20090123Storro Direct.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL OF
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P . O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE i WASHINGTON 99220 - 3 7 2 7TELEPHONE: [phone]
FACSIMILE: [phone]
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2UG3 23 PM 12: 39
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AN CHAGES FOR ELECTRIC AN
NATURA GAS SERVICE TO ELECTRIC
AN NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
FOR AVISTA CORPORATION
(ELECTRIC ONLY)
CASE NO. AVU-E-09-01
DIRECT TESTIMONY
OF
RICHAD L. STORRO
1
2
I. INTRODUCTION
Q.Please state your name, employer and business
3 address.
4
5
A.My name is Richard L. Storro.I am employed as
the Vice President of Energy Resources by Avista
6 Corporation located at 1411 East Mission Avenue, Spokane,
7 Washington.
8 Q.Would you briefly describe your educational and
9 professional background?
10 A.I received a Bachelor of Science degree in
11 physics from the College of Idaho and a Bachelor of Science
12 degree in electrical engineering from the University of
13 Idaho, both in 1973. I began working for Avista in 1973 as
14 a distribution engineer and have held several other
15 engineering positions with the Company.I have held
16 management positions in line and gas operations, system
17
18
operations,hydro production and construction,and
transmission.I joined the Energy Resources Department as
19 a Power Marketer in 1997, became Director of Power Supply
20 in 2001, became President of Avista Ventures in 2007, and
21 became Vice President of Energy Resources in January 2009.
22 Q. What is the scope of your testimony in this
23 proceeding?
24
25
A. My testimony will provide an overview of Avista's
resource planning and power operations.This overview
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Avista Corporation
1 includes sumaries of the Company's resources, the current
2 and future load and resource position, future resource
3 plans, and an update on the Company's involvement with the
4
5
Chicago Climate Exchange.The third section discusses the
Lancaster Power Purchase Agreement.The fourth section of
6 my testimony discusses hydro and thermal project upgrades.
7 This is followed by a hydro relicensing update.My
8 testimony concludes with a discussion of generation plant
9 operation and maintenance issues.
10 A table of contents for my testimony is as follows:
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12
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15
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18
19
20
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i.II.III.iv.
V.
VI.
DescriptionIntroduction
Avista i S Resource Planning and Power Operations
Lancaster Power Purchase Agreement
Hydro and Thermal Project upgrades
Hydro Relicensing
Generation Plant Operation & Maintenance
Page
1
3
11
22
25
31
Q.Are you sponsoring any exhibits?
A.Yes.I am sponsoring Exhibi t No.4, Schedules 1
22 through 5. Schedule 1 is Avista' s 2007 Electric Integrated
23 Resource Plan, Schedule 2 is a map and picture of the
24 Lancaster Generation Facility, Schedule 3 is the Lancaster
25 Generating Facility Power Purchase Agreement Evaluation
26 Overview, Schedule 4 is the independent Valuation of the
27 Lancaster Facility Tolling Agreement, and Schedule 5 is the
28 Overview of the Lancaster Power Purchase Agreement.
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Avista Corporation
1
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II.AVISTA i S RESOURCE PLAING AN POWER OPERATIONS
Q.Would you please provide a brief overview of
3 Avista' s power generating resources?
4 A.Yes.Avista's resource portfolio consists of a
5 mix of hydroelectric generation projects, base-load coal
6 and natural gas-fired thermal generation facilities, wood
7 waste-fired renewable generation, natural gas-fired peaking
8 generation proj ects, long-term contracts including wind and
9 Mid-Columia hydroelectric generation, and market power
10 purchases and exchanges.Avista-owned generation
11 facilities have a total capability of 1,787.6 MW, which
12 includes 55% hydroelectric and 45% thermal resources.
13 Table No.1 below sumarizes the present net
14 capabili ty of Avista' s owned generation resources:
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Avista Corporation
1 Table No.1: Avista Generation
t;:.~:~!:i~%~¿t
MW
541
261
18
10.2
15
15
90.4
36
222
280
45
Northeast CT
Kettle Falls CT
Boulder Park
Rathdrum CT
.;;,Jotal:'Natlifai !Gâaeêåkiíl' ...!.
56
10
24
164
2
3 The Company also has long-term contractual rights for
4 166 MW of capability from Mid-Columia generation projects
5 in 2009, owned and operated by the Public utility Districts
6 of Grant, Chelan and Douglas counties.The Company has a
7 ten-year contract for 35 MW of wind generation capability
8 from the Stateline Wind Project and also receives 100 MW of
9 energy from other contracts through 2010.
10 Q.Would you please provide an overview of Avista' s
11 resource planning and power supply operations?
A.Yes. The Company uses a combination of owned and12
13 contracted-for resources to serve its requirements.
