090) TO BELCOU31 (90012) CKT 3 [230.00 - 230.00 kV] N-2 (ADJ): Bell - Coulee # 6 500kV and Coulee - Westside 230kV 8.91
24 ht 285.53 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] BF: A1186 Lancaster-Noxon, Boulder-Lancaster -4.26
23 ht 295.13 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-1: Boulder - Lancaster 230 kV -5.08
22 ht 299.48 Line EASTFARM (48117) TO OTIS (48311) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV 5.42
21 ht 320.34 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer -4.9
20 ht 321.03 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer -4.9
19 ht 343.98 Line HATWAI (40519) TO MOSCOW (48249) CKT 1 [230.00 - 230.00 kV] BF: 4652 Dworshak-Taft, Dworshak-Hatwai, Dworshak 500 kV Switched Shunt -7.55
18 ht 345.85 Line BELLAN11 (90011) TO LANCASTR (40624) CKT 1 [230.00 - 230.00 kV] BF: R427 Beacon North & South 230 kV -32.19
17 ht 346.31 Line BELLAN11 (90011) TO LANCASTR (40624) CKT 1 [230.00 - 230.00 kV] N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV -31.02
183 hs 350.23 Line HUETTER (48159) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BF: A638 Rathdrum 115 kV, Appleway-Rathdrum -4.11
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Contingency analysis for the 350 MW request reveals 141 new facility violations between the two cases studied,
with the highest instance of thermal overloading shown in Figure 3 for the loss of both the Beacon – Kootenai
and Boulder – Lancaster 230 kV transmission lines.

FIGURE 3: WORST PERFORMING CONTINGENCY EVENT; HEAVY SUMMER CASE; 350 MW REQUEST
Project Alternatives
Historic generation interconnection studies6 done for the same area of this request show that reconductoring
alone is not sufficient for this level of incremental generation. In addition to the alternatives presented in the
referenced study, a promising option includes:
1. Point of Interconnection (POI)
a. New 3 position Double Bus Double Breaker station (Kootenai); $4 million
2. Upgrade 23.5 miles of 115 kV transmission line to a minimum summer rating of 166 MVA for $7.0
million
3. Construct a new, 5-position 230 kV station approximately 1 mile west of Indian Trails station for $11
million
a. Terminate the Bell – Westside and Coulee – Westside 230 kV transmission lines at this station
4. Construct a new 35 mile 230 kV, 800 MVA summer rated transmission line from Rathdrum station to the
newly construction station for $25.2 million

6 http://www.oasis.oati.com/AVAT/AVATdocs/Rathdrum500_Final.pdf

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Rathdrum Station
Three incremental outputs were requested for this station: 26, 50, and 200 MW. These requests were studied as
follows:
 26 MW supplied by upgrading the existing turbines
 50 and 200 MW coming from symmetrical generators at each of the Rathdrum 115 kV buses
 50 and 200 MW supplied by a single generator placed at the Rathdrum 230 kV bus (see Figure 4)

FIGURE 4: 200 MW INCREMENTAL GENERATION AT RATHDRUM; 2019 HIGH TRANSFER CASE

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Rathdrum 26 MW request; 115 kV interconnection; $2.84 million to $10.9 million
Analysis
For P0 conditions, both study cases received generation up to 26 MW without issue.
For performance during contingencies, Table 2 shows results from the ATC analysis, and Table 3 shows
Contingency Analysis results for new facility thermal violations created by requested generation at 26 MW.
TABLE 5: ATC RESULTS FOR 26 MW REQUEST
Case Generation Limiting Element Limiting CTG % OTDF
ht 8.16 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer -12.38
hs 12.85 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder #2 115 kV 8.52
ht 13.16 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-1: Boulder - Lancaster 230 kV -12.79
ht 13.75 Line EASTFARM (48117) TO OTIS (48311) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV 22.45
hs 18 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -15.45
ht 18.81 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer -12.37
ht 23.08 Line BOULDERE (48522) TO IRVIN (48165) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder #1 115kV 7.63
ht 27.97 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-1: Opportunity - Otis Orchards 115 kV Open @ OTI 6.88

TABLE 6: CONTINGENCY ANALYSIS RESULTS FOR 26 MW REQUEST; THERMAL VIOLATIONS ONLY
Label Element Percent Case
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 103.58 hs
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV LANCASTR (40624) -> BELLAN11 (90011) CKT 1 at BELLAN11 101.84 ht
N-1: Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 101.83 ht
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 101.82 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 101.74 ht
BUS: Beacon South 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.63 ht
N-2 (ADJ): Bell - Taft 500 kV and Bell - Lancaster 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.27 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 101.04 ht
N-2 (ADJ): Beacon - Boulder #2 115 kV and Beacon - Ninth & Central #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at SPKINDPK 100.86 hs

Project Alternatives
1. If back-tripping ($400,000) is used to mitigate some of the existing issues, all issues created by the
additional 26 MW can be mitigated by upgrading 5.8 miles of 115 kV transmission line to a minimum
summer rating of 124 MVA for a cost of approximately $2.44 million.
2. If back-tripping is not employed, all issues created by the additional 26 MW can be mitigated by
upgrading:
a. 13.8 miles of 115 kV transmission line to a minimum summer rating of 124 MVA for $5.8 million
b. 7.1 miles of the BPA’s Bell – Lancaster 230 kV Transmission Line to a minimum summer rating of
675 MVA for $5.11 million

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Rathdrum 50 MW request; 115 kV interconnection; $10.7 to $18.7 million
Analysis
For P0 conditions, both study cases received generation up to 50 MW without issue.
For performance during contingencies, Table 2 shows results from the ATC analysis, and Table 3 shows
Contingency Analysis results for new facility thermal violations created by requested generation at 50 MW.
TABLE 7: ATC RESULTS FOR 50 MW REQUEST
Case Generation Limiting Element Limiting CTG % OTDF
ht 8.16 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer -12.38
hs 12.85 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder #2 115 kV 8.52
ht 13.16 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-1: Boulder - Lancaster 230 kV -12.79
ht 13.75 Line EASTFARM (48117) TO OTIS (48311) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV 22.45
hs 18 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -15.45
ht 18.81 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer -12.37
ht 23.08 Line BOULDERE (48522) TO IRVIN (48165) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder #1 115kV 7.63
ht 27.97 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-1: Opportunity - Otis Orchards 115 kV Open @ OTI 6.88
ht 32.72 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] BF: A290 Hot Springs 230 kV, Hot Springs-Rattlesnake 5.72
ht 33.1 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer -12.38
ht 33.9 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] BUS: Bell S3 230 kV 6.52
ht 36.77 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum -17.63
ht 36.98 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] N-1: Boulder - Lancaster 230 kV -12.79
hs 37.18 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV 26.84
ht 38.49 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-1: Beacon - Boulder 230 kV 7.19
ht 43.98 Line EASTFARM (48117) TO POST FLS (48329) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -12.47
ht 44.01 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer -12.37
ht 44.6 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: A388 Bell S2 & S3 230 kV 12.22
ht 46.05 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] PSF: Ramsey 115 kV 14.06
hs 47.62 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV -15.45
ht 47.7 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV -14.27
ht 51.76 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Bell - Taft 500 kV and Bell - Lancaster 230 kV -12.25

TABLE 8: CONTINGENCY RESULTS FOR THERMAL ISSUES; 50 MW REQUEST
Label Element Percent Case
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 107.8 hs
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 106.31 ht
N-1: Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 105.59 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 105.46 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 104.66 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 104.2 hs
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV LANCASTR (40624) -> BELLAN11 (90011) CKT 1 at BELLAN11 103.53 ht
BUS: Beacon South 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 103.3 ht
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 103.26 hs
N-1: Boulder - Lancaster 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 102.57 ht
N-2 (ADJ): Bell - Taft 500 kV and Bell - Lancaster 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.54 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 102.47 ht
N-2 (ADJ): Beacon - Boulder #2 115 kV and Beacon - Ninth & Central #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at SPKINDPK 102.09 hs
N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at SPKINDPK 101.83 hs
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 101.63 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS 101.27 ht
N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder #1 115kV BOULDERE (48522) -> IRVIN (48165) CKT 1 at BOULDERE 101.26 ht
N-1: Opportunity - Otis Orchards 115 kV Open @ OTI BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.21 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV BELLAN11 (90011) -> BELL S3 (40090) CKT 1 at BELLAN11 101.17 ht
PSF: Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.87 ht
N-1: Beacon - Boulder 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.51 ht

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Project Alternatives
1. POI at Rathdrum Station would cost an estimated $1 million
2. Project options necessary to mitigate new facility violations:
a. If back-tripping ($400,000) is used to mitigate some of the existing issues, all issues created by
the additional 50 MW can be mitigated by upgrading 22.2 miles of 115 kV transmission line to a
minimum summer rating of 131 MVA for a cost of approximately $9.3 million.
b. If back-tripping is not employed, all issues created by the additional 50 MW can be mitigated by
upgrading:
i. 29.8 miles of 115 kV transmission line to a minimum summer rating of 131 MVA for
$12.5 million
ii. 7.2 miles of the BPA’s Bell – Lancaster 230 kV Transmission Line to a summer rating of
675 MVA for $5.18 million

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Rathdrum 200 MW request; 115 kV interconnection; $10.3 to $48.5 million
Analysis
For P0 conditions, both study cases show significant loading on the local 115 kV system as shown in Figure 5.

FIGURE 5: P0 LOADING FOR 200 MW REQUEST DURING HIGH TRANSFER SCENARIO
For performance during contingencies, an additional 200 MW at Rathdrum station 115 kV buses creates facility
thermal violations for 137 unique contingency events (See Appendix C). Table 9 presents a list of all facilities
overloaded for this generation level, and it shows the sum of percent thermal overload for each facility in each
case.
TABLE 9: SUM OF FACILITY THERMAL OVERLOADS; 200 MW REQUEST
Facilities hs ht
IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 1211.48 11050.11
BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 1062.15 2939.24
PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 574.11 4778.41
RAMSEY (48349) -> PRAIRIEB (40855) CKT 1 at RAMSEY 421.5 201.68
RATHDRMW (48355) -> HUETTER (48159) CKT 1 at HUETTER 325.84
PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 324.22 2633.82
MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 260.06 4351.73
RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 239.45 422.67
HUETTER (48159) -> HERN (48155) CKT 1 at HERN 200.73
SPKINDPK (48405) -> IRVIN (48165) CKT 1 at IRVIN 110.04
OPPORTUN (48299) -> CHESTER (48069) CKT 1 at CHESTER 107.21
ROSSPARK (48371) -> THIRHACH (48431) CKT 1 at ROSSPARK 100.55
POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS 231.07
LANCASTR (40624) -> BELLAN11 (90011) CKT 1 at BELLAN11 114.64
BOULDERE (48522) -> IRVIN (48165) CKT 1 at BOULDERE 112.19
WEST (48463) -> WESTBPA2 (41276) CKT 1 at WESTBPA2 102.26
BELLAN11 (90011) -> BELL S3 (40090) CKT 1 at BELLAN11 112.03
EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 356.45
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Figure 6 shows system thermal performance after the loss of both the Kootenai – Rathdrum and Lancaster –
Rathdrum 230 kV transmission lines; this is the worst performing event.

