20110706Lafferty Di.pdf

.
Rt('''c, ir:~... ..DAVID J. MEYER ~
VICE PRESIDENT AND CHIEF COUNSEL FOR ,UII ,JUt -5 M1 1/: t¡4
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P .0. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
DAVID. MEYER~AVISTACORP. COM
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-11-01
DIRECT TESTIMONY
OF
ROBERT J. LAFFERTY
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
1
2
I. INTRODUCTION
Q.Please state your name, emloyer and business
3 address.
4 A.My name is Robert J. Lafferty. I am employed as
5 the Director of Power Supply at Avista Corporation, located
6 at 1411 East Mission Avenue, Spokane, Washington.
7 Q.Would you briefly describe your educational and
8 professional background?
9 A.Yes. I received a Bachelor of Arts degree in
10 Business Administration and a Bachelor of Science degree in
11 Electrical Engineering from Washington State Uni versi ty,
12 both in 1974.I began working as a distribution engineer
13 for Avista in 1974 and held several different engineering
14 posi tions with the Company.In 1979, I passed the
15 Professional Engineering License examination in the state
16 of Washington.I have held management positions in
17 engineering, marketing, demand-side-management and energy
18 resources. I began work in the Energy Resources Department
19 in March 1996, and have held various positions involving
20 the planning, acquisition and optimization of energy
21 resources. I became the Director of Power Supply in March
22 2008, where my primary responsibilities involve management
23 and oversight of the short- and long-term planning and
24 acquisition of power resources for the Company.
Lafferty, Di 1
Avista Corporation
1 Q. What is the scope of your testimony in this
2 proceeding?
3
4
A. My testimony provides an overview of Avista's
resource planning and power supply operations.This
5 includes summaries of the Company's generation resources,
6 the current and future load and resource position, future
7 resource plans, and an update on the Company's plans
8 regarding the acquisition of new renewable resources.As
9 part of an overview of the Company's risk management
10 policy, I will provide an update on the Company's hedging
11
12
practices.I will address hydroelectric and thermal
project upgrades,followed by an update on recent
13 developments regarding hydro licensing.
14 A table of contents for my testimony is as follows:
15
16
17
18
19
20
21
22
23
24
I.II.III.iv.v.
DescriptionIntroduction
Resource Planning and Power Operations
Risk Management Policy
Generation Capital Projects
Hydro Relicensing
Page
1
3
11
16
22
Q.Are you sponsoring any exhibits?
Yes. I am sponsoring Exhibit No.4, Schedule 1,A.
25 which includes Avista's 2009 Electric Integrated Resource
26 Plan, Schedule 2 which provides a forecast of Company load
27 and resource positions from 2011 through 2031, and
28 confidential Schedule 3C which includes Avista's Energy
29 Resources Risk Policy.
30
Lafferty, Di 2
Avista Corporation
1
2
II. RESOURCE PLAING AN POWER OPERATIONS
Q.Would you please provide a brief overview of
3 Avista's generating resources?
4 A.Yes.Avista's resource portfolio consists of
5 hydroelectric generation projects, base-load coal and
6 natural gas-fired combined-cycle generation facilities,
7 woodwaste-fired generation,natural gas-fired peaking
8 generation, long-term contracts, including wind and Mid-
9
10
Columbia hydroelectric generation,and market power
purchases and exchanges.Avista-owned generation
11 facili ties have a total capability of 1,777 MW, which
12 includes 56% hydroelectric and 44% thermal resources.
13 Illustration No. 1 below summarizes the present net
14 capability of Avista' s owned generation resources:
15 Illustration No.1: Avista's Generation
Avista-Owned GenerationHydroelectricMWBase-Load MW Natural Gas MW
Generation Therml Peaking
Generation Genera t.ion
Noxon Rapids 557 Colstrip 222 Northeast CT 56
Units 3 &4
Cabinet Gorge 255 Coyote 278 Kettle Falls 7
Sprinqs 2 CT
Post Falls 18 Kettle Falls 50 Boulder Park 24
Upper Falls 10 Rathdrum CT 149
Monroe Street 15
Nine Mile 18
Lonq Lake 83LittleFalls35Total991 Total Base-550 Total 236
Hvdroelectric Load Therml Peakina
Total Owned 1,777 MW
Generation
16
17
18
In addition, the Company currently has long-term
contractual rights for 134 aMW from Mid-Columbia
Lafferty, Di 3
Avista Corporation
1 hydroelectric projects in 2012, from projects owned and
2 operated by the Public Utility Districts of Chelan, Douglas
3 and Grant counties.Avista also has a long-term power
4 purchase agreement (PPA) in place entitling the Company to
5 dispatch, purchase fuel for and receive the power output
6 from the 275 MW Lancaster combined-cycle combustion turbine
7 project located in Rathdrum, Idaho.
8 Q.Would you please provide a sumry of Avista' s
9 power supply operations and planning for new resources?
10 A.Yes.Avista uses a combination of owned and
11 contracted-for resources to serve its load requirements.