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Avista Corporation
1 Dispatch decisions related to these resources are made by
2 Supply section of the Energy ResourcesthePower
3
4
The Department studies capacity and energyDepartmen t .
resource needs on an ongoing basis.The Company utilizes
5 short and medium-term wholesale transactions to balance
6
7
resources with load requirements.Longer-term resource
upgrades to existingdecisionsfornew resources,
8 resources, demand-side management (DSM) , and long-term
9 contract purchases are generally made in conjunction with
10 the Integrated Resource Plan (IRP)and Request for
11 Proposals (RFP) processes.
12 Please suirize the current load and resourceQ.
13 position for the Company.
14 The Company had forecasted annual energy andA.
15 capacity deficits starting in 2011 in the 2007 Electric
16 IRP, without the addition of the Lancaster Power Purchase
17 The Company is currently proj ecting aAgreement (PPA).
18 balanced-to-surplus energy position through 2017 on an
19 average annual basis with the inclusion of the Lancaster
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21
However, as I will explain later, there are monthlyPPA.
and quarterly deficits and surpluses prior to 20l7.The
22 Company's annual energy net resource position becomes
23 deficient in 2018 and the deficiencies will increase from
24 that time forward if additional resources beyond the
25 Lancaster PPA are not added.The average annual energy
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1 resource deficiency in 2018 is 8 aM which increases to 515
2 aM in 2028.
3 The Company's capacity resource position is surplus
4 through 2018 with the inclusion of the Lancaster PPA.
5 Capacity deficiencies begin at 67 MW in 2019 and increase
6 to 843 MW in 2028. Additional details concerning the load
7 and resource positions are in Company witness Kalich' s
8 Exhibi t No.5, Schedule 2.
9 Q.How does the Company plan to meet future resource
10 needs beginning in 2018?
11 A.The Company has pursued the Preferred Resource
12 Strategy laid out in the 2007 Electric IRP, which is
13 attached as Exhibi t No.4, Schedul e 1.The IRP provides
14 details about resource needs, specific cost and operating
15 characteristics of the resources evaluated for the
16 Preferred Resource Strategy, and the scenarios used for
17 resource evaluations.
18 The Company's 2007 Electric IRP was submitted to the
19 Commission in August 2007.The Company will continue
20 evaluating a mix of resource options to meet future load
21 requirements,including medium-term market purchases,
22 generation ownership, hydroelectric upgrades, renewable
23 resources, customer load reduction (e.g., conservation),
24 long-term contracts, and generation lease or tolling
25 arrangements.As stated earlier, longer-term resource
Storro, Di 6
Avista Corporation
1 decisions are generally made in conjunction with the
2 Company's IRP and RFP processes, although the Company does
3 acquire some resources outside of formal RFP processes.
4 The first decade of the Company's Preferred Resource
5 Strategy in the 2007 IRP included a mix of 87 MW of DSM,
6 upgrades to existing plants, 350 MW of gas-fired CCCT, 300
7 MW of wind, and 35 MW of other renewable generation (such
8 as small co-generation, biomass and geothermal) .
9 The Company continues to evaluate and acquire various
10 demand side management (DSM) measures. Avista has acquired
11 approximately 138 aM of DSM over the past 30 years.The
12 Company has over 110 aM of DSM still in place today, which
13 equates to 6.2% of the Company's owned generation. Avista
14 continues to acquire cost-effective DSM and anticipates
15 acquiring an additional 87 aMW of DSM over the next decade
16 based on the 2007 IRP results.
17 The Company's Preferred Resource Strategy will be
18 updated in the 2009 Electric IRP, which we plan to submit
19 to the Commission in August 2009.Research and modeling
20 for this new plan are currently underway by the Company's
21 Resource Planning Department with the aid of the Technical
22 Advisory Committee.
23 Q.Please provide an update on renewable energy
24 acquisitions.
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Avista Corporation
1 A.The Company has actively pursued renewable energy
2 projects that meet the resource acquisition goals set in
3 the Preferred Resource Strategy (PRS) of the 2007 Electric.
4 IRP.The PRS is in the process of being updated for the
5 2009 IRP.The renewable component of the first decade of
6 the 2007 PRS included 300 MW of nameplate capacity wind and
7 35 MW of other renewable resources.Other renewable
8 resources include low or carbon neutral technologies such
9 as biomass, geothermal and solar generation.
10 The Company purchased the rights to develop a 50 MW
11 wind site located at Reardan, Washington from Energy
12 Northwes t in May 2008.This site has already been proven
13 to be a viable wind site through several studies based on
14 collected and historical wind data.We are also
15 investigating the acquisition of additional leases to
16 expand the potential of the site to 65 MW.The Reardan
17 site is currently scheduled to be developed and on line by
18 2013.The Company has also placed met towers at other
19 locations within its service territory and will determine
20 whether or not to proceed wi th further development of any
21 of those sites after sufficient wind speed data is
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collected.Other renewable energy options are also being
considered.The Company will consider a request for
24 proposals for wind and other renewables after the 2009 IRP
25 has been completed in August 2009.
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Avista Corporation
1 Q.Can you provide an overview of Avista's risk
2 management program for energy resources?