FIGURE 6: WORST PERFORMING CONTINGENCY EVENT; HIGH TRANSFER SCENARIO
Project Alternatives
1. POI at Rathdrum Station would cost an estimated $1 million
2. Three alternatives for mitigating new facility violations:
a. If back-tripping is used to mitigate some of the existing issues, all issues created by the
additional 50 MW can be mitigated by upgrading 22.2 miles of 115 kV transmission line to a
minimum summer rating of 131 MVA for a cost of approximately $9.3 million.
b. If back-tripping is not employed, all issues created by the additional 200 MW can be mitigated
by upgrading:
i. 52.8 miles of 115 kV transmission line to a minimum summer rating of 174 MVA for
$22.2 million
ii. 7.2 miles of the BPA’s Bell – Lancaster 230 kV Transmission Line to a summer rating of
675 MVA for $5.18 million
c. Construct a new 230 kV transmission line from Rathdrum Station to a new station north of
Westside Station
i. Construct a new, 5-position 230 kV station approximately 1 mile west of Indian Trails
station alongside the 500 kV right-of-way for $11 million
1. Terminate the Bell – Westside and Coulee – Westside 230 kV transmission lines
at this station
ii. Construct a new, 35 mile 230 kV, 800 MVA summer rated transmission line from
Rathdrum station to the newly construction station for $25.2 million
iii. Upgrade 31.7 miles of 115 kV transmission lines to a summer rating greater than 156
MVA for $13.3 million
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Rathdrum 50 MW Request; 230 kV interconnection; $7 to $16.8 million
Analysis
For P0 conditions, both study cases received generation up to 50 MW without issue.
For performance during contingencies, Table 2 shows results from the ATC analysis, and Table 3 shows
Contingency Analysis results for new facility violations created by requested generation at 50 MW.
TABLE 10: ATC RESULTS FOR 50 MW REQUEST
Case Trans Lim Limiting Element Limiting CTG % OTDF
ht 3.85 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer -5.65
ht 3.86 Line EASTFARM (48117) TO OTIS (48311) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV 20.28
ht 25.55 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer -5.65
ht 26.31 Line BOULDERE (48522) TO IRVIN (48165) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder #1 115kV 5.3
ht 33.11 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-1: Opportunity - Otis Orchards 115 kV Open @ OTI 4.15
hs 34.3 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV -9.48
hs 38.3 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV 24.1
ht 39.42 Line EASTFARM (48117) TO POST FLS (48329) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV -7.6
ht 47.21 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-1: Beacon - Boulder 230 kV 5
ht 56.03 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Bell - Taft 500 kV and Bell - Lancaster 230 kV -4.55

TABLE 11: CONTINGENCY RESULTS FOR 50 MW REQUEST
Label Element Percent Case
N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 107.55 ht
N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 105.51 hs
N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 103.02 hs
N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV BELLAN11 (90011) -> BELL S3 (40090) CKT 1 at BELLAN11 102.75 ht
N-1: Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 102.67 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 102.5 ht
N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 102.06 hs
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 101.79 ht
N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS 101.18 ht
N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder #1 115kV BOULDERE (48522) -> IRVIN (48165) CKT 1 at BOULDERE 100.51 ht
N-1: Opportunity - Otis Orchards 115 kV Open @ OTI BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.49 ht

Project Alternatives
1. POI at Rathdrum Station would cost an estimated $1.5 million
2. Project options necessary to mitigate new facility violations:
a. If back-tripping is used to mitigate some of the existing issues, all issues created by the
additional 50 MW can be mitigated by upgrading 13 miles of 115 kV transmission line to a
minimum summer rating of 131 MVA for a cost of approximately $5.5 million.
b. If back-tripping is not employed, all issues created by the additional 50 MW can be mitigated by
upgrading:
i. 36.3 miles of 115 kV transmission line to a summer rating of 131 MVA for $15.2 million
ii. 0.1 miles of the BPA’s Bell – Bell AN11 230 kV Transmission Line to a summer rating of
800 MVA for $100,000

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Rathdrum 200 MW Request; 230 kV interconnection; $15.5 to $21.5 million
Analysis
For P0 conditions, both study cases received generation up to 200 MW without issue.
For performance during contingencies, Table 2 shows results from the ATC analysis, and Table 3 shows
Contingency Analysis results for new facility violations created by requested generation at 200 MW.
TABLE 12: ATC RESULTS FOR 200 MW REQUEST

Case Trans Lim Limiting Element Limiting CTG % OTDF
ht 2.69 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BUS: Ramsey 115 kV 4.57
ht 3.14 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] BUS: Otis Orchards 115 kV 3.69
ht 4.04 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Post Falls - Ramsey 115 kV & Ramsey - Rathdrum # 1 115 kV 4.51
ht 7.09 Line BENEWAH (48037) TO PINE CRK (48317) CKT 1 [230.00 - 230.00 kV] BF: A288 Hot Springs 230 kV, Hot Springs-Noxon Rapids # 1 -4.16ht10.83 Line BENEWAH (48037) TO PINE CRK (48317) CKT 1 [230.00 - 230.00 kV] BUS: Hot Springs 230 kV -4.16
ht 23.7 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]BF: A1561 Boulder-Lancaster, Lancaster Generator # 1 & # 2 -6.86
ht 26.27 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]N-1: Lancaster - Rathdrum 230 kV -11.43
hs 34.3 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV -9.48
ht 36.76 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]BF: R508 Lancaster-Rathdrum, Rathdrum # 1 230/115 Transformer -10.04hs38.3 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV 24.1
ht 41.36 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-1: Boulder - Lancaster 230 kV -5.85
ht 45.32 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] PSF: Otis Orchards 115 kV 3.69
ht 47.76 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]BF: A1558 Bell-Lancaster, Lancaster-Rathdrum -11.48
ht 49.09 Line EASTFARM (48117) TO OTIS (48311) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV 6.29ht50.42 Line PRAIRIEB (40855) TO RAMSEY (48349) CKT 1 [115.00 - 115.00 kV] BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum -9.7
ht 57.6 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]BF: A388 Bell S2 & S3 230 kV -4.5
ht 59.23 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]BF: R408 Lancaster-Rathdrum, Rathdrum # 2 230/115 Transformer -9.33
ht 63.75 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer -5.65
ht 64.36 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer -5.65ht66.1 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]BF: R508 Lancaster-Rathdrum, Rathdrum # 1 230/115 Transformer -10.04
ht 73.78 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Beacon - Rathdrum 230kV and Lancaster - Noxon 230kV 4.87
ht 73.88 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]BF: A1558 Bell-Lancaster, Lancaster-Rathdrum -11.48
ht 73.99 Line IRVIN (48165) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV -8.05
hs 77.96 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV -9.48ht79.55 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]BF: A1561 Boulder-Lancaster, Lancaster Generator # 1 & # 2 -5.85
hs 88.83 Line MOAB (47511) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV -24.1
ht 91.38 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]BF: R408 Lancaster-Rathdrum, Rathdrum # 2 230/115 Transformer -9.33
ht 96.43 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] N-1: Lancaster - Rathdrum 230 kV -9.46
hs 102.87 Line BOULDERE (48522) TO MOAB (47511) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV -24.1ht114.54 Line BELLAN11 (90011) TO LANCASTR (40624) CKT 1 [230.00 - 230.00 kV] BF: R427 Beacon North & South 230 kV -32.19
ht 115.07 Line BELLAN11 (90011) TO LANCASTR (40624) CKT 1 [230.00 - 230.00 kV] N-2 (STR): Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV -31.02
hs 119.79 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV -24.1
ht 119.94 Line HUETTER (48159) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV -13.17
ht 137.25 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] BF: A1558 Bell-Lancaster, Lancaster-Rathdrum -9.49ht137.57 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] N-1: Lancaster - Rathdrum 230 kV -11.43
hs 140.52 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder # 2 115 kV 6.08
ht 145.93 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] BF: R508 Lancaster-Rathdrum, Rathdrum # 1 230/115 Transformer -8.32
hs 146.04 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Beacon - Boulder # 2 115 kV and Beacon - Ninth & Central # 2 115 kV 3.84
ht 154.16 Line HERN (48155) TO HUETTER (48159) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV -13.17ht154.96 Line BELL S3 (40090) TO BELLAN11 (90011) CKT 1 [230.00 - 230.00 kV] BF: R427 Beacon North & South 230 kV -32.19
ht 157.02 Line BELL S3 (40090) TO BELLAN11 (90011) CKT 1 [230.00 - 230.00 kV] N-2 (STR): Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV -31.02
ht 160.88 Line HERN (48155) TO RAMSEY (48349) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV 13.17
ht 166 Line IDAHO_RD (48161) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BF: A1186 Lancaster-Noxon, Boulder-Lancaster -6.08
hs 180.74 Line PRAIRIEB (40855) TO RAMSEY (48349) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV -20.29ht185.55 Line IRVIN (48165) TO MILLWOOD (48237) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV 7.57
hs 198.16 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer 5.92
hs 198.55 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer 5.91
ht 201.01 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] BF: A1186 Lancaster-Noxon, Boulder-Lancaster -4.95
hs 215.17 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV] N-2: Beacon - Boulder 230 kV & Boulder - Irvin # 2 115 kV 7.15hs216.58 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] N-1: Boulder - Lancaster 230 kV 6.12
hs 231.38 Line IRVIN (48165) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV]BF: R427 Beacon North & South 230 kV -7.57
hs 238.18 Line PRAIRIEB (40855) TO RAMSEY (48349) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV -7.97
hs 243.76 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV -7.97
hs 293.13 Line HUETTER (48159) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BUS: Rathdrum East 115 kV -4.51hs299.93 Line HUETTER (48159) TO RATHDRMW (48355) CKT 1 [115.00 - 115.00 kV] BF: A506 Rathdrum 115 kV, Pine Street-Rathdrum -4.51
hs 301.74 Line PRAIRIEB (40855) TO RAMSEY (48349) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV -6.59
hs 311.86 Line POST FLS (48329) TO PRAIRIEB (40855) CKT 1 [115.00 - 115.00 kV] N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV -6.59
ht 326.58 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BUS: Bell S3 230 kV 5.36
ht 326.58 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: A572 Bell S3 230 kV, Bell-Boundary # 3 5.36ht337.01 Line IDAHO_RD (48161) TO PLEASANT (48319) CKT 1 [115.00 - 115.00 kV] BF: 4148 Garrison-Taft # 2, Hot Springs-Taft 3.92
hs 368.83 Line CHESTER (48069) TO OPPORTUN (48299) CKT 1 [115.00 - 115.00 kV] BF: A600 Beacon North & South 115 kV -4.37
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TABLE 13: NEW FACILITY THERMAL VIOLATIONS FOR 200 MW REQUEST