12 The Power Supply Department is responsible for dispatch
13 decisions related to those resources for which the Company
14 has dispatch rights. The Department monitors and routinely
15 studies capacity and energy resource needs.Short- and
16 medium-term wholesale transactions are used to economically
17
18
balance resources with load requirements.Longer-term
resource decisions such as the acquisition of new
19 generation resources, upgrades to existing resources,
20 energy efficiency measures,and long-term contract
21 purchases are generally made in conj unction with the
22 Integrated Resource Plan (IRP) and will typically include a
23 Request for Proposals (RFP) or other market due diligence
24 process.
25 Q.Please sumrize the current load and resource
26 posi tion for the Company.
Lafferty, Di 4
Avista Corporation
1 A.Avista's 2009 Electric Integrated Resource Plan
2 shows forecasted annual energy deficits beginning in 2018,
3 and sustained annual capacity deficits beginning in 2019. i
4 These capacity and energy load/resource positions are shown
5 on pages 2-27 and 2-28,. respectively of Schedule 1 of
6 Exhibi t No.4. However, our most recent load and resource
7 projection, which is attached as Schedule 2 of Exhibit No.
8 4, indicates that the annual deficits have moved out
9 another year. Therefore, Avista's current projection shows
10 an annual energy deficit beginning in 2020 of about 19 aMW,
11 and increasing to a 406 aMW deficit in 2031. The Company's
12 January capacity resource position, based on an 18-hour
13 peak event (6 hours per day and over 3 days), is currently
14 projected to be surplus through 2021.Sustained annual
15 capacity deficiencies, based on a January peak, begin at
16 148 MW in 2022 and increase to a 779 MW deficit in 2031.
17 The Company's August capacity resource position, based on
18 an 18-hour peak event, is currently projected to be surplus
19 through 2018.Sustained annual capacity deficiencies,
20 based on an August peak, begin at 56 MW in 2019 and
21 increase to a 667 MW deficit in 2031.
22
23
Q.How does the Company plan to meet future energy
and capacity needs beginning in 2020 and 2019,
24 respectively?
i The Company has a 1 SO MW capacity exchange agreement with Portland General Electrc that ends in
December 2016 which results in short-term annual capacity deficits in 201S and 2016. Sustained annual
capacity deficits begin in 2019.
Lafferty, Di 5
Avista Corporation
1 A.The Company will be guided by its Preferred
2 Resource Strategy. The current Preferred Resource Strategy
3 is described in the 2009 Electric IRP, which is attached as
4 Schedule 1 of Exhibit No.4.The IRP provides details
5 about proj ected resource needs, specific resource costs,
6 resource operating characteristics, and the scenarios used
7 for evaluating the mix of resources for the Preferred
8 Resource Strategy.
9 The Company's 2009 Electric IRP was submitted to the
10 Commission in August 2009, following the completion of a
11 public process involving six Technical Advisory Committee
12 meetings.The IRP represents the preferred resource plan
13 at a point in time, however, the Company will continue
14
15
evaluating resource options to meet future load
requirements,including medium-term market purchases,
16 generation ownership, hydroelectric upgrades, renewable
17 resources, distribution efficiencies, energy efficiency
18 measures, long-term contracts, and generation lease or
19 tolling arrangements.As stated earlier, longer-term
20 resource decisions are generally made in conjunction with
21 the Company's IRP and RFP processes, although the Company
22 may acquire some resources outside of formal RFP processes.
23 Avista's 2009 Preferred Resource Strategy includes 5
24 MWs of distribution efficiencies,339 MWs of energy
25 efficiency, 5 MWs of upgrades to existing hydroelectric
26 plants,750 MWs of natural gas-fired combined-cycle
27 combustion turbine (CCCT), and 350 MWs of wind located in
Lafferty, Di 6
Avista Corporation
1 the Pacific Northwest.The timing of these resources as
2 published in the 2009 IRP is shown in Illustration No. 2
3 below.
4 Illustration No.2: 2009 Electric IRP Preferred Resource5 Strategy
6
Resource Type By the End of Nameplate Ener.gy
Northwest Wind 2012 150.0 48.0
Distribution 2010 /2015 5.0 2.7
Little Falls 2013 /2016 3.0 0.9
Northwest Wind 2019 150.0 50.0
CCCT 2019 250.0 225.0
Upper Falls 2020 2.0 1. 0
Northwest Wind 2022 50.0 17.0
CCCT 2024 250.0 225.0
CCCT 2027 250.0 225.0
Energy Efficiency All Years 339.0 226.0
Total 1,449.0 1,020.6
7
8 Q.Are there any costs specifically associated with
9 meeting Washington State's renewable portfolio standard
10 included in this case?
11 A.No.All direct costs related to meeting
12 Washington State's renewable portfolio standards have been
13 assigned to Washington customers.