3 A.Yes,Avista utilities uses a variety of
4 techniques to manage risks associated with serving load and
5 managing Company resources.The Company's risk management
6 approach uses price diversification through the use of a
7 layering strategy for forward purchases and sales, and by
8 using stop-loss price controls to protect against market
9 price run-ups and run-downs by utilizing upper and lower
10 price control limits.The Energy Resources Risk Policy
11 provides general guidance to manage the Company's energy
12 risk exposure, as it relates to electric power and natural
13 gas resources over the long term (more than 18 months),
14 short term (monthly and quarterly periods out to 18
15 months), and immediate term (present month).The purpose
16 of the Risk Policy is not to develop a specific procurement
17 plan for buying or selling power or natural gas for
18
19
generation at any particular time.Several factors,
including the variability associated with loads,
20 hydroelectric generation, and electric power and natural
21 gas prices, are considered in the decision-making process
22 regarding procurement of electric power and natural gas for
23 generation.
24 The use of a layering strategy reduces the Company's
25 and its customers' exposure to purchases of large amounts
Storro, Di 9
Avista Corporation
1 of energy during high-priced periods.An after-the-fact
2 view of the purchases over time will show that some of the
3 transactions will be advantageous, while other transactions
4 will not be as advantageous.However, this layering
5 strategy will provide for more stable pricing for customers
6 over the long-term.
7 Q.Can you please provide an update of the Company's
8 involvement with the Chicago Climate Exchange?
9 A.Yes, the Company joined the Chicago Climate
10 Exchange (CCX) in 2007. The CCX commitment is divided into
11 Phases 1 and 2 which span 2003 to 2006 and 2007 to 2010
12 respectively.The Company liquidated its 400,000 metric
13 tons of surplus Phase 1 credits in 2008 for $2,577,100 for
14 an average price of $6.44 per metric ton.The Company
15 presently has approximately 147,000 tons of surplus credits
16 from the 2007 compliance year which the Company plans to
17 sell after the CCX prices rebound since they have been
18 below $2 per ton since Septemer 2008.The Company
19 anticipates a surplus of credits for all of the remaining
20 years in Phase 2.We do not plan on continuing with the
21 CCX past Phase 2 when it ends in 2010, because of
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Washington's involvement with the Western Climate
Initiative.The CCX is a voluntary reduction program and
24 companies can no longer be a memer if they are bound by a
25 mandatory emissions reduction program.
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Avista Corporation
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III. Lancaster Power Purchase Agreement
Q.What is the Lancaster Power Purchase Agreement?
A.The Power Purchase Agreement for the Lancaster
Generating Facility (Lancaster PPA)is a tolling
5 arrangement for a merchant gas-fired plant. This merchant
6 plant is located in the Company's service territory just
7 outside of Rathdrum, Idaho.Exhibi t No.4, Schedule 2
8 includes a picture of the Lancaster Generating Facility and
9 a map of its location.
10 The Lancaster Generating Facility is a General
11 Electric Frame 7FA turbine that went into commercial
12 service as a merchant plant in September 2001.The plant
13 is comprised of a 245 MW gas-fired combined-cycle
14 combustion turbine plus 30 MW of duct firing capability.
15 The plant employs 20 people, had an average net heat rate
16 in 2006 of 6,925 btu/kWh, and an average equivalent
17 availability of 92.9% in 2006.
18 Internal and independent reviews both indicated that
19 the Lancaster PPA is cost-effective compared to other
20 resource options under base case conditions as well as
21 under several scenarios that will be described in more
22 detail later in my testimony.
23 Although we are providing documentation regarding the
24 decision-making related to Lancaster in this filing, we are
25 not proposing that the revenues and expenses be reflected
Storro, Di 11
Avista Corporation
1 in retail rates in this filing.Lancaster will become a
2 utility resource on January 1, 2010, and this case will be
3 concluded prior to that time.It is unlikely, however,
4 that Avista' s next general rate case will be concluded on
5 or before January 1, 2010. As Mr. Johnson explains in his
6 testimony, we are proposing that the Lancaster revenues and
7 expenses, beginning January 1, 2010, be included in the PCA
8 until they can be reflected in base retail rates.
9 Q.Could you please provide some background related
10 to the acquisition of the Lancaster PPA by Avista
11 Utilities?
12 A.Yes.The opportuni ty to acquire the power
13 purchase agreement (tolling) rights for Lancaster was a
14 result of negotiations related to the sale of Avista Energy
15 which held the rights to this tolling arrangement.In
16 April 2007, the utility completed an initial assessment of
17 the Lancaster PPA utilizing the 2007 IRP model.The
18 assessment concluded that this type of resource fit the
19 Company's long-term capacity and energy needs. The PRS for
20 the 2007 IRP had indicated that a 350 MW natural gas
21 baseload resource was needed in the 2008 - 2017 timeframe.
22 As part of the April 17, 2007 announcement of the sale of
23 Avis ta Energy to Coral Energy, the Company also announced
24 that Avista Utilities would have rights to the Lancaster
25 PPA beginning on January 1, 2010.
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Avista Corporation
1 Q.Please provide an overview of the agreements
2 included with the Lancaster PPA.