Project Alternatives
1. POI at Rathdrum Station would cost an estimated $1.5 million
2. Project options necessary to mitigate new facility violations:
a. If back-tripping is used to mitigate some of the existing issues, all issues created by the
additional 200 MW can be mitigated by upgrading 33.4 miles of 115 kV transmission line to a
minimum summer rating of 175 MVA for a cost of approximately $14.0 million.
b. If back-tripping is not employed, all issues created by the additional 200 MW can be mitigated
by upgrading:
i. 47.3 miles of 115 kV transmission line to a minimum summer rating of 175 MVA for
$19.9 million
ii. 0.1 miles of the BPA’s Bell – Bell AN11 230 kV Transmission Line to a summer rating of
800 MVA for $100,000
Label Element Percent Case
N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 142.76 hsN-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 131.27 ht
N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 130.97 hsN-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 127.64 hs
N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 122.3 hs
N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 118.82 hs
N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 116.18 hs
N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV BELLAN11 (90011) -> BELL S3 (40090) CKT 1 at BELLAN11 115 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 113.44 ht
N-1: Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 112.61 htBF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 112.19 ht
BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 111.32 htN-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS 110.94 ht
N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 110.38 hs
N-1: Boulder - Lancaster 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 109.6 ht
BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 109.21 ht
BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 108.3 htN-1: Lancaster - Rathdrum 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 107.27 ht
N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder # 1 115kV BOULDERE (48522) -> IRVIN (48165) CKT 1 at BOULDERE 107.21 htN-2 (ADJ): Beacon - Rathdrum 230kV and Bell - Lancaster 230kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.79 ht
N-2 (STR): Beacon - Rathdrum 230 kV & Boulder - Lancaster 230 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 106.51 ht
N-1: Beacon - Boulder 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.09 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 105.96 ht
BF: A1561 Boulder-Lancaster, Lancaster Generator # 1 & # 2 IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.65 htN-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 105.63 hs
N-1: Opportunity - Otis Orchards 115 kV Open @ OTI BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.41 htBF: A1186 Lancaster-Noxon, Boulder-Lancaster IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.28 ht
N-2 (ADJ): Beacon - Rathdrum 230kV and Bell - Lancaster 230kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.18 ht
BUS: Beacon North 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 104.83 ht
N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder # 2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 103.8 hs
PSF: Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 103.54 htBF: R508 Lancaster-Rathdrum, Rathdrum # 1 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 103.27 ht
N-2 (STR): Beacon - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV RAMSEY (48349) -> PRAIRIEB (40855) CKT 1 at RAMSEY 103.24 hsBF: A1184 Lancaster-Noxon, Lancaster-Rathdrum MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 103.02 ht
N-1: Opportunity - Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.9 ht
N-2 (ADJ): Beacon - Boulder # 2 115 kV and Beacon - Ninth & Central # 2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.01 hs
N-2: Beacon - Boulder 230 kV & Beacon - Irvin # 1 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.87 ht
BF: A645 Otis Orchards 115 kV, Boulder-Otis Orchards BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.36 htBUS: Beacon North 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.31 ht
BF: R427 Beacon North & South 230 kV SPKINDPK (48405) -> IRVIN (48165) CKT 1 at IRVIN 101.28 hsBF: R408 Lancaster-Rathdrum, Rathdrum # 2 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.16 ht
BF: R554 Boulder-Lancaster, Boulder # 1 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.15 hsN-1: Beacon - Rathdrum 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.15 ht
BF: R454 Boulder-Lancaster, Boulder # 2 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.12 hs
BF: A717 Boulder East & West 115 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 100.94 ht
BF: A1558 Bell-Lancaster, Lancaster-Rathdrum IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.8 ht
N-2: Beacon - Boulder 230 kV & Boulder - Irvin # 2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.68 hsN-1: Opportunity - Otis Orchards 115 kV Open @ OPT BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.67 ht
N-1: Boulder - Lancaster 230 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 100.59 htBF: A667 Ramsey 115 kV, Appleway-Ramsey IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.53 ht
BF: A668 Ramsey 115 kV, Ramsey-Rathdrum # 1 IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.48 ht
N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS 100.35 ht
N-2 (ADJ): Beacon - Bell # 4 230kV and Beacon - Rathdrum 230kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.3 ht
N-1: Beacon - Rathdrum 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.28 htN-2 (ADJ): Beacon - Bell # 4 230kV and Beacon - Rathdrum 230kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.27 ht
BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.04 ht
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Thornton Station
Thornton 30 MW and 100 MW Request; $400,000
Two incremental wind energy outputs were requested for this station: 30 MW and 100 MW. These requests
were studied as coming from a single wind plant as depicted in Figure 7:

FIGURE 7: THORNTON WIND REQUEST; 2024 HEAVY SUMMER CASE

Analysis
For P0 conditions, both study cases received generation up to 100 MW without issue.
For performance during contingencies, Table 2 shows results from the ATC analysis, and Table 3 shows
Contingency Analysis results for existing facility violations exacerbated by requested generation at 100 MW.
TABLE 14: ATC RESULTS FOR THORNTON WIND REQUEST

Case Trans Lim Limiting Element Limiting CTG % OTDF
19ht 25.07 Line BOULDERE (48522) TO IRVIN (48165) CKT 1 [115.00 - 115.00 kV]N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder # 1 115kV 5.32
24hs 36.5 Line IRVIN (48165) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV]BF: R427 Beacon North & South 230 kV -5.2319ht45.81 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV]N-1: Beacon - Boulder 230 kV 5.03
24hs 110.87 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV]N-1: Boulder - Irvin # 2 115 kV 3.81
24hs 138.73 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV]N-2 (STR): Beacon - Boulder 230 kV & Beacon - Rathdrum 230 kV 5.95
19ht 141.46 Line BOULDERW (48520) TO SPKINDPK (48405) CKT 1 [115.00 - 115.00 kV]N-2: Beacon - Boulder 230 kV & Beacon - Irvin # 1 115 kV 4.62
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TABLE 15: THERMAL FACILITY VIOLATIONS EXACERBATED BY NEW GENERATION

Project Alternatives
POI at Thornton Station would cost an estimated $400,000

Label Element Percent Case
N-2: Beacon - Boulder 230 kV & Boulder - Irvin # 2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.63 24hs
BF: R427 Beacon North & South 230 kV SPKINDPK (48405) -> IRVIN (48165) CKT 1 at IRVIN 104.47 24hs
N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder # 1 115kV BOULDERE (48522) -> IRVIN (48165) CKT 1 at BOULDERE 103.7 19ht
N-1: Beacon - Boulder 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.83 19ht
BF: A600 Beacon North & South 115 kV OPPORTUN (48299) -> CHESTER (48069) CKT 1 at CHESTER 102.27 24hs
N-1: Opportunity - Otis Orchards 115 kV Open @ OTI BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.1 19ht
BF: A645 Otis Orchards 115 kV, Boulder-Otis Orchards BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.83 24hs
BUS: Beacon North 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.07 19ht
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Othello Station
Othello 25 MW Solar request; $2 million
This request involves interconnecting up to 25 MW of solar generation, which is modeled in this study as a
simple generic source at the Othello Switching Station as show in Figure 8.

FIGURE 8: OTHELLO GENERATION REQUEST; 2024 HEAVY SUMMER CASE
Analysis
For P0 conditions, both study cases received generation up to 25 MW without issue.
For performance during contingencies, Table 16 shows results from the ATC analysis, and there are no new
facility violations created by requested generation at 25 MW.
TABLE 16: ATC RESULTS FOR OTHELLO GENERATION REQUEST

Project Alternatives
POI at Othello Station would cost an estimated $2 million
Case Trans Lim Limiting Element Limiting CTG % OTDF
ht 95.58 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-1: Othello SS - Warden # 2 115 kV Open @ OSS 60.49ht105.61 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-1: Othello SS - Warden # 2 115 kV (OSS-L&R)60.49
ht 107.02 Line OTHELLO (48307) TO OTHELOSS (48309) CKT 1 [115.00 - 115.00 kV]N-1: Othello SS - Warden # 1 115 kV -54.95ht110.59 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-2 (ADJ): Benton - Midway # 2 230 kV and Benton - Othello SS 115 kV 62.79
ht 110.64 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-1: Benton - Othello SS 115 kV (OSS-SOT)62.79
ht 110.68 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-1: Benton - Othello SS 115 kV Open @ OSS 62.79
hs 115.23 Line OTHELLO (48307) TO OTHELOSS (48309) CKT 1 [115.00 - 115.00 kV]N-1: Benton - Othello SS 115 kV Open @ OSS -37.21
hs 115.29 Line OTHELLO (48307) TO OTHELOSS (48309) CKT 1 [115.00 - 115.00 kV]N-2 (ADJ): Benton - Midway # 2 230 kV and Benton - Othello SS 115 kV -37.21
hs 115.35 Line OTHELLO (48307) TO OTHELOSS (48309) CKT 1 [115.00 - 115.00 kV]N-1: Benton - Othello SS 115 kV (OSS-SOT)-37.21
hs 115.43 Line OTHELLO (48307) TO OTHELOSS (48309) CKT 1 [115.00 - 115.00 kV]N-2 (ROW): Benton - Midway # 2 230 kV and Benton - Midway # 1 115 kV and Benton - Othello SS 115 kV -37.21
hs 115.52 Line OTHELLO (48307) TO OTHELOSS (48309) CKT 1 [115.00 - 115.00 kV]N-2 (ADJ): Benton - Midway # 1 115 kV and Benton - Othello SS 115 kV -37.21
hs 115.88 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-1: Othello SS - Warden # 2 115 kV Open @ OSS 60.65hs119.53 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-1: Benton - Othello SS 115 kV Open @ OSS 62.79
hs 119.59 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-2 (ADJ): Benton - Midway # 2 230 kV and Benton - Othello SS 115 kV 62.79hs119.65 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-1: Benton - Othello SS 115 kV (OSS-SOT)62.79
hs 119.74 Line OTHELOSS (48309) TO WARDEN A (48455) CKT 1 [115.00 - 115.00 kV]N-2 (ROW): Benton - Midway # 2 230 kV and Benton - Midway # 1 115 kV and Benton - Othello SS 115 kV 62.79ht125.82 Line OTHELLO (48307) TO OTHELOSS (48309) CKT 1 [115.00 - 115.00 kV]N-1: Benton - Othello SS 115 kV Open @ OSS -37.21
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Northeast Station
Northeast 10 MW; $0
This request involves interconnecting up to 10 MW of additional generation, which is modeled in this study as a
simple generic source at the Northeast Station as show in Error! Reference source not found..

FIGURE 9: NORTHEST GENERATION REQUEST; 2024 HEAVY SUMMER CASE
Analysis
For P0 conditions, both study cases received generation up to 10 MW without issue.
For performance during contingencies, Table 17 shows results from the ATC analysis, and there are no new
facility violations created by requested generation at 10 MW.
TABLE 17: ATC RESULTS FOR NORTHEAST GENERATION REQUEST

Project Alternatives
None required
Case Trans Lim Limiting Element Limiting CTG % OTDFht76.49 Line BEACON N (48023) TO NORTHEAS (48277) CKT 1 [115.00 - 115.00 kV]N-2 (ROW and ADJ): Beacon - Francis & Cedar 115 kV and Bell - Northeast 115 kV -100
ht 76.52 Line BEACON N (48023) TO NORTHEAS (48277) CKT 1 [115.00 - 115.00 kV]N-1: Bell - Northeast 115 kV -100ht76.55 Line BEACON N (48023) TO NORTHEAS (48277) CKT 1 [115.00 - 115.00 kV]N-1: Bell - Northeast 115 kV Open @ NE -100ht77.16 Line BEACON N (48023) TO NORTHEAS (48277) CKT 1 [115.00 - 115.00 kV]BF: B356 Bell 115 kV, Bell-Northeast -100
ht 89.73 Line BEACON N (48023) TO NORTHEAS (48277) CKT 1 [115.00 - 115.00 kV]BF: B346 Bell 115 kV, Addy-Bell -100ht93.44 Line BELL BPA (40087) TO WAIKIKIT (48449) CKT 1 [115.00 - 115.00 kV]N-2 (ROW): Beacon - Bell # 5 230 kV and Beacon - Francis & Cedar 115 kV and Beacon - Northeast 115 kV -100
ht 94.58 Line BELL BPA (40087) TO WAIKIKIT (48449) CKT 1 [115.00 - 115.00 kV]BF: A600 Beacon North & South 115 kV -100
ht 94.64 Line BELL BPA (40087) TO WAIKIKIT (48449) CKT 1 [115.00 - 115.00 kV]N-2 (ROW): Beacon - Bell # 4 230 kV and Beacon - Bell # 1 115 kV and Beacon - Northeast 115 kV and Beacon - Francis & Cedar 115 kV -100ht95.3 Line NORTHEAS (48277) TO WAIKIKIT (48449) CKT 1 [115.00 - 115.00 kV]BF: A572 Bell S3 230 kV, Bell-Boundary # 3 62.72
ht 95.42 Line NORTHEAS (48277) TO WAIKIKIT (48449) CKT 1 [115.00 - 115.00 kV]BUS: Bell S3 230 kV 62.72ht97.6 Line NORTHEAS (48277) TO WAIKIKIT (48449) CKT 1 [115.00 - 115.00 kV]N-2 (ROW): Bell - Taft 500 kV and Bell - Lancaster 230 kV and Beacon - Rathdrum 230 kV and Boulder - Lancaster 230 kV 62.09ht98.22 Line NORTHEAS (48277) TO WAIKIKIT (48449) CKT 1 [115.00 - 115.00 kV]N-2 (ADJ): Bell - Taft 500 kV and Bell - Lancaster 230 kV 62.11
ht 101.71 Line BOULDER (48524) TO BENEWAH (48037) CKT 1 [230.00 - 230.00 kV]N-2 (ROW): Bell - Coulee # 6 500 kV and Bell - Coulee # 3 230 kV and Bell - Coulee # 5 230 kV and Coulee - Westside 230 kV and Bell - Creston 115 kV 12.81
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Kettle Falls Station
Kettle Falls 10 MW; $0
This request involves interconnecting up to 10 MW of additional generation, which is modeled in this study as a
simple generic source at the Kettle Falls Station as shown in Figure 10.