14 Q.Can you provide some background regarding why the
15 Company initiated an RFP for renewable resources in 2011.
16 A.Yes.Avista has continued to monitor renewable
17 resource market conditions, particularly with respect to
18 projects bid into its 2009 renewable resource RFP.Avista
19 was recently made aware of a significant drop in prospective
20 proj ect costs associated with construction of new wind
21 generation facilities that are still in a position to take
Lafferty, Di 7
Avista Corporation
1 advantage of currently available near-term tax incentives
2 for projects brought on-line prior to December 31, 2012. The
3 material drop in project cost was the primary reason for the
4 Company's decision to issue a request for proposals in
5 February 2011 for up to 35 aMW of renewable energy.The
6 2011 renewable resource RFP seeks qualifying projects or
7 project output for the 2012 to 2032 time period.Avista
8 stated in the RFP that the Company expected that bids should
9 not exceed $62/MWh and that Avista would not submit a self-
10 build option. The combination of the significant drop in
11 proj ect cost and the substantial tax incentives available
12 today for projects completed by December 31, 2012 point
13 toward long-term benefits for customers compared to the
14 alternative of waiting until a later time when tax
15 incentives, attractive project pricing, and particularly
16 attractive wind project sites may no longer be available to
17 Avista.
18 Q.What is the status of the 2011 renewable resource
19 request for proposals?
20 A.The Company completed its due diligence and
21 negotiations for the 2011 renewable resource request for
22 proposals. The Company has signed a 30-year power purchase
23 agreement with Palouse Wind,LLC,(Palouse Wind)an
24 affiliate of First Wind Energy, LLC. Under the PPA, Avista
25 will acquire all of the power produced by a wind project
26 being developed by Palouse Wind in Whitman County,
27 Washington.The project will have approximately 100 MW of
Lafferty, Di 8
Avista Corporation
1 nameplate capacity and is expected to produce approximately
2 40aMW. Deliveries are expected to begin in the second half
3 of 2012.
4
5
6
Q.What is the status of the Reardan wind project?
A.Avista continues to study the Reardan wind
project site in preparation for later development.The
7 Company expects to issue an RFP at a later date to meet
8 addi tional future resource needs, and expects that the
9 Reardan project would be considered in that later process.
10 The Company chose not to introduce a Reardan project option
11 into the 2011 renewable resource RFP primarily because of
12 the short time frame available to secure competi ti ve bids
13 for turbines and balance of plant construction.When the
14 Company decided in mid-February to initiate a 2011
15 renewable resource RFP, potential bidders had indicated
16 that they would need a power purchase agreement executed by
17 early to mid-May in order to be able to complete a proj ect
18 that would qualify for all of the available tax incentives.
19 Therefore, Avista sought projects that were ready to be
20 built and required bids to be due by March 7, 2011.The
21 competi ti ve bidding for wind turbines and balance of plant
22 work necessary to prepare the Reardan project for
23 evaluation did not fit into the short bidding window for
24 this RFP.
25 Q.Can you provide an update of the Company's
26 evaluation of a direct connection of Avista transmission to
27 the Bonneville Power Administration's Lancaster substation?
Lafferty, Di 9
Avista Corporation
1 A.Yes.Avista is currently engaged in a process
2 with the Bonneville Power Administration (BPA) to jointly
3 study interconnecting Avista's transmission lines to the
4 BPA Lancaster substation, where the Lancaster plant is
5 currently interconnected.The proposed proj ect would
6 interconnect the transmission systems of BPA and Avista at
7 the BPA Lancaster substation.An Avista transmission
8 interconnection to the BPA substation, however, would
9 continue to utilize the BPA Lancaster substation.The
10 costs associated with continued use of the substation would
11 be subj ect to negotiation between the Company and BPA.
12 Pursuant to Avista's Line and Load Interconnection
13 request dated September 2, 2009, Bonneville completed its
14 Line and Load Interconnection System Impact Study on August
15 20, 2010 and is in the process of finalizing its Line and
16 Load Interconnection Facilities Study, currently expected
17 to be completed in August of 2011. Upon completion of the
18 Line and Load Interconnection Facilities Study, Bonneville
19 will tender a Construction Agreement to Avista. Bonneville
20 has communicated to Avista that its current engineering and
21 construction schedule suggests that the Avista-Bonneville
22 Lancaster 230 kV interconnection may be constructed in
23 2013.
24 Construction of a stand-alone Avista interconnection
25 (where the Lancaster project is disconnected from the
26 Bonneville system and connected directly to the Avista
27 system) would not provide the reliability benefits and
Lafferty, Di 10
Avista Corporation
1 additional import capacity that an Avista-Bonneville230 kV
2 transmission interconnection provides, therefore, this form
3 of a self-build option has not received any further
4 consideration as part of the j oint study work.
5
6
7
III. RISK MAAGEMNT POLICY
Q.Can you provide a high level sumry of Avista' s
8 risk management program for energy resources?