3
4
A.There are three main components to this
agreement,which include the actual Power Purchase
5 Agreement, natural gas transportation for the plant, and
6 transmission for the plant.
7 The PPA for Lancaster is available to the Company from
8 January 1, 2010 through October 31, 2026.In exchange for
9 payments outlined in the PPA, the utility will have the
10 right to dispatch Lancaster. This requires the Company to
11 arrange and pay for natural gas fuel procurement and
12 transportation to the Lancaster plant,as well as
13 subsequent transmission to move the power from the plant.
14 In turn, the Company is entitled to the entire electric
15 capacity and energy output from the plant.
16 The Lancaster plant is interconnected with the Gas'
17 Transmission Northwest (GTN) natural gas pipeline system.
18 On January 1, 2010, the Company will receive permanent
19 assignent of firm natural gas transportation capacity on
20 the TransCanada Alberta and TransCanada BC sys tems and
21 temporary assignent of firm natural gas transportation
22 capacity on the GTN system.The GTN temporary assignment
23 of firm transportation capacity on the GTN pipeline by
24 Shell Corporation terminates on October 31, 2017.These
25 firm transportation agreements will allow for deliveries of
Storro, Di 13
Avista Corporation
1 approximately 26,000 Dth/d from the AECO trading hub on the
2 Alberta system and approximately 26,000 Dth/d from either
3 the Stanfield or Malin trading hubs south of the plant off
4 of the GTN system.
5 The Lancaster plant is interconnected electrically
6 with the Bonneville Power Administration (BPA). There is a
7 transmission agreement, held by the Company in the name of
8 Avista Energy,with BPA for 250 MW of long-term
9 transmission capacity rights from the Lancaster point of
10 receipt to the John Day point of delivery that was assigned
11 to Coral on a short term basis through December 31, 2009.
12 Effective January 1, 2010, there will be a permanent
13 assignent of the long-term transmission rights to Avista
14 utilities.These transmission rights will be used while
15 the Company evaluates interconnecting Lancaster directly
16 with our system.
17 Q.How did the Company determine the need and
18 suitability of the Lancaster PPA?
19 A.The initial analysis was performed by the
20 Company's Resource Planning staff based on the 2007 IRP
21 models and methodology.It had already been determined as
22 part of the IRP process that there was a need for energy
23 and capacity in the timeframe for the availability of the
24 Lancaster PPA based on the load and resource tabulations.
25 An analysis of the first, third and fourth quarters
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Avista Corporation
1 (excluding the spring runoff months)showed deficits
2 beginning in 2010, with annual average energy deficiencies
3 in 2011.Capacity deficits started at 146 MW in 2011 and
4 grew into the future. These energy and capacity deficits,
5 combined with the IRP identified need of 350 MW of base
6 load natural gas-fired resources,indicated that the
7 Lancaster PPA was an alternative option for the Company and
8 its customers.
9 Q.p~ease provide more details about the internal
10 study on the Lancaster PPA.
11 A.The Lancaster Generating Facility Power Purchase
12 Agreement Evaluation Overview was completed on April 11,
2007.A copy of this study is included as Exhibit 4,13
14 Schedule 3.The study identified all of the natural gas-
15 fired combined cycle plants located in the Northwest to use
16 as a comparison to Lancaster. Of the 13 plants identified
17 with a combined capacity of 1,946 MW, only four of those
18 plants besides Lancaster were not owned by utilities. None
19 of these plants were known to be for sale at the time the
20 study was completed.This essentially ruled out the
21 purchase of a brownfield site.However, the study was
22 conducted with the assumption that a brownfield site was
23 available.Brownfield site costs were chosen based on a
24 review of the most recent plant purchases in the Pacific
25 Northwes t .
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Avista Corporation
1 Q.What were the results of the internal study
2 concerning the Lancaster PPA?
3 A.In all base cases, the Lancaster PPA provided a
4 significant benefit relative to the construction of a
5 greenfield plant.The 2010 start date showed a positive
6 benefit to thePPA unless a brownfield project of less than
7 $550/kW were located.The Company was not aware of any
8 such proj ects at the time of this study and has not found
9 any proj ects in this price range since the study was
10 completed.
11 Q.Were any third-party reviews of the Lancaster PPA
12 solicited?
13 A.Yes, in August 2007 the Company contracted with
14 Thorndike Landing, LLC for an independent assessment of the
Lancaster PPA relative to other utility gas-fired15
16 operations.The study used four different valuation
17 metrics and perspectives including discounted cash flow
18 analysis,valuation under a purchase scenario,
19 identification and valuation of similar assets, and a
20 review of similar market transactions in the region. They
21 'also reviewed the Company's analytical processes used for
22 the Lancaster evaluation and resource planning in general.
23 Thorndike Landing completed their study and assessment
24 late in October 2007 and it is included as Exhibit 4,
25 Schedule 4. The study concluded that the Lancaster PPA was
Storro, Di 16
Avista Corporation
1 cost-effective and financially favorable relative to other
2 natural gas-fired options generally available to utilities
3 in the Pacific Northwest.