FIGURE 10: KETTLE FALLS GENERATION REQUEST; 2024 HEAVY SUMMER CASE
Analysis
For P0 conditions, both study cases received generation up to 10 MW without issue.
For performance during contingencies, Table 18 shows results from the ATC analysis, and there are no new
facility violations created by requested generation at 10 MW.
TABLE 18: ATC RESULTS FOR KETTLE FALLS GENERATION REQUEST

Project Alternatives
No mitigating steps are necessary for this request
Case Trans Lim Limiting Element Limiting CTG % OTDF
ht 76.04 Line GREENWDA (48143) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV] N-1: Addy - Colville BPA 115 kV -63.23ht76.3 Line GREENWDA (48143) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV] N-1: Kettle Falls Tap 115 kV -100ht76.32 Line GREENWDA (48143) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV] N-1: Kettle Falls Tap 115 kV Open @ KET -100
ht 76.74 Line KETTLE T (40607) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV]BF: B1145 Addy 115 kV, Addy-Kettle Falls -100
ht 76.75 Line KETTLE T (40607) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV]N-1: Addy - Kettle Falls 115 kV Open @ KET -100ht77.26 Line GREENWDA (48143) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV] BF: B1768 Colville BPA 115 kV, Colville BPA-Kettle Falls -100ht77.98 Line KETTLE T (40607) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV]N-1: Addy - Kettle Falls 115 kV -100
ht 79.91 Line COLV AVA (48083) TO GREENWDA (48143) CKT 1 [115.00 - 115.00 kV] N-1: Kettle Falls Tap 115 kV Open @ KET -100
ht 79.92 Line COLV AVA (48083) TO GREENWDA (48143) CKT 1 [115.00 - 115.00 kV] N-1: Kettle Falls Tap 115 kV -100
ht 80.93 Line COLV AVA (48083) TO GREENWDA (48143) CKT 1 [115.00 - 115.00 kV] BF: B1768 Colville BPA 115 kV, Colville BPA-Kettle Falls -100ht81.78 Line COLV AVA (48083) TO GREENWDA (48143) CKT 1 [115.00 - 115.00 kV] N-1: Addy - Colville BPA 115 kV -63.23ht83.12 Line GREENWDA (48143) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV] BF: B1766 Colville BPA 115 kV, Boundary-Box Canyon-Colville BPA -100
ht 86.75 Line COLV AVA (48083) TO GREENWDA (48143) CKT 1 [115.00 - 115.00 kV] BUS: Colville 115 kV -100
hs 89.01 Line GREENWDA (48143) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV] N-1: Kettle Falls Tap 115 kV -100hs89.01 Line GREENWDA (48143) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV] N-1: Kettle Falls Tap 115 kV Open @ KET -100hs89.15 Line KETTLE T (40607) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV]BF: B1145 Addy 115 kV, Addy-Kettle Falls -100
hs 89.15 Line KETTLE T (40607) TO KETTLEAV (48175) CKT 1 [115.00 - 115.00 kV]N-1: Addy - Kettle Falls 115 kV Open @ KET -100
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Long Lake Dam
Long Lake 68 MW; $19.7 million
This request involves adding 68 MW at Long Lake station, which is modeled in this study as two generators, one
at each 115 kV bus as shown in Figure 11.

FIGURE 11: LONG LAKE GENERATION REQUEST; 2024 HEAVY SUMMER CASE
Analysis
For P0 conditions, both study cases received generation up to 68 MW without issue.
For performance during contingencies, Table 19 shows results from the ATC analysis, and Table 20 shows
Contingency Analysis results for new facility violations created by requested generation.

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TABLE 19: ATC RESULTS FOR LONG LAKE GENERATION REQUEST

Case Trans Lim Limiting Element Limiting CTG % OTDF
ht 9.73 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] N-1: Airway Heights - Devils Gap 115 kV Open @ DGP 65.77
ht 11.39 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] N-1: Airway Heights - Devils Gap 115 kV 65.77
ht 12.27 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap 65.77
ht 12.29 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] PSF: Airway Heights 115 kV 65.77
ht 16.64 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]N-1: Airway Heights - Devils Gap 115 kV Open @ DGP 65.77
ht 18.37 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]N-1: Airway Heights - Devils Gap 115 kV 65.77
ht 19.17 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap 65.77
ht 19.19 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]PSF: Airway Heights 115 kV 65.77
ht 20.62 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] N-1: Airway Heights - Devils Gap 115 kV Open @ AIR 65.77
ht 26.21 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV Open @ NMS 62.44
ht 26.4 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV 62.44
ht 27.63 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]N-1: Airway Heights - Devils Gap 115 kV Open @ AIR 65.77
ht 29.37 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] PSF: Westside 115 kV 60.74
ht 31.29 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV Open @ WES 62.44
ht 31.45 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV 62.35
ht 33.76 Line AIRWAYHT (48009) TO GARDENSP (48131) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV Open @ NMS 62.44
ht 33.94 Line AIRWAYHT (48009) TO GARDENSP (48131) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV 62.44
hs 34.7 Line DEVILGPE (48103) TO LONGLAKE (48201) CKT 1 [115.00 - 115.00 kV] N-1: Devils Gap - Long Lake # 2 115 kV -100
hs 34.88 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] PSF: Westside 115 kV 60.14
hs 35.15 Line DEVILGPE (48103) TO LONGLAKW (48199) CKT 1 [115.00 - 115.00 kV] N-1: Devils Gap - Long Lake # 1 115 kV -100
ht 35.38 Line DEVILGPE (48103) TO LONGLAKE (48201) CKT 1 [115.00 - 115.00 kV] N-1: Devils Gap - Long Lake # 2 115 kV -100
ht 35.54 Line DEVILGPE (48103) TO LONGLAKW (48199) CKT 1 [115.00 - 115.00 kV] N-1: Devils Gap - Long Lake # 1 115 kV -100
hs 37.06 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] BF: A413 Westside 115 kV, Ninemile-Westside 60.75
ht 37.11 Line AIRWAYHT (48009) TO GARDENSP (48131) CKT 1 [115.00 - 115.00 kV] PSF: Westside 115 kV 60.74
ht 38.74 Line AIRWAYHT (48009) TO GARDENSP (48131) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV Open @ WES 62.44
ht 38.98 Line AIRWAYHT (48009) TO GARDENSP (48131) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV 62.35
ht 41.13 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV Open @ NMS -62.44
ht 41.3 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV -62.44
hs 42.44 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] N-1: Airway Heights - Devils Gap 115 kV Open @ DGP 65.77
hs 44.63 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] N-1: Airway Heights - Devils Gap 115 kV 65.77
ht 44.68 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] PSF: Westside 115 kV -60.74
ht 46.1 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV Open @ WES -62.44
hs 46.32 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap 65.77
ht 46.35 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV -62.35
hs 46.38 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] PSF: Airway Heights 115 kV 65.77
hs 46.64 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV 62.35
hs 46.67 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV Open @ NMS 62.45
hs 46.98 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV 62.45
hs 48.6 Line DEVILGPE (48103) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] BUS: Westside 115 kV 60.75
hs 56.53 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] PSF: Westside 115 kV -60.14
ht 56.57 Line DEVILGPE (48103) TO NINEMILE (48269) CKT 1 [115.00 - 115.00 kV] N-1: Airway Heights - Devils Gap 115 kV Open @ DGP 65.77
hs 57.61 Line NINEMILE (48269) TO INDTRAIL (48164) CKT 1 [115.00 - 115.00 kV] N-1: Airway Heights - Devils Gap 115 kV Open @ AIR 65.77
ht 58.07 Line DEVILGPE (48103) TO NINEMILE (48269) CKT 1 [115.00 - 115.00 kV] N-1: Airway Heights - Devils Gap 115 kV 65.77
hs 58.28 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] BF: A413 Westside 115 kV, Ninemile-Westside -60.75
ht 58.92 Line DEVILGPE (48103) TO NINEMILE (48269) CKT 1 [115.00 - 115.00 kV] BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap 65.77
ht 58.92 Line DEVILGPE (48103) TO NINEMILE (48269) CKT 1 [115.00 - 115.00 kV] PSF: Airway Heights 115 kV 65.77
hs 59.85 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]N-1: Airway Heights - Devils Gap 115 kV Open @ DGP 65.77
hs 62.25 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]N-1: Airway Heights - Devils Gap 115 kV 65.77
hs 63.91 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap 65.77
hs 63.91 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]PSF: Airway Heights 115 kV 65.77
hs 67.15 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV Open @ NMS -62.45
ht 67.21 Line DEVILGPE (48103) TO NINEMILE (48269) CKT 1 [115.00 - 115.00 kV] N-1: Airway Heights - Devils Gap 115 kV Open @ AIR 65.77
hs 67.62 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV -62.35
hs 67.96 Line AIRWAYHT (48009) TO W.PLAINS (47513) CKT 1 [115.00 - 115.00 kV] N-1: Nine Mile - Westside 115 kV -62.45
hs 74.67 Line INDTRAIL (48164) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]N-1: Airway Heights - Devils Gap 115 kV Open @ AIR 65.77
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TABLE 20: NEW FACILIYT THERMAL VIOLATIONS FOR 68 MW REQUEST