9 A.Yes. Avista Utili ties uses several techniques to
10 manage the risks associated with serving load and managing
11 Company-owned and controlled resources.Avista's Energy
12 Resources Risk Policy provides general guidance to manage
13 the Company's energy risk exposure relating to electric
14 power and natural gas resources over the long-term (more
15 than 36 months), the short-term (monthly and quarterly
16 periods up to approximately 36 months), and the immediate
17 term (present month).A copy of the current Energy
18 Resources Risk Policy is in Confidential Schedule 3C in
19 Exhibit No.4.
20 The Energy Resources Risk Policy is not a specific
21 procurement plan for buying or selling power or natural gas
22 at any particular time, but is a guideline used by
23 management when making procurement decisions for electric
24 power and natural gas fuel for generation.Several
25 factors, including the variability associated with loads,
26 hydroelectric generation, and electric power and natural
27 gas prices, are considered in the decision-making process
Lafferty, Di 11
Avista Corporation
1 regarding procurement of electric power and natural gas for
2 generation.
3 The Company aims to strategically develop or acquire
4 long-term energy resources as suggested by the Company's
5 IRP acquisi tion targets,while taking advantage of
6 competitive opportunities to satisfy electric resource
7 supply needs in the long-term period. On the other end of
8 the time spectrum, electric power and fuel transactions in
9 the immediate term are driven by a combination of factors
10 that incorporate both economics and operations, including
11 near-term market conditions (price and liquidity) ,
12 generation economics, project license requirements, load
13 and generation variability, reliability considerations, and
14 other near-term operational factors.
15 For the short-term time frame, the Company's Energy
16 Resources Risk Policy guides its approach to hedging
17 financially open forward positions. A financially open
18 forward period position may be the result of either a short
19 or a long position.A calendar quarter occurring at a
20 future time is an example of such a forward period. A short
21 position situation occurs when the Company has not yet
22 purchased the fixed price fuel to generate power, nor,
23 alternatively, has it purchased fixed price electric power
24 from the market, in order to meet a projected average load
25 for a forward time period.The amount of load that is in
26 excess of the amount of fixed price power available for
27 that forward time period represents an open short position.
Lafferty, Di 12
Avista Corporation
1 A long position situation occurs when the Company has fixed
2 priced generation or fueled generation above its expected
3 average load needs (e. g. hydroelectric generation during
4 the May-June time period) and has not yet made a fixed
5 price sale of that surplus power into the market in order
6 to balance resources and loads. The amount of fixed priced
7 generation that is in excess of the average load for that
8 forward period represents an open long position.
9 The Company employs an Electric Hedging Plan to guide
10 power supply position management in the short-term period.
11 The Risk Policy Electric Hedging Plan is essentially a
12 price diversification approach employing a layering
13 strategy for forward purchases and sales of either natural
14 gas fuel for generation or electric power in order to
15 approach a generally balanced position against expected
16 load as forward periods draw nearer.
17
18
Q.Please describe the Electric Hedging Plan.
A.The Electric Hedging Plan is detailed in Exhibit
19 2 of the Risk Policy (Exhibit No.4, Confidential Schedule
20 3C) .The use of the Electric Hedging Plan approach, as
21 outlined in Exhibit 2 of the Risk Policy (Confidential
22 Schedule 3C), describes what is essentially a layering
23 strategy aimed to average-in purchases or sales of electric
24 power and natural gas generation fuel over a period of
25 time. This approach aims to smooth the impacts of price
26 volatility in the energy markets.
Lafferty, Di 13
Avista Corporation
The Electric Hedging Plan in the Risk Policy describes
2 the basic analytic approach that the Company utilizes to
3 guide hedging electric power positions over the short-term,
4 prompt month, and through the next 34 to 36 month period.
5 The plan guides management of financially open positions in
6 increments of 25 aMW. Open financial positions that exceed
7 25 aMW are cured with a variety of transactions as
8 permitted under the Risk Policy including fixed price
9 physical power, fixed price physical natural gas, and
10 combinations of financial fixed for floating swap
11 transactions coupled with index physical transactions. The
12 Company uses statistical price movement triggers, based on
13 historic volatility in the forward power and natural gas
14 markets, the entire short-term period and also uses
15 triggers based on expiring time periods in the nearer-term
16 period up to 18 months in the future to trigger
17 transactions to cure open positions.The trigger
18 indicators from the Hedge Scheduler statistical model are
19 indicated on the daily position reports and provide
20 guidance to management for prospecti ve forward
21 transactions. Additional details concerning how the Hedge
22 Scheduler works can be found in Exhibit 2 of the Energy
23 Resources Risk Policy.(Exhibi t No.4, Confidential
24 Schedule 3C).
25 Q.Can you provide some addi tional background
26 regarding how the near-term hedging plan operates?
Lafferty, Di 14
Avista Corporation
1 A.Yes.The Electric Hedging Plan (sometimes
2 referred to as the "Hedge Scheduler") operates somewhat
3 differently between two separate time periods within the
4 short-term 36-month window. The period beginning with the
5 prompt month and up to approximately 18 months into the
6 future, as determined by the monthly and quarterly tradable
7 forward periods, focuses on mechanically layering in
8 transactions,. as well as taking advantage of price declines
9 in electric energy or fuel prices.The period
10 approximately 19 months to 36 months into the future, as
11 determined by the number of quarterly tradable forward
12 periods, primarily looks for declines in electric energy
13 prices or fuel prices.