4 Q.Can you describe the discounted cash flow aspect
5 of the Thorndike Landing study and the results of that
6 study?
7 A.Yes, Thorndike Landing performed a discounted
8 cash flow analysis to determine the intrinsic and extrinsic
9 value of the Lancaster PPA under base, high and low case
10 scenarios.The base case assumed that the output from
11 Lancaster can be interconnected to the Avista transmission
12 system and that the transmission will be remarketed or
13 otherwise optimized. The high case scenario included a
14 doubling of CO2 prices, which raised the overall cost of
15 running this plant by the price of the CO2 emissions
16 credits.The low case scenario assumed the addition of
17 5,000 MW of combined cycle capacity throughout the WECC,
18 which negatively impacts margins by providing a large
19 amount of regional surplus power.The total value of the
20 Lancaster PPA, as dispatched against the market, was
21 positive in all three cases modeled for the Thorndike
22 Landing study showing that the PPA was cost-effective for
23
24
Avista.Table 2 shows the results of this independent
evaluation.The results ranged from a PPA value of
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Avista Corporation
1 $500,000 in the low case up to $20.5 million in the high
2 case.
3 Table 2: Lancaster PPA Value vs. Market
Power Purchase Power Purchase
Agreement Value Agreement Value
Description ($000)($/kW)
Base Case $16,500 $64
Low Case $500 $2
High Case $20,500 $78
4
5 Q.Can you describe the valuation under the purchase
6 scenario section of the Thorndike Landing study along with
7 the valuation of similarly-situated plants?
8 A.Yes, Thorndike Landing performed a valuation of
9 Lancaster under an ownership scenario which was then
10 compared to ownership values of other recent plant
11 transactions in the region.This aspect of the study
12 represented the present value of the difference between the
13 variable dispatch costs, fixed O&M, insurance, and taxes
14 for each plant compared to the proj ect market net revenue.
15 In this portion of the study, the variable dispatch cost
16 excluded the cost of the PPA in the case of Lancaster or
17 the recovery of capital or fixed costs in the case of other
18 plants.This comparison indicated that the Lancaster
19 project had a greater value per kilowatt than recently
20 constructed or transacted plants in the region.Even
21 though the Company will not own the Lancaster plant, this
22 section of the study is a strong indication that a similar
Storro, Di 18
Avista Corporation
1 PPA or toll opportunities at one of the other regional
2 plants would be somewhat less economically favorable to the
3 Company than Lancaster. Table 3 sumarizes the results of
4 this aspect of the study.
5
6 Table 3: Lancaster Plant Value vs. Regional CCCT Projects
7
8
Project Name plant Value ($/kW)
Lancaster $677
Coyote springs 2 $652
Port Westward $528
Goldendale $365
Q.Why did the Company not purchase Lancaster
9 outright rather than taking a power purchase agreement?
10 A.The Thorndike Landing study, along with the
11 Company's own studies, indicated that the outright purchase
12 of Lancaster would be a beneficial and preferable option to
13 the Company.The Lancaster plant became available for
14 purchase in 2007 along with 13 other power plants, all
15 owned by Goldman Sachs through its Cogentrix subsidiary,
16 located across the U. S. in 2007.The Company submi t ted a
17 bid for the Lancaster plant, but that bid was rejected
18 because Goldman Sachs wanted to sell all of the plants to a
19 single purchaser . This left the power purchase agreement
20 as the only viable option for obtaining the generation
21 output from the Lancaster plant.
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Avista Corporation
1 Q.Please discus the aspect of the Thorndike Landing
2 study'that identified market activity for similar types of
3 plants.
4 A.The Thorndike Landing review of similarly-
5 situated plants found seven comparable transactions that
6 yielded an average value of $533/kW within the region.
7 Approximately 25 comparable transactions were found
8 throughout the rest of the U. S. with an average value of
9 $465/kW.Therefore,the Lancaster value of $677/kW
10 compares very favorably with these transactions.
11 Q.What was the final opinion of the Thorndike
12 Landing study concerning the Lancaster PPA?
13 A.Thorndike Landing stated that they "found that
14 the Toll provides positive value to Avista and its
15 customers. . . and the value of the Lancaster facility appears
16 consistent with - if not greater than - the value of other
17 resources in the market." (See Exhibit 4, Schedule 4 at p.
18 1) Thorndike Landing also reviewed Avista's analytic
19 process and valuation methodology and found the following:
20 Thorndike Landing has reviewed Avista' s analytical21 methodology and has found that Avista' s analytical
22 process and methodology is a very contemporary23 approach to analyzing resources. In fact, the
24 utility industry in general has been slow, as25 compared to other industries, to adopt risk26 analysis into its process and it wasn't until the27 power and sector crises of 2001-02 that even some28 utilities began to incorporate risk into their29 processes. Today, we find that many utilities do30 factor risk analyses into their processes, but31 many still do not. Additionally, Avista' s process
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Avista corporation
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is also grounded on sound resource planning using
multiple scenarios and a robust vs. static process
through which the company is able to assess
mul tiple scenarios and resource portfolios, not
just a single resource in isolation. For these
reasons, we have found that Avista' s analytical
process is sound and even surpasses processes used
by many of their peers across the industry.