Label Element Percent Case
N-1: Devils Gap - Long Lake # 2 115 kV LONGLAKE (48201) -> DEVILGPE (48103) CKT 1 at LONGLAKE 130.97 hs
N-1: Devils Gap - Long Lake # 1 115 kV LONGLAKW (48199) -> DEVILGPE (48103) CKT 1 at LONGLAKW 130.95 hsN-1: Devils Gap - Long Lake # 2 115 kV LONGLAKE (48201) -> DEVILGPE (48103) CKT 1 at LONGLAKE 125.79 ht
N-1: Devils Gap - Long Lake # 1 115 kV LONGLAKW (48199) -> DEVILGPE (48103) CKT 1 at LONGLAKW 125.78 ht
N-1: Airway Heights - Devils Gap 115 kV Open @ DGP NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 124.01 ht
N-1: Airway Heights - Devils Gap 115 kV NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 123.88 ht
BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 123.51 ht
PSF: Airway Heights 115 kV NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 123.51 ht
N-1: Airway Heights - Devils Gap 115 kV Open @ DGP INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 121.13 ht
N-1: Airway Heights - Devils Gap 115 kV INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 121 ht
PSF: Airway Heights 115 kV INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 120.6 ht
BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 120.6 ht
N-1: Airway Heights - Devils Gap 115 kV Open @ AIR NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 119.94 ht
BUS: Airway Heights 115 kV NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 119.54 ht
N-1: Airway Heights - Devils Gap 115 kV Open @ AIR INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 117.06 ht
N-1: Nine Mile - Westside 115 kV Open @ NMS DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 116.91 htN-1: Nine Mile - Westside 115 kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 116.85 htBUS: Airway Heights 115 kV INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 116.64 ht
PSF: Westside 115 kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 115.4 ht
N-1: Nine Mile - Westside 115 kV Open @ WES DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 114.99 ht
N-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 114.79 ht
BF: A413 Westside 115 kV, Ninemile-Westside DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 114.76 ht
N-1: Nine Mile - Westside 115 kV Open @ NMS AIRWAYHT (48009) -> GARDENSP (48131) CKT 1 at AIRWAYHT 114.64 ht
N-1: Nine Mile - Westside 115 kV AIRWAYHT (48009) -> GARDENSP (48131) CKT 1 at AIRWAYHT 114.57 ht
PSF: Westside 115 kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 113.35 hs
BUS: Westside 115 kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 112.95 ht
BF: A413 Westside 115 kV, Ninemile-Westside DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 112.87 hs
PSF: Westside 115 kV AIRWAYHT (48009) -> GARDENSP (48131) CKT 1 at AIRWAYHT 112.67 ht
BF: A470 Westside 115 kV, College & Walnut-Westside DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 112.67 ht
N-1: Nine Mile - Westside 115 kV Open @ WES AIRWAYHT (48009) -> GARDENSP (48131) CKT 1 at AIRWAYHT 112.28 htN-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV AIRWAYHT (48009) -> GARDENSP (48131) CKT 1 at AIRWAYHT 112.07 htBF: A413 Westside 115 kV, Ninemile-Westside AIRWAYHT (48009) -> GARDENSP (48131) CKT 1 at AIRWAYHT 111.91 ht
N-1: Nine Mile - Westside 115 kV Open @ NMS W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 111.27 ht
N-1: Nine Mile - Westside 115 kV W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 111.21 ht
N-1: Airway Heights - Devils Gap 115 kV Open @ DGP NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 110.56 hs
N-1: Airway Heights - Devils Gap 115 kV NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 110.37 hs
PSF: Westside 115 kV W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 109.78 ht
BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 109.7 hs
PSF: Airway Heights 115 kV NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 109.7 hs
BUS: Westside 115 kV AIRWAYHT (48009) -> GARDENSP (48131) CKT 1 at AIRWAYHT 109.69 ht
N-1: Airway Heights - Garden Springs 115 kV NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 109.64 ht
N-2: Airway Heights - Garden Springs 115 kV and Garden Springs - Westside 115 kV NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 109.48 ht
N-1: Nine Mile - Westside 115 kV Open @ WES W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 109.35 ht
N-1: Nine Mile - Westside 115 kV Open @ NMS DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 109.33 hsBF: A470 Westside 115 kV, College & Walnut-Westside AIRWAYHT (48009) -> GARDENSP (48131) CKT 1 at AIRWAYHT 109.32 htN-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 109.26 hs
N-1: Nine Mile - Westside 115 kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 109.19 hs
N-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 109.14 ht
BF: A413 Westside 115 kV, Ninemile-Westside W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 109.14 ht
BUS: Westside 115 kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 108.26 hs
BF: A470 Westside 115 kV, College & Walnut-Westside DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 107.77 hs
BUS: Westside 115 kV W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 107.33 ht
BF: A470 Westside 115 kV, College & Walnut-Westside W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 107.06 ht
N-1: Airway Heights - Garden Springs 115 kV INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 106.74 ht
N-2: Airway Heights - Garden Springs 115 kV and Garden Springs - Westside 115 kV INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 106.57 ht
PSF: Westside 115 kV W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 105.42 hs
BF: A413 Westside 115 kV, Ninemile-Westside W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 105.03 hs
N-1: Airway Heights - Devils Gap 115 kV Open @ DGP DEVILGPE (48103) -> NINEMILE (48269) CKT 1 at DEVILGPE 104.82 htN-1: Airway Heights - Devils Gap 115 kV Open @ AIR NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 104.77 hsN-1: Airway Heights - Devils Gap 115 kV DEVILGPE (48103) -> NINEMILE (48269) CKT 1 at DEVILGPE 104.69 ht
BUS: Nine Mile 115 kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 104.5 ht
N-1: Nine Mile - Westside 115 kV Open @ WES DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 104.46 hs
PSF: Nine Mile 115 kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 104.44 ht
BF: A655 Ninemile 115 kV, Ninemile-Westside DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 104.44 ht
PSF: Airway Heights 115 kV DEVILGPE (48103) -> NINEMILE (48269) CKT 1 at DEVILGPE 104.29 ht
BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap DEVILGPE (48103) -> NINEMILE (48269) CKT 1 at DEVILGPE 104.29 ht
BUS: Airway Heights 115 kV NINEMILE (48269) -> INDTRAIL (48164) CKT 1 at NINEMILE 104.1 hs
N-1: Devils Gap - Nine Mile 115 kV DEVILGPE (48103) -> W.PLAINS (47513) CKT 1 at DEVILGPE 104.04 ht
N-1: Airway Heights - Devils Gap 115 kV Open @ DGP INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 103.57 hs
N-1: Airway Heights - Devils Gap 115 kV INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 103.4 hs
PSF: Airway Heights 115 kV INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 102.69 hs
BF: A180 Airway Heights 115 kV, Airway Heights-Devils Gap INDTRAIL (48164) -> WEST (48461) CKT 1 at INDTRAIL 102.69 hs
N-1: Nine Mile - Westside 115 kV Open @ NMS W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 101.58 hsN-2 (ADJ): Coulee - Westside 230kV and Nine Mile - Westside 115kV W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 101.48 hsN-1: Nine Mile - Westside 115 kV W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 101.45 hs
N-1: Airway Heights - Devils Gap 115 kV Open @ AIR DEVILGPE (48103) -> NINEMILE (48269) CKT 1 at DEVILGPE 100.72 ht
BUS: Westside 115 kV W.PLAINS (47513) -> AIRWAYHT (48009) CKT 1 at W.PLAINS 100.42 hs
BUS: Airway Heights 115 kV DEVILGPE (48103) -> NINEMILE (48269) CKT 1 at DEVILGPE 100.32 ht
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Project Alternatives; $19.7 million
The level of generation requested at Long Lake can be integrated with the following projects:
1. Construct a new 115 kV transmission line between Reardan and Silver Lake
a. Build a new 3 position 115 kV station at Reardan; $4 million
b. Build a new 4 position 115 kV station at Silver Lake; $5 million
c. Construct 18 miles of 115 kV transmission line with a minimum summer rating of 138 MVA
between the new stations; $7.56 million
2. Rebuild 15.7 miles of existing 115 kV transmission line to minimum summer rating of 205 MVA; $3.14
million

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Monroe Street
Monroe Street 80 MW; $7 million
This request involves adding 80 MW at Monroe Street, which is modeled in this study as a single generator at
Post Street station as shown in Figure 12.

FIGURE 12: MONROE STREET GENERATION REQUEST; 2024 HEAVY SUMMER CASE
Analysis
For P0 conditions, both study cases received generation up to 80 MW without issue.
For performance during contingencies, Table 21 shows results from the ATC analysis. No new facility violations
were discovered for the requested generation.

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TABLE 21: ATC RESULTS FOR MONROE STREET GENERATION REQUEST

Project Alternatives
While the study connected the new generation at Post Street station, this is not a feasible POI. The POI for this
request would be chosen as College and Walnut Station, and this would cost an estimated $7 million
Case Trans Lim Limiting Element Limiting CTG % OTDF
hs 146.85 Line POSTSTRT (48339) TO THIRHACH (48431) CKT 1 [115.00 - 115.00 kV] PSF: Sunset 115 kV 72.49
hs 148.05 Line POSTSTRT (48339) TO THIRHACH (48431) CKT 1 [115.00 - 115.00 kV] BUS: Metro 115 kV 72.82
hs 148.65 Line POSTSTRT (48339) TO THIRHACH (48431) CKT 1 [115.00 - 115.00 kV] N-1: Metro - Post Street 115 kV 72.82
hs 151.06 Line POSTSTRT (48339) TO THIRHACH (48431) CKT 1 [115.00 - 115.00 kV] N-1: Metro - Sunset 115 kV 72.82
hs 157.62 Line POSTSTRT (48339) TO THIRHACH (48431) CKT 1 [115.00 - 115.00 kV] BUS: Sunset 115 kV 72.49
hs 194.06 Line METRO (48225) TO SUNSET (48421) CKT 1 [115.00 - 115.00 kV]N-1: Post Street - Third & Hatch 115 kV 60.99
hs 208.98 Line METRO (48225) TO SUNSET (48421) CKT 1 [115.00 - 115.00 kV]BUS: Third & Hatch 115 kV 60.85
hs 243.87 Line METRO (48225) TO POSTSTRT (48339) CKT 1 [115.00 - 115.00 kV]N-1: Post Street - Third & Hatch 115 kV -60.99
hs 246.2 Line METRO (48225) TO POSTSTRT (48339) CKT 1 [115.00 - 115.00 kV]BUS: Third & Hatch 115 kV -60.85
ht 281.68 Line SPKWASTE (48409) TO WEST (48461) CKT 1 [115.00 - 115.00 kV]BUS: Post Street 115 kV -41.32
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Post Falls
Post Falls 10 to 22 MW; $2.1 to $5.2 million
This request involves adding from 10 to 22 MW at Post Falls, which is modeled in this study as a single generator
at Post Falls 115 kV bus as shown in.