14 Electric surplus and deficit positions are hedged
15 using the Electric Hedging Plan as a guide and may be
16 adjusted by management judgment depending upon the
17 circumstances of a particular surplus or deficit situation.
18 The short-term electric position report is distributed each
19 business day.
20 The power supply position is managed by the Director
21 of Power Supply. Similar types of position issues are also
22 addressed in regards to natural gas supplies and are
23
24
managed by the Director of Gas Supply.Any changes to
practices are communicated to the Risk Management
25 Commi ttee.
26 The Risk Management Committee (RMC) is comprised of
27 Avista management who are not directly part of Energy
Lafferty, Di 15
Avista Corporation
1 Resources operations, and are appointed by the Chief
2 Executive Officer.The RMC provides an oversight and
3 advisory role concerning energy resource management and
4 wholesale energy market risk policies and adherence to
5 those policies.
6 iv. GENERATION CAPITAL PROJECTS
7 Q.Please describe the upgrade projects for the
8 Noxon Rapids generating units.
9 A.The Company is nearing the end of a multi-year
10 program to upgrade four of the five Noxon Rapids generating
11 uni ts from 1950' sera technology2.Once completed, the
12 upgrades on these four units are expected to improve
13 reliability and increase efficiency by adding 30 MW of
14 addi tional capacity and approximately 6 aMW of energy to
15
16
the Noxon Rapids proj ect .Illustration No. 3 below
summarizes the upgrade schedule,and the additional
17 capaci ty and efficiency gains of these upgrades by unit.
18 Illustration No.3: Noxon Rapids Upgrades
Noxon Rapids Schedule of Additional EfficiencyUnit#Completion Capacity Improvement
1 April 2009 7.5 MW 4.16%
3 April 2010 7.5 MW 4.15%
2 Mav 2011 7.5 MW 2.42%
4 May 2012 7.5 MW 1.49%
19
20 The Noxon Unit #1 work included the replacement of the
21 stator core, rewinding the stator, installing a new turbine
22 and performing a complete mechanical overhaul.This
2 The fifth unit was installed in 1977.
Lafferty, Di 16
Avista Corporation
1 upgrade increased the Unit's energy efficiency by 4.16%,
2 and increased the unit rating by 7.5 MW. The upgrade also
3 fixed several reliability concerns for Unit #1 including
4 mechanical vibration and stator age.This work was
5 completed in 2009. The costs and additional generation of
6 this proj ect were pro formed, and approved for recovery, in
7 Case No. AVU-E-09-01.
8 The Noxon Unit #3 upgrade, completed in May 2010,
9 increased energy efficiency by 4.15%, and boosted the unit
10 rating by 7.5 MW. The costs and additional generation for
11 Uni t #3 were approved for recovery in Case No. AVU-E-10-01.
12 Noxon Unit #2 had a new turbine installed and complete
13 mechanical overhaul in May of this year.This upgrade is
14 proj ected to increase Unit #2 efficiency by 2.42% and
15 increase the unit rating by 7.5 MW. The costs for the Unit
16 #2 upgrade were $9.1 million (system).
17 The upgrade work at Noxon Unit #4 involves the
18 installation of a new turbine and a complete mechanical
19 overhaul starting in August 2011 and ending in May 2012.
20 The Unit #4 upgrade is proj ected to increase efficiency by
21 1.49% and increase the unit capacity rating by 7.5 MW.
22 The costs associated with Noxon Unit #2 are $9.1
23 million (system) and Unit #4, planned for completion in May
24 2012, will cost approximately $8.8 million (system).
25 Company witness Ms. Andrews incorporates the Idaho share of
26 these costs in her adj ustments.The increased generating
Lafferty, Di 17
Avista Corporation
1 capabili ty from these units is reflected in Mr. Kalich's
2 AURORA~p modeling of pro forma power supply costs.
3 Q.Can you please provide a brief description of the
4 other generation-related capital projects that are included
5 in this case?
6 A.Yes. The total 2011 and 2012 generation projects
7 included in the Company's case, as identified by Company
8 witness Mr. DeFelice and described below, total $59.6
9 million on a system basis. The 2011 Noxon Unit #2 and Unit
10 #4 upgrade projects discussed above represent $17.9 million
11 of this total.The other generation capital projects
12 totaling $41.9 million (system), are discussed below.
13 Therml - Kettle Falls Capital Additions - $1,731,000
14 Kettle Falls Capital Projects include the acquisition of
15 water rights and subsequent development of the wells for
16 the long-term plant water supply beginning in 2011. The17 other maj or capital proj ect includes the replacement of the
18 boiler control system (DCS). $731,000 of capital additions
19 for this category are for 2011 and the remaining $1,000,000
20 of capital additions are for 2012.