Therefore, we have not identified any area or
aspect of its process generally for which we would
suggest modification at this time. (See Exhibit 4,
Schedule 4 at p. 15)
Thorndike Landing concluded as follows:
14
15
16
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22
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In conclusion, Thorndike Landing believes that the
transaction for the Toll is reasonable and that
the value Avista would remit for the Toll isreasonable and would resul t in a net benef i t to
Avista and its customers. Further, based on ourt
analysis and assumptions, the value of the
Lancaster Facility appears to be greater than that
of other recently constructed or transacted
facilities in the region. The greater value
appears to be primarily driven by one or more ofthe following:
25 . Lower electric transmission costs
26 . Lower gas transportation costs
27
28
. Lower gas taxes (the state of Idaho has no
fuel tax)
29
30
31
32
. Dual sourcing of fuel (Alberta/Malin vs.
Sumas). (See Exhibit 4, Schedule 4, at p.19)
Q. IS the Lancaster PPA a prudent acquisition?
A.Yes, the Lancaster acquisition is prudent.As
33 shown in the internal and external studies covered in the
34 preceding testimony, the Lancaster PPA is needed for
35 utility service, it is cost-effective compared to other
Storro, Di 21
Avista Corporation
1 alternatives, and fits within the resource needs identified
2 in the 2007 IRP.
3 Q.Can you suirize the studies that lead the
4 Company to believe that the Lancaster PPA is a prudent
5 decision?
6 A.Yes.Both the internal and external studies
7 regarding the Lancaster PPA showed that the PPA was cost-
8 effective when compared to similar base load resources and
9 is needed for utility service based on the Company's load
10 and resource position, and fits within the resource
11 guidelines established in the 2007 IRP.The cost-
12 effectiveness of the PPA included an analysis of the
associated natural gas transportation and electric13
14 transmission agreements.Furthermore, the Lancas ter PPA
15 provides the Company with the ability to operate the plant
16 in a flexible manner consistent with an owned-plant and the
17 PPA stipulations provide protections against losses due to
18 mechanical failures at the facility. A white paper that
19 sumarizes the Lancaster studies can be found in Exhibit 4,
20 Schedule 5.
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iV. HYDRO AN THERM PROJECT UPGRAES
Q.Can you provide an overview of the capi tal
24 improvements. that were recently completed on the Noxon
25 Rapids Proj ect ?
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Avista Corporation
1 A.Yes.Reliability work was completed on Noxon
2 Rapids Unit #5, the largest and most efficient unit at the
3 project, which was installed in 1977.This reliability
4 work began in September 2007 and was completed in 2008.
5 The work was not expected to increase the unit's 92.0%
6 efficiency rating or the 125 MW unit rating, but solved
7 several reliability concerns.The costs associated with
8 this work were approximately $9.2 million (system) and were
9 included and approved in Case No. AVU-E-08-01.
10 Q.Please describe the upgrade proj ects planned for
11 the Noxon Rapids generating units starting in 2009.
12 A.The Company plans to upgrade the Noxon Rapids
13 generating units #1 through #4 which are currently using
14 1950' s era technology.The upgrades on these four units
15 are expected to add an additional 30 MW of capacity and 6
16 aMW of energy to the Noxon Rapids project and improve
17 reliability.One upgrade is planned for completion
18 annually, starting in April 2009 and ending in 2012. Table
19 No.4, Noxon Rapids Upgrades, sumarizes the timing and
20 additional capacity and efficiency of these upgrades.
Storro, Di 23
Avista Corporation
1 Table No. 4:: Noxon Rapids Upgrades
Noxon Rapids Schedule of Additional Additional
Unit #Coiletion Capacity Efficiency
1 April 2009 7.5 MW 5.0%
3 April 2010 7.5 MW 7.8%
2 April 2011 7.5 MW 6.0%
4 April 2012 7.5 MW 4.7%
2
3
4
For Unit #1, we are replacing the stator core,
rewinding the s ta tor,installing a new turbine and
5 performing a complete mechanical overhaul which is expected
6 to be completed in April 2009. This upgrade is expected to
7 increase the unit's efficiency 5.0% and increase the unit
8 rating 7.5 MW.The upgrade will also solve several
9 reliability concerns for the unit including mechanical
10 vibration and the age of the stator.
11 The remaining upgrade work on Units #2, #3 and #4 are
12 planned from 2009 to 2012. The Unit #3 upgrade is planned
13 to increase unit efficiency 7.8% and boost the unit rating
14 7.5 MW.Uni t #2 is scheduled to have a new turbine and
15 complete mechanical overhaul between August 2010 and April
2011.This upgrade is planned to increase unit #216
17 efficiency 6.0% and boost the unit rating by 7.5 MW.The
18 upgrade work at Unit #4 involves the installation of a new
19 turbine and a complete mechanical overhaul from August 2011
20 through April 2012.The Unit #4 upgrade is planned to
Storro, Di 24
Avista corporation
1 increase efficiency 4.7% and increase the unit rating by
2 7.5 MW.