FIGURE 13: POST FALLS GENERATION REQUEST; 2024 HEAVY SUMMER CASE
Analysis
For P0 conditions, both study cases received generation up to 22 MW without issue.
For performance during contingencies, two 115 kV transmission line segments present issues:
 10 MW request; East Farms – Post Falls 115 kV segment overloads
 22 MW request; Otis Orchards – Post Falls 115 kV Transmission Line overloads
Project Alternatives
 10 MW Request - rebuild East Farms – Post Falls line to minimum summer rating of 160 MVA for $2.01
million
 22 MW Request – above project in addition to rebuilding the Otis Orchard – Post Falls 115 kV
Transmission Line to minimum summer rating of 170 MVA for $3.2 million

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Appendix A
Future projects included in this analysis
Project Name Project Scope Targeted Date of
Operation
Chelan - Stratford River
Crossing Rebuild Project
Rebuild the Columbia River crossing to 795ACSS to
correct Chelan – Stratford line overload 2015
Odessa Capacitor Installation
Install two steps of 13.4 MVAR shunt capacitors for
reactive support at Odessa Substation for added
restoration capability
2015
Stratford Strain Bus Rebuild
Project
Stratford strain bus replacement to relieve existing bottle
neck on Stratford - Larson line within the Stratford
Substation
2015
Ninth and Central – Sunset 115
kV Line Reconductoring
Reconductor 1.97 miles of limiting 250 CU conductor
with 795AAC conductor with minimum thermal
capacity rating of 150 MVA at 40C.
2016
Benton – Othello SS 115 kV
Transmission Line Rebuild
Reconductor Avista’s 26 mile section of the Benton –
Othello Switching Station 115 kV Transmission Line
with 795 ACSS with a minimum thermal capacity of
205MVA at 40C.
2016
Spokane Valley Transmission
Reinforcement
A comprehensive project that includes:
1) Replace 4.37 miles of 556 AAC conductor with
150 MVA capacity or better conductor.
2) Rebuild Millwood, 20 MVA Transformers & 4
Feeders. Normally Open (SCADA controlled
switch) provides Back-Up service for IEP
Load.
3) New Irvin Switching Station, breaker & a half,
6 line termination with 2 future line
terminations, distribution facilities per
Distribution Engineering Group, one 33.5
MVAr capacitor bank with space for one future
capacitor bank,
4) Replace 1.74 miles of 4/0 ACSR conductor
with 150 MVA capacity or better conductor.
5) Convert Opportunity to a Switching Station
(single bus, single breaker).
6) New 2.19 miles Single Circuit 150 MVA (IEP
Tap). Possible double circuit with Irvin-
Opportunity 115 kV Line.
2016
Addy – Devil’s Gap 115 kV
Transmission Line
Reconductor 5.19 miles (rebuild between Ford and Long
Lake Tap) of limiting conductor which consist of 266.8
ACSR and 397.5 ACSR conductor resulting in a
capacity limitation of 71.5 MVA at 40C, to be rebuilt to
a capacity of 150 MVA at 40C
2017
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Project Name Project Scope Targeted Date of
Operation
Noxon Reactors Installation Install two steps of 50 MVAR shunt reactors for reactive
support at Odessa Substation for high voltages 2017
Sandcreek-Bronx-Cabinet
Rebuild
Bronx - Cabinet Rebuild from Cabinet to Clark Fork
with 795 ACSS 2017
Coeur d'Alene - Pine Creek 115
Rebuild
Coeur d'Alene - Pine Creek 115 Rebuild replace with
795 conductor and operate closed 2018
Hallett & White – Silver Lake
115 kV Transmission Line
Rebuild
The transmission line will be rebuilt with 795 ACSR
conductor with minimum thermal capacity of 150 MVA
at 40C
2018
Westside Transformer phase 1
Westside Transformer Replacement Project includes a
new 250 MVA Westside No.1 230/115 kV Transformer
installation which was identified in the 2013 Planning
Assessment to be implemented by 2018 for an N-1
contingency (Westside No.2 230/115 kV outage)
2018
Garden Springs 115 Station
Garden Springs 115 kV station
-Loops the existing Airway Height - Sunset line into
Garden Springs
-Includes rebuild of Sunset - Westside from GDN to
SUN with 795

2019
Roxboro-Warden Rebuild
The Lind – Warden 115 kV Transmission Line is 21
miles long, and is constructed primarily with 7#8 CU
conductor resulting in a capacity limit of 57 MVA at
40C. Rebuild to 795 ACSS with aminimum of 150
MVA thermal capacity at 40C.
2020
Westside Transformer phase 2 Remove Westside Transformers 1 and 2 and replace
with a new 250 MVA Transformer. 2020

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Appendix B
New facility violations for Kootenai 350 MW request
Label Element Percent Case
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 138.25 hs
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 134.6 hs
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV BELLAN11 (90011) -> BELL S3 (40090) CKT 1 at BELLAN11 130.67 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 127.9 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS 124.08 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 123.57 hs
N-1: Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 121.95 ht
N-1: Lancaster - Rathdrum 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 121.42 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 121.16 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 120.41 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 120.19 ht
N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 119.82 ht
N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 119.73 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 119.58 ht
N-1: Boulder - Lancaster 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 118.9 ht
BF: R427 Beacon North & South 230 kV SPKINDPK (48405) -> IRVIN (48165) CKT 1 at IRVIN 118.86 hs
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 118.14 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 117.36 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 117.2 ht
BF: R508 Lancaster-Rathdrum, Rathdrum #1 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 115.91 ht
N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 115.77 hs
N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 115.38 hs
N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder #1 115kV BOULDERE (48522) -> IRVIN (48165) CKT 1 at BOULDERE 114.84 ht
BF: A1561 Boulder-Lancaster, Lancaster Generator #1 & #2 IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 114.8 ht
BF: A1186 Lancaster-Noxon, Boulder-Lancaster IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 114.62 ht
BF: A1558 Bell-Lancaster, Lancaster-Rathdrum IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 114.55 ht
N-2: Beacon - Boulder 230 kV & Boulder - Irvin #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 114.15 hs
N-1: Lancaster - Rathdrum 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 113.6 ht
BUS: Beacon North 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 113.53 ht
N-1: Beacon - Boulder 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 113.26 ht
BF: R408 Lancaster-Rathdrum, Rathdrum #2 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 113.03 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 112.69 hs
N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 111.93 ht
N-1: Beacon - Kootenai 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 111.76 ht
BUS: Beacon North 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 111.71 ht
N-1: Opportunity - Otis Orchards 115 kV Open @ OTI BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 111.67 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV RAMSEY (48349) -> PRAIRIEB (40855) CKT 1 at RAMSEY 110.91 hs
N-2 (ADJ): Beacon - Boulder #2 115 kV and Beacon - Ninth & Central #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 110.78 hs
N-2 (ADJ): Beacon - Bell #4 230kV and Beacon - Kootenai 230kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 110.66 ht
PSF: Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 110.59 ht
N-1: Lancaster - Rathdrum 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 110.58 ht
BF: A600 Beacon North & South 115 kV OPPORTUN (48299) -> CHESTER (48069) CKT 1 at CHESTER 109.39 hs
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 109.18 hs
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 109.16 hs
N-1: Opportunity - Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 109.13 ht
N-1: Boulder - Lancaster 230 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 109.13 ht
N-2 (ADJ): Beacon - Bell #4 230kV and Beacon - Kootenai 230kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 108.94 ht
N-1: Beacon - Kootenai 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 108.92 ht
N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 108.9 ht
N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS 108.68 ht
N-2: Beacon - Boulder 230 kV & Beacon - Irvin #1 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 108.48 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 108.16 ht
BF: R508 Lancaster-Rathdrum, Rathdrum #1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 108.06 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 107.89 ht
N-2 (ADJ): Bell - Coulee #6 500 kV and Bell - Creston 115 kV WEST (48463) -> WESTBPA2 (41276) CKT 1 at WESTBPA2 107.8 ht
N-1: Boulder - Lancaster 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 107.74 hs
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 107.69 ht
BF: A667 Ramsey 115 kV, Appleway-Ramsey IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 107.57 ht
BF: A668 Ramsey 115 kV, Ramsey-Rathdrum #1 IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 107.51 ht
BF: A717 Boulder East & West 115 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 107.31 ht
N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 107.07 ht
BF: A1561 Boulder-Lancaster, Lancaster Generator #1 & #2 PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 107.05 ht
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BF: R427 Beacon North & South 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 106.95 ht
N-1: Opportunity - Otis Orchards 115 kV Open @ OPT BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.89 ht
BF: A645 Otis Orchards 115 kV, Boulder-Otis Orchards BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.89 ht
BF: A645 Otis Orchards 115 kV, Boulder-Otis Orchards BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.88 hs
BF: A1186 Lancaster-Noxon, Boulder-Lancaster PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 106.85 ht
BF: A1558 Bell-Lancaster, Lancaster-Rathdrum PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 106.78 ht
N-1: Post Falls - Ramsey 115 kV Open @ RAM IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 106.72 ht
BUS: Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 106.67 ht
BUS: Beacon North 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.61 hs
N-2 (STR): Post Falls - Ramsey 115 kV & Ramsey - Rathdrum #1 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 106.31 ht
BF: 4122 Bell-Taft, Hot Springs-Taft BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.28 ht
BF: R452 Beacon-Boulder, Boulder #2 230/115 Transformer BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.77 ht
N-1: Boulder - Irvin #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.72 hs
BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.57 ht
N-1: Opportunity - Otis Orchards 115 kV Open @ OTI BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.54 hs
BF: A211 Post Falls 115 kV, Post Falls-Ramsey IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.37 ht
N-1: Post Falls - Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.37 ht
BF: A669 Ramsey 115 kV, Post Falls-Ramsey IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.34 ht
BUS: Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.29 ht
BF: R408 Lancaster-Rathdrum, Rathdrum #2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 105.16 ht
BF: R552 Beacon-Boulder, Boulder #1 230/115 Transformer BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.04 ht
BF: R508 Lancaster-Rathdrum, Rathdrum #1 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 105.02 ht
BF: A506 Rathdrum 115 kV, Pine Street-Rathdrum RATHDRMW (48355) -> HUETTER (48159) CKT 1 at HUETTER 104.87 hs
PSF: Post Falls 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 104.86 ht
PSF: Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 104.75 ht
BUS: Rathdrum East 115 kV RATHDRMW (48355) -> HUETTER (48159) CKT 1 at HUETTER 104.72 hs
BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 104.5 hs
N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 104.3 ht
BF: A1561 Boulder-Lancaster, Lancaster Generator #1 & #2 MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 104.04 ht
BUS: Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 104.02 hs
N-1: Beacon - Kootenai 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 103.89 ht
BF: A1186 Lancaster-Noxon, Boulder-Lancaster MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 103.84 ht
BUS: Beacon North 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 103.84 ht
BF: R427 Beacon North & South 230 kV LANCASTR (40624) -> BELLAN11 (90011) CKT 1 at BELLAN11 103.83 ht
N-1: Bell - Coulee #6 500 kV WEST (48463) -> WESTBPA2 (41276) CKT 1 at WESTBPA2 103.79 ht
BF: A1558 Bell-Lancaster, Lancaster-Rathdrum MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 103.76 ht
N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV LANCASTR (40624) -> BELLAN11 (90011) CKT 1 at BELLAN11 103.71 ht
N-2 (ADJ): Beacon - Francis & Cedar 115kV and Bell - Coulee #6 500kV WEST (48463) -> WESTBPA2 (41276) CKT 1 at WESTBPA2 103.68 ht
N-1: Boulder - Lancaster 230 kV RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 103.58 ht
BUS: Post Falls 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 103.25 ht
N-1: Otis Orchards - Post Falls 115 kV Open @ PF IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 103.24 ht
N-1: Post Falls - Ramsey 115 kV Open @ PF IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 103.24 ht
PSF: Ramsey 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 102.97 ht
BF: A641 Otis Orchards 115 kV, Opportunity-Otis Orchards BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.88 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 102.85 ht
N-2 (ADJ): Beacon - Bell #4 230kV and Beacon - Kootenai 230kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 102.8 ht
BF: A688 Ninth & Central North & South 115 kV ROSSPARK (48371) -> THIRHACH (48431) CKT 1 at ROSSPARK 102.78 hs
N-1: Otis Orchards - Post Falls 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.75 ht
BF: A324 Post Falls 115 kV, Otis Orchards-Post Falls IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.73 ht
BF: 4119 Bell-Taft, Garrison-Taft #1 BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.67 ht
BF: AXXX Bell S0 & S1 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.6 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 102.43 ht
N-1: Bell - Taft 500 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.35 ht
N-2 (STR): Bell - Coulee #3 230 kV & Bell - Westside 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.21 ht
BF: R408 Lancaster-Rathdrum, Rathdrum #2 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 102.12 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 102.05 ht
N-1: Otis Orchards - Post Falls 115 kV Open @ OTI IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.94 ht
BF: AXXX Irvin - IEP 115 kV, Boulder - Irvin #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.84 ht
N-1: Lancaster - Rathdrum 230 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 101.55 ht
N-1: Bell - Westside 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.48 ht
BF: R427 Beacon North & South 230 kV BELLAN11 (90011) -> BELL S3 (40090) CKT 1 at BELLAN11 101.46 ht
PSF: Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.46 hs
N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV BELLAN11 (90011) -> BELL S3 (40090) CKT 1 at BELLAN11 101.35 ht
BF: R476 Benewah-Moscow 230, Benewah 230/115 Transformer BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.1 ht
N-2: Ninth & Central - Opportunity 115 kV & Opportunity - Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.09 ht
BF: A388 Bell S2 & S3 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.95 ht
BUS: Boulder West 115 kV BOULDERE (48522) -> IRVIN (48165) CKT 1 at BOULDERE 100.85 hs
N-1: Beacon - Kootenai 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 100.84 ht
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N-2 (ADJ): Bell - Coulee #6 500kV and Bell - Westside 230kV FRANCEDR (48127) -> NORTHWES (48279) CKT 1 at FRANCEDR 100.81 ht
BUS: Beacon North 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 100.8 ht
N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 100.74 ht
N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV RAMSEY (48349) -> PRAIRIEB (40855) CKT 1 at RAMSEY 100.74 hs
BF: A638 Rathdrum 115 kV, Appleway-Rathdrum RATHDRMW (48355) -> HUETTER (48159) CKT 1 at HUETTER 100.6 hs
N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 100.41 hs
N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV IRVIN (48165) -> MILLWOOD (48237) CKT 1 at IRVIN 100.4 ht
BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.37 ht
N-2 (ADJ): Bell - Taft 500 kV and Lancaster - Noxon 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.31 ht
BF: A370 Bell S1 & S2 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 100.16 ht
BF: R427 Beacon North & South 230 kV IRVIN (48165) -> MILLWOOD (48237) CKT 1 at IRVIN 100.1 ht