2122 Therml - Colstrip Capital Additions - $11,889,000
23 Colstrip capital additions in 2011 and 2012 include major24 work on the ash storage ponds for Units 3 and 4. This25 proj ect will increase the capacity of the ponds to their
26 final permitted level and is necessary for continued plant
27 operation. During our 2011 outage on Unit 3, we completed
28 installation of a new set of low pressure rotors, a major
29 inspection of the intermediate pressure turbine, a30 generator rewind and other capital proj ects as part of our
31 maintenance program to maintain plant reliability and32 performance. Capital additions for 2012 include superheat
33 section replacement costs for Unit 4, environmental costs
34 associated with the EPA's Hazardous Air Pollutants rule,35 and a rotor rewind. $6,926,000 of the capital additions for
36 this category are for 2011 and the remaining $4,963,000 are37 for 2012 capital additions.
3839 Therml - Coyote Springs 2 Capital Additions - $11,030,00040 At Coyote Springs 2, we are expected to reach 48,000 hours
41 of operation. Maj or gas turbine components are scheduled
42 to be inspected and/or replaced in accordance with original
Lafferty, Di 18
Avista Corporation
1 equipment manufacturer (OEM) guidelines. Avista has a
2 long-term service agreement in effect for the gas turbine
3 wi th the OEM, who will be performing the work. During this
4 extended planned outage, Avista will also be performing
5 maintenance on the steam turbine and other plant systems.
6 $630,000 of the capital spending in this category are for7 2011 and the remaining $10,400,000 are for 2012 capital
8 additions.
910 Therml - Other Small Project Capital Additions - $316,000
11 Please refer to the workpapers of Mr. DeFelice for a
12 detailed listing of the projects included in this category.13 $156,000 of the capital additions in this category are for
14 2011 and the remaining $160,000 are for 2012.
15
16 Hydro - Cabinet Gorge Capital Project - $800,000
17 Capital projects being completed at Cabinet Gorge include
18 the repair and replacement of the discharge ring,19 replacement of the governor on Unit #1, and the replacement
20 of the intake gate controls. The governor on Unit #1 is
21 being replaced because of reliability issues. We have
22 experienced several problems with the governor system and
23 the particular model in place is no longer being supported
24 by the manufacturer. We have a limited number of spare
25 parts for the governor system, and there are components26 that could pose a significant challenge to find
27 replacements to return the unit to service in a timely
28 manner if those components failed. The intake gate
29 controls date back to the original commissioning of the
30 proj ect. The contactors and control switches are no longer
31 dependable and their functionality has become increasingly
32 intermittent. The gate control work involves the
33 replacement of the original motor controls and switches34 with an automated control scheme. All of the capital
35 spending for this category occurred in 2011.
3637 Hydro - Noxon Rapids Capital Projects - $1,000,00038 The Noxon Rapids capital proj ects include the final cost
39 for the replacement of the Generation Step Up transformer A
40 Bank that was completed in 2010. All of the capital
41 additions for this category are for 2011.
42
43 Hydro - Post Falls Capital Project - $2,500,000
44 The Post Falls capital projects include the FERC required
45 replacement of the intake gates. The rack and pinion46 system to raise and lower the intake gates has aged to the
47 point where they are experiencing an increasing number of
48 problems and occasional failures. The gate drive system
49 presents a personnel hazard which can be designed away with50 a new system. The wood timber gates also need to be51 replaced because of age. A new fabricated steel vertical
52 lift gate system will be installed in its place. All of
53 the capital additions for this category are in 2012.
54
Lafferty, Di 19
Avista Corporation
1 Hydro Clark Fork Implementation PM&E Agreement
2 $2,905,000
3 The Clark Fork Implementation PM&E agreement capital
4 expendi tures include the acquisition of property rights for
5 recreational improvements or habitat restoration. Three
6 major acquisitions currently being pursued include the fee
7 ti tle acquisition of the Cabinet Gorge RV Park to meet8 future recreation needs; fee title acquisition of riparian9 habitat on a tributary in Idaho to protect bull trout10 spawning and rearing habitat; and acquisition of a11 conservation easement to protect riparian habitat on the
12 Bull River in Montana. Numerous ongoing recreation site
13 improvements include the replacement of boat ramps, docks,14 and restrooms. upgrading electrical and septic systems, and
15 trail development and improvements. Habitat enhancement
16 projects include improvement and maintenance of existing
17 wetlands on the Noxon Rapids and Cabinet Gorge reservoirs,
18 tributary habitat enhancements such as culvert replacement,19 stream bed reconstruction and riparian re-vegetation and
20 protection to improve passage, spawning and rearing for21 native salmonids. $1,468,000 of the capital additions for
22 this category are for 2011 spending and $1,437,000 are for23 2012 capital additions.
24
25 Hydro - Little Falls Capital Projects - $2,300,000
26 The capital projects at the Little Falls hydroelectric
27 project include the installation of new generator voltage28 regulators and new generator breakers for all four units in
29 2012.