3 The costs associated with Unit #1 are planned for
4 completion in April 2009 i totaling approximately $17.2
5 million (system), is further described in Company witness
6 Mr. DeFelice's testimony.Company wi tness Ms. Andrews
7 incorporates the Idaho share of these costs in her
8 adjustments.The costs for the remaining Noxon Rapids
9 upgrades for units #3, #2 and #4 have not been included in
10 this case, but will be included in future rate proceedings.
11
12
13
v.HYDRO RELICENSING
Q.Would you please provide an update on work being
14 done under the existing FERC operating license for the
15 Company's Clark Fork River generation projects?
16 A.Yes.Avista received a new 45-year FERC
17 operating license for its Cabinet Gorge and Noxon Rapids
18 hydroelectric generating facilities on the Clark Fork River
19 on March 1, 2001.The Company has made significant
20 progress working in collaboration with 27 signatories to
21 the Clark Fork Settlement Agreement toward meeting the
22 goals, terms, and conditions of the Protection, Mitigation
23 and Enhancement (PM&E) measures under the license.The
24 implementation program has resulted in the protection of
25 approximately 2,500 acres of bull trout, wetlands, uplands,
Storro, Di 25
Avista Corporation
1 and riparian habitat.The fish passage program, using
2 electrofishing and trapping with over 150 adults radio
3 tagged and their movements studied, has reestablished bull
4 trout connectivity between Lake Pend Oreille and the Clark
5 Fork River tributaries above Cabinet Gorge Dam. Avista has
6 worked with the U. S. Fish and Wildlife Service to develop
7 two experimental fish passage facilities.The testing of
8 these facilities, however, has not produced a design that
9 will attract adult bull trout. Nevertheless, studies will
10 continue to seek solutions for developing a volitional fish
11 passage facility.
12 Recreation facility improvements have been made to 30
13 si tes along the reservoirs.Finally, tribal memers
14 continue to monitor known cultural and historic resources
15 located within the project boundary to ensure that these
16 sites are appropriately protected.The earlier costs
17 associated with the PM&E measures were reviewed and were
18 included in prior cases.Ms. Andrews has included a pro
19 forma adjustment to reflect the planned PM&E expenditures
20 for the 2009/2010 proforma period.
21 Q.Would you please provide an update on the current
22 status of the Cabinet Gorge Bypass Tuels Project?
23 A.Yes. Total dissolved gas levels occurring during
24 spill periods at Cabinet Gorge Dam was an unresolved issue
25 when the current Clark Fork license was received.The
Storro, Di 26
Avista Corporation
1 license provided time to study the actual biological
2 impacts of dissolved gas and subsequent development of a
3 dissolved gas mitigation plan.The studies documented no
4 biological impact from dissolved gas below the proj ect;
5 however,the stakeholders ultimately concluded that
6 dissolved gas levels should be mitigated, in accordance
7 with federal and state law. A plan to reduce dissolved gas
8 levels was developed with all stakeholders, including the
9 Idaho Department of Environmental Quality. The original
10 plan called for the modification of two existing diversion
11 tunnels which could redirect streamflows exceeding turbine
12 capacity away from the spillway.
13 The 2006 Preliminary Design Development Report for the
14 Cabinet Gorge Bypass Tunnels Project indicated that the
15 preferred tunnel configuration did not meet the
16 performance, cost and schedule criteria established in the
17 approved Gas Supersaturation Control Plan (GSCP). This led
18 the Gas Supersaturation Subcommittee to determine that the
19 Cabinet Gorge Bypass Tunnels Proj ect was not a viable
20 alternative to meet the GSCP.The subcommittee is
21 developing an addendum to the original GSCP and it is
22 expected to be completed in the first quarter of 2009.
23 Even though the final addendum has not been completed, the
24 subcommittee has agreed that the tunnel bypass proj ect did
25 not meet expectations so an addendum to the GSCP with
Storro, Di 27
Avista Corporation
1 mitigation and other alternatives must be pursued.The
2 cost of the original study was completed in 2008 and
3 included in the last Idaho General Rate Case, No. AVU-E-08-
4 01.
5 Q.What is the status of expenditures related to
6 compliance with the Clark Fork P.E's?
7 A.Since implementation began,the Clark Fork
8 Management Committee1 (CFMC) and FERC have reviewed and
9 approved all annual PM&E budgets.The CFMC has been very
10 deliberate in their review and approval of annual budgets
11 to assure that only quality projects directly tied to the
12 CFSA are approved. In addition, during the last several
13 years, unforeseen conditions such as severe rain and snow
14 events, extended spring run-off sometimes resulting in
15 flooding, and dramatic swings in fuel and materials costs
16 have resulted in a numer of previously approved proj ects
17 eventually being postponed or eliminated.Those proj ects
18 combined with the prudence review of the CFMC, have
19 resulted in a larger then anticipated unexpended PM&E
20 obligation currently estimated at $4.3 million.In
21 anticipation of the need to reduce the unexpended
22 obligation and to assure that the unexpended obligation
23 does not continue to grow, Avista plans to expend, with
1 The Clark Fork Management Committee is comprised of representatives
from the 28 Agency, Tribal and Non-governmental signatories to the
Clark Fork Settlement Agreement.