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Appendix C
New facility thermal violations for Rathdrum 200 MW request; 115 kV option
Label Element Percent Case
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 146.18 hs
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 134.09 hs
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 133.17 hs
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 131.81 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 130.46 hs
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 129.6 hs
N-1: Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 126.81 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 126 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 125.09 ht
N-1: Boulder - Lancaster 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 123.81 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 123.54 ht
BF: R408 Lancaster-Rathdrum, Rathdrum #2 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 123.32 ht
PSF: Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 123.28 ht
BF: R400 Kootenai-Rathdrum, Rathdrum #2 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 123.14 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 123.03 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 122.08 ht
BF: R508 Lancaster-Rathdrum, Rathdrum #1 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 121.53 ht
BF: R500 Kootenai-Rathdrum, Rathdrum #1 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 120.97 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 120.23 hs
BF: A667 Ramsey 115 kV, Appleway-Ramsey IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 120.22 ht
BF: A668 Ramsey 115 kV, Ramsey-Rathdrum #1 IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 120.16 ht
BF: A1186 Lancaster-Noxon, Boulder-Lancaster IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 119.38 ht
BUS: Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 119.31 ht
N-1: Post Falls - Ramsey 115 kV Open @ RAM IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 119.29 ht
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 119.22 hs
N-2 (STR): Post Falls - Ramsey 115 kV & Ramsey - Rathdrum #1 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 119 ht
BF: A1561 Boulder-Lancaster, Lancaster Generator #1 & #2 IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 118.79 ht
N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 118.16 ht
BF: A669 Ramsey 115 kV, Post Falls-Ramsey IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 118 ht
N-1: Lancaster - Rathdrum 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 117.96 ht
N-1: Post Falls - Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 117.96 ht
BF: A211 Post Falls 115 kV, Post Falls-Ramsey IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 117.78 ht
PSF: Post Falls 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 117.28 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS 117 ht
BUS: Beacon North 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 116.72 ht
N-1: Beacon - Kootenai 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 116.6 ht
N-1: Kootenai - Rathdrum 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 116.58 ht
N-1: Post Falls - Ramsey 115 kV Open @ PF IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 115.87 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 115.86 ht
PSF: Ramsey 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 115.76 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 115.76 hs
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 115.73 hs
N-2 (ADJ): Beacon - Bell #4 230kV and Beacon - Kootenai 230kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 115.72 ht
BUS: Post Falls 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 115.69 ht
BF: R408 Lancaster-Rathdrum, Rathdrum #2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 115.45 ht
N-1: Otis Orchards - Post Falls 115 kV Open @ PF IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 115.43 ht
BF: R400 Kootenai-Rathdrum, Rathdrum #2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 115.29 ht
BF: A324 Post Falls 115 kV, Otis Orchards-Post Falls IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 115.2 ht
N-1: Otis Orchards - Post Falls 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 114.95 ht
N-1: Boulder - Lancaster 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 114.52 hs
BF: A717 Boulder East & West 115 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 114.42 ht
N-1: Otis Orchards - Post Falls 115 kV Open @ OTI IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 114.15 ht
BF: R508 Lancaster-Rathdrum, Rathdrum #1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 113.66 ht
N-2 (STR and ADJ): Beacon - Boulder 230 kV & Beacon - Boulder #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 113.38 hs
BF: R500 Kootenai-Rathdrum, Rathdrum #1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 113.13 ht
N-1: Boulder - Lancaster 230 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 113.12 ht
BF: R427 Beacon North & South 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 112.91 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 112.87 ht
PSF: Ramsey 115 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 112.81 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV LANCASTR (40624) -> BELLAN11 (90011) CKT 1 at BELLAN11 112.74 ht
BF: A667 Ramsey 115 kV, Appleway-Ramsey PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 112.71 ht
BF: A668 Ramsey 115 kV, Ramsey-Rathdrum #1 PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 112.64 ht
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N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 112.58 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 112.57 ht
BF: R408 Lancaster-Rathdrum, Rathdrum #2 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 112.41 ht
BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 112.4 ht
BF: R400 Kootenai-Rathdrum, Rathdrum #2 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 112.26 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 112.15 ht
BUS: Ramsey 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 111.8 ht
BF: A1186 Lancaster-Noxon, Boulder-Lancaster PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 111.8 ht
N-1: Post Falls - Ramsey 115 kV Open @ RAM PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 111.72 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 111.72 ht
BUS: Otis Orchards 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 111.59 ht
N-2: Beacon - Boulder 230 kV & Boulder - Irvin #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 111.53 hs
N-2 (STR): Post Falls - Ramsey 115 kV & Ramsey - Rathdrum #1 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 111.45 ht
BF: A1558 Bell-Lancaster, Lancaster-Rathdrum IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 111.34 ht
BUS: Beacon South 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 111.31 ht
BF: A1561 Boulder-Lancaster, Lancaster Generator #1 & #2 PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 111.2 ht
N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV POST FLS (48329) -> EASTFARM (48117) CKT 1 at POST FLS 110.91 ht
BF: A641 Otis Orchards 115 kV, Opportunity-Otis Orchards IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 110.82 ht
BF: A645 Otis Orchards 115 kV, Boulder-Otis Orchards IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 110.72 ht
PSF: Otis Orchards 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 110.71 ht
BF: R508 Lancaster-Rathdrum, Rathdrum #1 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 110.63 ht
N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 110.55 ht
BF: A669 Ramsey 115 kV, Post Falls-Ramsey PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 110.51 ht
N-1: Post Falls - Ramsey 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 110.4 ht
N-2 (ADJ): Beacon - Boulder 230kV and Beacon - Boulder #1 115kV BOULDERE (48522) -> IRVIN (48165) CKT 1 at BOULDERE 110.25 ht
BF: A211 Post Falls 115 kV, Post Falls-Ramsey PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 110.24 ht
N-1: Lancaster - Rathdrum 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 110.18 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV BELLAN11 (90011) -> BELL S3 (40090) CKT 1 at BELLAN11 110.16 ht
BF: R500 Kootenai-Rathdrum, Rathdrum #1 230/115 Transformer MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 110.1 ht
BF: A506 Rathdrum 115 kV, Pine Street-Rathdrum RATHDRMW (48355) -> HUETTER (48159) CKT 1 at HUETTER 110.08 hs
BF: R427 Beacon North & South 230 kV SPKINDPK (48405) -> IRVIN (48165) CKT 1 at IRVIN 110.04 hs
BUS: Rathdrum East 115 kV RATHDRMW (48355) -> HUETTER (48159) CKT 1 at HUETTER 109.93 hs
N-2 (ADJ): Beacon - Boulder #2 115 kV and Beacon - Ninth & Central #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 109.81 hs
PSF: Post Falls 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 109.75 ht
BF: A667 Ramsey 115 kV, Appleway-Ramsey MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 109.75 ht
BF: A668 Ramsey 115 kV, Ramsey-Rathdrum #1 MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 109.69 ht
N-1: Opportunity - Otis Orchards 115 kV Open @ OTI BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 109.12 ht
BUS: Beacon North 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 109.03 ht
N-1: Beacon - Boulder 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 108.94 ht
N-1: Beacon - Kootenai 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 108.9 ht
N-1: Kootenai - Rathdrum 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 108.89 ht
N-1: Rathdrum #2 230/115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 108.88 ht
BUS: Ramsey 115 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 108.85 ht
N-1: Benewah - Pine Creek 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 108.83 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 108.83 hs
BF: A1186 Lancaster-Noxon, Boulder-Lancaster MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 108.83 ht
N-1: Post Falls - Ramsey 115 kV Open @ RAM MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 108.75 ht
N-2 (STR): Post Falls - Ramsey 115 kV & Ramsey - Rathdrum #1 115 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 108.49 ht
BF: R474 Benewah-Pine Creek, Benewah 230/115 Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 108.43 ht
N-1: Post Falls - Ramsey 115 kV Open @ PF PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 108.33 ht
BF: A1561 Boulder-Lancaster, Lancaster Generator #1 & #2 MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 108.23 ht
PSF: Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 108.2 hs
BUS: Post Falls 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 108.17 ht
N-2 (ADJ): Beacon - Bell #4 230kV and Beacon - Kootenai 230kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 108.03 ht
N-1: Otis Orchards - Post Falls 115 kV Open @ PF PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 107.93 ht
N-2 (ADJ): Bell - Taft 500 kV and Bell - Lancaster 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 107.77 ht
N-2 (STR): Beacon - Kootenai 230 kV & Boulder - Lancaster 230 kV RAMSEY (48349) -> PRAIRIEB (40855) CKT 1 at RAMSEY 107.77 hs
N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 107.76 hs
BF: A324 Post Falls 115 kV, Otis Orchards-Post Falls PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 107.68 ht
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 107.63 hs
N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 107.58 ht
BF: A669 Ramsey 115 kV, Post Falls-Ramsey MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 107.57 ht
BF: A720 Boulder East 115 kV, Boulder-Rathdrum PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 107.54 ht
PSF: Boulder East 115 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 107.54 ht
N-1: Otis Orchards - Post Falls 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 107.45 ht
N-1: Post Falls - Ramsey 115 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 107.44 ht
BF: A211 Post Falls 115 kV, Post Falls-Ramsey MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 107.28 ht
BF: A600 Beacon North & South 115 kV OPPORTUN (48299) -> CHESTER (48069) CKT 1 at CHESTER 107.21 hs
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N-1: Lancaster - Rathdrum 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 107.17 ht
N-1: Boulder - Lancaster 230 kV RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 107.16 ht
PSF: Post Falls 115 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 106.79 ht
N-1: Otis Orchards - Post Falls 115 kV Open @ OTI PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 106.67 ht
N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV EASTFARM (48117) -> OTIS (48311) CKT 1 at EASTFARM 106.64 ht
N-1: Opportunity - Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.61 ht
BUS: Beacon North 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.6 ht
N-2 (ADJ): Beacon - Kootenai 230kV and Bell - Lancaster 230kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 106.54 ht
N-1: 3TM Bell - Boundary #1 230 kV Open @ BELL IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 106.48 ht