30
31 Hydro - Spokane River Implementation (PM&E) - $3,348,000
32 The Spokane River Project capital projects fulfill FERC's
33 license requirements for aesthetic spill channel
34 modifications at Upper Falls, and numerous recreation site
35 improvements at Nine Mile and Lake Spokane (the Long Lake
36 Dam reservoir). The aesthetic spill channel modification
37 is a mandatory condition, which was included in the License
38 as part of the Washington 401 Water Quality Certification,
39 whereas the recreation projects are FERC's own License
40 requirements. This year we are modeling a number of
41 potential total dissolved gas remedies for Long Lake Dam,
42 and monitoring low dissolved oxygen in the tailrace to
43 determine if the improvements we installed last year will
44 sufficiently meet the State's water quality standards. We
45 are currently working on the channel modifications at Upper
46 Falls, and the required Nine Mile and Lake Spokane
47 recreation projects. $2,243,000 of the capital additions
48 are for 2011 and $1,105,000 of the capital additions are
49 for 2012.
5051 Hydro - Other Small Project Capital Additions - $2,826,000
52 Please refer to the workpapers of Mr. DeFelice for a
53 detailed listing of the projects included in the hydro -
54 other small project capital additions category. $1,874,000
Lafferty, Di 20
Avista Corporation
1 is for 2011 capital additions and $952,000 is for 20122 capital additions.
3
4 Other Small Generation Capital Additions - $1,130,000
5 Please refer to the workpapers of Mr. DeFelice for a
6 detailed listing of the projects included in the hydro -
7 other small generation proj ect capital additions category.
8 $342,000 of the capital dollars are being spent in 2011 and
9 the remaining $788,000 are in 2012.
1011 Ms. Andrews incorporates Idaho's share of these
12 capital proj ect additions in her adjustments.
13 Q.Please provide a sumry of the generation
14 capital expenditures in this case?
15 A.Illustration No. 4 is a table of the generation
16 capi tal projects included in this case.
17 Illustration No.4: Generation Capital Projects Sumry
2011 2012CapitalCapital Total Capi tal
Project Name Additions Additions Costs (OOO's)
(000' s)(000' s)(System)
(System)(System)
Noxon Rapids Unit #2 $9,110 $0 $9,110
Noxon Rapids Unit #4 $0 $8 757 $8,757KettleFalls$731 $1,000 $1,731Colstrip$ 6, 926 $4,963 $11,889
Coyote Springs 2 $630 $10,400 $11,030CapitalAdditions
Other Small Thermal $156 $160 $316CabinetGorqe$800 $0 $800
Noxon Rapids $1, 000 $0 $1,000
Post Falls $0 $2,500 $2,500
Clark Fork $1,468 $1,437 $2,905Implementation
Little Falls $0 $2,300 $2,300
Spokane River $2,243 $1,105 $3,348Implementation
Other Small Hydro $1,874 $952 $2,826
Other Small $342 $788 $1,130Generation
Total $25,280 $34,362 $59,642
18
Lafferty, Di 21
Avista Corporation
1
2
V. HYDRO RELICENSING
Q.Would you please provide an update on work being
3 done under the existing FERC operating license for the
4 Company's Clark Fork River generation projects?
5 A.Yes.Avista received a new 45-year FERC
6 operating license for its Cabinet Gorge and Noxon Rapids
7 hydroelectric generating facilities on the Clark Fork River
8 on March 1, 2001.The Company has continued to work with
9 the 27 Clark Fork Settlement Agreement signatories to meet
10 the goals, terms, and conditions of the Protection,
11 Mitigation and Enhancement (PM&E) measures under the
12 license. The implementation program, in coordination with
13 the Management Committee which oversees the collaborative
14 effort, has resulted in the protection of approximately
15 2,620 acres of bull trout, wetlands, uplands, and riparian
16 habitat.More than 35 individual stream habitat
17 restoration projects have occurred on 25 different
18 tributaries wi thin our proj ect area. Avista has collected
19 data on nearly 12,000 individual bull trout within the
20 proj ect area.The upstream fish passage program, using
21 electrofishing, trapping and hook-and-line capture efforts,
22 has reestablished bull trout connecti vi ty between Lake Pend
23 Oreille and the Clark Fork River tributaries above Cabinet
24 Gorge and Noxon Rapids Dams through the upstream transport
25 of 313 adult bull trout, with over 150 of these radio
26 tagged and their movements studied. Avista has worked with
27 the U. S. Fish and Wildlife Service to develop and test two
Lafferty, Di 22
Avista Corporation
1 experimental fish passage facili ties.Avista,in
2 consul tation with key state and federal agencies, is
3 currently developing designs for both a permanent upstream
4 adult fishway for Cabinet Gorge and a permanent tributary
5 trap for Graves Creek (an important bull trout spawning
6 tributary) .
7
8
Recreation facility improvements have been made to
over 23 sites along the reservoirs.Avista also owns and
9 manages over 100 miles of shoreline that includes 3,500
10 acres of property to meet FERC requirements to meet our
11 natural resource goals while allowing for public use of
12 these lands where appropriate.
13 Finally, tribal members continue to monitor known
14 cul tural and historic resources located wi thin the proj ect
15 boundary to ensure that these sites are appropriately
16 protected.
17 Q.Would you please provide an update on the current
18 status of managing total dissolved gas issues at Cabinet
19 Gorge dam?
20 A.Yes.How best to deal with total dis sol ved gas
21 (TDG) levels occurring during spill periods at Cabinet
22 Gorge Dam was unresolved when the current Clark Fork
23 license was received.The license provided time to study
24 the actual biological impacts of dissolved gas and to
25 subsequently develop a dissolved gas mitigation plan.
26 Stakeholders, through the Management Committee, ultimately
27 concluded that dis sol ved gas levels should be mitigated, in
Lafferty, Di 23
Avista Corporation
1 accordance with federal and state laws. A plan to reduce
2 dissolved gas levels was developed with all stakeholders,
3 including the Idaho Department of Environmental Quality.
4 The original plan called for the modification of two
5 existing diversion tunnels which could redirect streamflows
6 exceeding turbine capacity away from the spillway.
7 The 2006 Preliminary Design Development Report for the
8 Cabinet Gorge Bypass Tunnels Project indicated that the
9 preferred tunnel configuration did not meet the
10 performance, cost and schedule criteria established in the
11 approved Gas Supersaturation Control Plan (GSCP). This led
12 the Gas Supersaturation Subcommittee to determine that the
13 Cabinet Gorge Bypass Tunnels Project was not a viable
14 alternative to meet the GSCP.The subcommittee then
15 developed an addendum to the original GSCP to evaluate
16 al ternati ve approaches to the Tunnel Proj ect. In September
17 2009, the Management Committee (MC) agreed with the
18 proposed addendum, which replaces the Tunnel Proj ect with a
19 series of smaller TDG reduction efforts, combined with
20 mitigation efforts during the time design and construction
21 of abatement solutions take place.
22 FERC approved the GSCP addendum in February 2010 and
23 in April 2010 the Gas Supersaturation Subcommittee (a
24
25
26
subcommi ttee of the MC)chose five TDG abatement
alternatives for feasibility studies.Feasibility studies
and design work continues.Implementation of the addendum
Lafferty, Di 24
Avista Corporation
1 is expected to be significantly less costly than the
2 Tunnels Proj ect Plan.
3 Q.Would you please give a brief update on the
4 status of the work being done under the new Spokane River
5 Hydroelectric Project's license?
6 A.Yes. The Company filed applications with FERC in
7 July 2005 to relicense five of its six hydroelectric
8 generation facilities located on the Spokane River.The
9 Spokane River Project includes the Long Lake, Nine Mile,
10 Upper Falls, Monroe Street, and Post Falls facilities.
11 Little Falls, the Company's sixth facility on the Spokane
12 River, is not under FERC jurisdiction, but operates under
13 separate Congressional authority.In June 2009, FERC
14 issued a new 50-year license for the Spokane River Project,
15 incorporating key agreements with the Department of
16 Interior and other key parties. Implementation of the new
17 license began immediately.Over 40 work plans were
18 prepared, reviewed and approved, as required, by the Idaho
19 Department of Environmental Quality, Washington Department
20 of Ecology, the U. S. Department of Interior,and FERC.
21 The work plans pertain not only to license requirements,
22 but also to meeting requirements under Clean Water Act 401
23 certifications by both Idaho and Washington and of other
24 mandatory conditions issued by the U. S. Department of
25 Interior.In 2010, Avista began implementing a number of
26 water quality, fisheries, recreation, cultural, wetland,
27 aquatic weed management, aesthetic, operational and related
Lafferty, Di 25
Avista Corporation
1
2
conditions (PM&E measures)across all five hydro
developments.In 2011, we will continue to implement
3 approved work plans and will begin implementing the few
4 remaining outstanding ones, once they are approved by FERC.
5
6
7
A number of the approved work plans require the
Company to conduct extensive studies to determine
appropriate measures to mitigate resource impacts.The
8 more significant studies and mitigation measures include
9 those for total dissolved gas (TDG) downstream of the Long
10 Lake facility and the low level of dissolved oxygen in Lake
11 Spokane, the reservoir created by the Long Lake facility.
12 Ini tial estimates for measures to address TDG range between
13 $ 7.0 and $ 17.0 million, and between $2.5 and $8.0 million
14 to address dissolved oxygen in Lake Spokane.These
15 estimates will be further refined as the relevant
16 evaluations and studies are completed.
17 Q.Does this conclude your pre-filed direct
18 testimony?
19 A.Yes it does.
Lafferty, Di 26
Avista Corporation
Integrated Resource Plan (IRP)
Compact Disc Exhibit
Also Available At
htt://ww.avistautiities.comlinside/resources/irp/electric/Pages/default.aspx
Exhibit No.4
Case Nos. AVU-E-ll-01 and A VU-G-LL-01
R. Laffert, Avista
Schedule 1, P. 1 of 1