N-2 (STR): Kootenai - Rathdrum 230 kV & Lancaster - Rathdrum 230 kV RAMSEY (48349) -> PRAIRIEB (40855) CKT 1 at RAMSEY 106.46 hs
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 106.43 ht
N-2 (STR): Hot Springs - Noxon #1 230 kV & Hot Springs - Noxon #2 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 106.29 ht
N-2 (STR): Boulder - Lancaster 230 kV & Boulder - Rathdrum 115 kV RAMSEY (48349) -> PRAIRIEB (40855) CKT 1 at RAMSEY 106.26 hs
BUS: Beacon North 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 106.03 ht
N-1: Beacon - Kootenai 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 105.9 ht
N-1: Kootenai - Rathdrum 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 105.89 ht
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer RATHDRMW (48355) -> IDAHO_RD (48161) CKT 1 at RATHDRMW 105.88 ht
BF: A638 Rathdrum 115 kV, Appleway-Rathdrum RATHDRMW (48355) -> HUETTER (48159) CKT 1 at HUETTER 105.83 hs
N-2 (ADJ): Kootenai - Rathdrum 230kV and Lancaster - Noxon 230kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.66 ht
BUS: Boulder East 115 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 105.59 ht
BF: AXXX Bell S0 & S1 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.46 ht
N-1: Post Falls - Ramsey 115 kV Open @ PF MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 105.37 ht
BUS: Pine Creek 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.34 ht
BF: A645 Otis Orchards 115 kV, Boulder-Otis Orchards BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.27 hs
N-1: Rathdrum #1 230/115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 105.26 ht
BF: R427 Beacon North & South 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 105.26 ht
BUS: Post Falls 115 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 105.22 ht
N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.12 hs
N-1: Opportunity - Otis Orchards 115 kV Open @ OTI BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 105.08 hs
N-2 (ADJ): Beacon - Bell #4 230kV and Beacon - Kootenai 230kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 105.03 ht
N-1: Otis Orchards - Post Falls 115 kV Open @ PF MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 104.99 ht
N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 104.94 ht
N-1: Boulder - Irvin #2 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 104.82 hs
BF: A324 Post Falls 115 kV, Otis Orchards-Post Falls MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 104.74 ht
BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 104.71 ht
BF: A370 Bell S1 & S2 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 104.58 ht
N-1: Otis Orchards - Post Falls 115 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 104.51 ht
N-2: Beacon - Boulder 230 kV & Beacon - Irvin #1 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 104.44 ht
BF: R400 Kootenai-Rathdrum, Rathdrum #2 230/115 Transformer PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 104.43 ht
N-1: Opportunity - Otis Orchards 115 kV Open @ OPT BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 104.38 ht
BF: A1184 Lancaster-Noxon, Lancaster-Rathdrum PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 104.27 ht
N-2 (ADJ): Bell - Taft 500 kV and Bell - Lancaster 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 104.17 ht
BUS: Otis Orchards 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 103.91 ht
BF: R408 Lancaster-Rathdrum, Rathdrum #2 230/115 Transformer PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 103.84 ht
N-1: Otis Orchards - Post Falls 115 kV Open @ OTI MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 103.73 ht
BF: A1558 Bell-Lancaster, Lancaster-Rathdrum PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 103.71 ht
BF: A645 Otis Orchards 115 kV, Boulder-Otis Orchards BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 103.67 ht
BUS: Bell S2 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 103.53 ht
N-2 (STR): Boulder - Boulder Park 115 kV & Boulder - Rathdrum 115 kV (8) PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 103.48 ht
BF: R400 Kootenai-Rathdrum, Rathdrum #2 230/115 Transformer BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 103.45 ht
BF: A668 Ramsey 115 kV, Ramsey-Rathdrum #1 IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 103.14 hs
BF: A641 Otis Orchards 115 kV, Opportunity-Otis Orchards PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 103.14 ht
BF: R500 Kootenai-Rathdrum, Rathdrum #1 230/115 Transformer BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 103.09 ht
BF: A645 Otis Orchards 115 kV, Boulder-Otis Orchards PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 103.04 ht
PSF: Otis Orchards 115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 103.04 ht
BF: 4122 Bell-Taft, Hot Springs-Taft IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.97 ht
BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.88 hs
BF: R452 Beacon-Boulder, Boulder #2 230/115 Transformer BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.76 ht
N-1: Boulder - Rathdrum 115 kV Open @ RAT PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 102.7 ht
N-1: Bell - Usk 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.69 ht
BF: R554 Boulder-Lancaster, Boulder #1 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 102.68 hs
BF: R454 Boulder-Lancaster, Boulder #2 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 102.65 hs
BF: R500 Kootenai-Rathdrum, Rathdrum #1 230/115 Transformer PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 102.49 ht
BF: A374 Bell S1 230 kV, Bell-Boundary #1 IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.44 ht
BF: R427 Beacon North & South 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.41 hs
BUS: Bell S1 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.41 ht
N-1: 3TM Bell - Boundary #1 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.41 ht
BUS: Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.4 hs
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BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.35 ht
BF: R427 Beacon North & South 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 102.28 ht
BF: R508 Lancaster-Rathdrum, Rathdrum #1 230/115 Transformer PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 102.24 ht
N-2 (ADJ): Beacon - Bell #4 230kV and Beacon - Kootenai 230kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.23 ht
N-1: Beacon - Kootenai 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.22 ht
BF: 4148 Garrison-Taft #2, Hot Springs-Taft IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.19 ht
N-1: Kootenai - Rathdrum 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.19 ht
BF: 4122 Bell-Taft, Hot Springs-Taft BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.19 ht
BF: A1186 Lancaster-Noxon, Boulder-Lancaster IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.14 hs
BF: A667 Ramsey 115 kV, Appleway-Ramsey IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 102.07 hs
BUS: Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 102.07 ht
N-2 (STR): Bell - Coulee #3 230 kV & Bell - Westside 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.97 ht
N-2 (STR): Beacon - Boulder 230 kV & Beacon - Kootenai 230 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 101.95 ht
BF: R552 Beacon-Boulder, Boulder #1 230/115 Transformer BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.9 ht
N-1: Ramsey - Rathdrum #1 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.9 ht
BF: A958 Bell-Usk, Usk 230/115 kV Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.89 ht
BUS: Beacon North 230 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.86 hs
BF: A953 Boundery-Usk, Usk 230/115 kV Transformer IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.84 ht
N-1: Boulder #1 230/115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.83 ht
BF: A642 Otis Orchards 115 kV, Otis Orchards-Post Falls MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 101.7 ht
N-1: Bell - Westside 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.62 ht
N-1: Ramsey - Rathdrum #1 115 kV Open @ RAT IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.55 ht
PSF: Otis Orchards 115 kV BOULDERW (48520) -> SPKINDPK (48405) CKT 1 at BOULDERW 101.54 ht
N-1: Boulder - Lancaster 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 101.52 hs
N-1: Boulder - Rathdrum 115 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 101.41 ht
N-2 (ADJ): Bell - Boundary #1 230 kV and Bell - Boundary #3 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.34 ht
N-1: Benewah - Pine Creek 230 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 101.32 ht
BUS: Ramsey 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.28 hs
N-1: Coeur d'Alene 15th St - Rathdrum 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.22 ht
N-1: Ramsey - Rathdrum #1 115 kV Open @ RAM IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 101.17 ht
N-1: Rathdrum #2 230/115 kV PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 101.1 ht
BF: A717 Boulder East & West 115 kV RAMSEY (48349) -> PRAIRIEB (40855) CKT 1 at RAMSEY 101.01 hs
N-1: Boulder #2 230/115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.94 ht
BF: R474 Benewah-Pine Creek, Benewah 230/115 Transformer PLEASANT (48319) -> MOAB (47511) CKT 1 at PLEASANT 100.92 ht
BUS: Otis Orchards 115 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 100.9 ht
N-1: Hot Springs - Noxon #1 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.87 ht
BF: B1145 Addy 115 kV, Addy-Kettle Falls IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.86 ht
N-1: Hot Springs - Noxon #2 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.84 ht
N-1: Hot Springs - Noxon #1 230 kV Open @ HOTS IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.82 ht
N-1: Appleway - Rathdrum 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.79 ht
N-2 (STR): Appleway - Ramsey 115kV and Coeur d'Alene - Ramsey 115kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.79 ht
N-1: Hot Springs - Noxon #1 230 kV Open @ NOX IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.78 ht
N-2 (STR): Bell - Boundary #3 230 kV & Addy - Bell 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.77 ht
BF: A1558 Bell-Lancaster, Lancaster-Rathdrum MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 100.74 ht
N-1: 3TM Bell - Boundary #3 230 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.59 ht
BUS: Addy 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.58 ht
N-1: Benewah - Pine Creek 230 kV PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 100.55 ht
BF: A688 Ninth & Central North & South 115 kV ROSSPARK (48371) -> THIRHACH (48431) CKT 1 at ROSSPARK 100.55 hs
N-1: Albeni Falls - Sacheen 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.5 ht
N-1: 3TM Bell - Boundary #3 230 kV Open @ BOUN IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.5 ht
BF: B323 Sacheen 115 kV, Albeni Falls-Sacheen IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.49 ht
N-1: Albeni Falls - Sacheen 115 kV Open @ ALB IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.49 ht
BF: A521 Devils Gap East 115 kV, Addy-Devils Gap IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.46 ht
BF: A540 Devil's Gap East & West 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.46 ht
BUS: Devils Gap East 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.46 ht
BF: A506 Rathdrum 115 kV, Pine Street-Rathdrum HUETTER (48159) -> HERN (48155) CKT 1 at HERN 100.44 hs
N-1: Appleway - Rathdrum 115 kV Open @ RAT IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.42 ht
BF: B1137 Addy 115 kV, Addy-Devils Gap IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.34 ht
BUS: Rathdrum East 115 kV HUETTER (48159) -> HERN (48155) CKT 1 at HERN 100.29 hs
BF: A526 Devils Gap East 115 kV, Airway Heights-Devils Gap IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.26 ht
PSF: Devils Gap East 115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.26 ht
BF: A1186 Lancaster-Noxon, Boulder-Lancaster PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 100.25 ht
N-1: Sacheen 230/115 kV IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.22 ht
BF: R474 Benewah-Pine Creek, Benewah 230/115 Transformer PRAIRIEB (40855) -> POST FLS (48329) CKT 1 at PRAIRIEB 100.17 ht
N-1: Albeni Falls - Sacheen 115 kV Open @ SACH IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.17 ht
N-1: Appleway - Rathdrum 115 kV Open @ APW IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.14 ht
BF: A641 Otis Orchards 115 kV, Opportunity-Otis Orchards MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 100.14 ht
BF: B1135 Addy 115 kV, Addy-Bell IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.07 ht
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N-1: Post Falls - Ramsey 115 kV Open @ RAM IDAHO_RD (48161) -> PLEASANT (48319) CKT 1 at IDAHO_RD 100.05 hs
BF: A645 Otis Orchards 115 kV, Boulder-Otis Orchards MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 100.04 ht
PSF: Otis Orchards 115 kV MOAB (47511) -> BOULDERE (48522) CKT 1 at MOAB 100.04 ht

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