Storro, Di 28
Avista Corporation
1 CFMC approval, an additional $500,000 per year in O&M
2 expenditures, starting in early 2010, for the 2010 - 2015
3 timeframe. Ms. Andrews has included a proforma adjustment
4 to reflect this increased spending level.
5 Q.Would you please give a brief update on the
6 status of efforts to relicense the Spokane River
7 Hydroelectric Projects?
8 A.Yes. The Company filed applications with FERC in
9 July 2005 to relicense five of its six hydroelectric
10 generation projects located on the Spokane River.The
11 Spokane River Project, which is currently under a single
12 FERC license, includes Long Lake, Nine Mile, Upper Falls,
13 Monroe Street, and Post Falls. Little Falls, the Company's
14 sixth proj ect on the Spokane River, is not under FERC
15 jurisdiction, but operates under separate Congressional
16 authority.Our current license for the Spokane River
17 Project expired in August 2007.The Company is currently
18 operating under an annual license, but expects to receive a
19 new 50-year license by July 2009.
20 The Spokane River Relicensing costs include actual
21 life-to-date expenditures from April 2001 through the end
22 of December 2008, and 2009 pro forma expenditures through
23 June 30 , 2009 .As explained by Company wi tness Ms.
24 Andrews, the maj ori ty of these charges were reviewed in the
Storro, Di 29
Avista Corporation
1 Company's previous general electric rate case proceeding,
2 Case No. AVU-E-08-01.Through the Settlement agreement
3 approved by the Commission in that case, the Company was
4 allowed to defer the amortization of these charges,
5 including a carrying charge on the deferrals and
6 unamortized balance, and include recovery of these costs in
7 its next general rate case.
8 Q.Has there been a final resolution to the
9 relicensing issues associated with the Coeur d'Alene Tribe?
10 A.Yes.A comprehensive agreement was signed with
11 the Coeur d' Alene Tribe and the U. S . Department of the
12 Interior.This agreement supports the issuance of a 50-
13 year FERC license for the Post Falls hydroelectric proj ect
14 and the Spokane River hydroelectric proj ects .The
15 comprehensive settlement provides for payment over the life
16 of the license of over $150 million for environmental
17 measures in and around Coeur d' Alene Lake and for
18 compensation to the tribe, as well as rights-of-way for
19 transmission lines over tribal lands and future storage
20 payments connected with a new FERC license for the Post
21 Falls dam.The settlement also includes provisions for
22 Avista to make payments to the Tribe for past and future
23 use of submerged Tribal lands and to satisfy the Company's
24 obligation to mitigate the impacts of the Post Falls dam on
Storro, Di 30
Avista Corporation
1 the Tribes natural and cul tural resources on its
2 Reservation.
3 The proposed settlement between the Coeur d' Alene
4 Tribe, Avista, and the U. S. Department of the Interior was
5 explained in Avista' s prior general rate case (Case No.
6 AVU-E-08-01) .Ms. Andrews has reflected the costs
7 associated with the settlement in this case through a pro
8 forma adjustment.
9
10
11
VI.Generation Plant Operation & Maintenance Expenses
Q.Is the Company experiencing increased
12 expenditures associated with the operation and maintenance
13 of its generation facilities?
14
15
A.Yes.The operation and maintenance expenses for
Avista's generating facilities continue to increase.Ms.
16 Andrews has included Idaho's share of the 2009-2010
17 proforma period incremental non-labor costs above the test
18 period of approximately $899,000 (Idaho share).These
19 increases are mainly due to major O&M expenditures planned
20 for Colstrip (completed 1984 1986) ,Kettle Falls
21 (completed in 1983), and Rathdrum CT (completed in 1995).
22 Increased costs at Colstrip include major overhauls of
23 units # 4 and #3 in 2009 and 2010 respectively.Kettle
24 Falls will be undergoing a turbine overhaul in 2009.
25 Rathdrum CT has a hot gas path maintenance scheduled for
Storro, Di 31
Avista Corporation
1 unit #1 in 2010 and painting of both units in 2011. These
2 increases represent a new and higher level of O&M costs
3 that are expected to continue given where each of the
4 projects are in their respective life-cycles.
5 Q.In addition to the O&M expenses described above,
6 are there other significant O&M expenses anticipated by the
7 Company?
8 A.Yes.The Company and the owners of Colstrip
9 Units #3 and #4 are required to mitigate the mercury
10 emissions from these projects. Mercury emissions laws in
11 Montana are going into effect January 1, 2010 with a second
12 phase going into effect in 2018.Initial testing of
13 mercury control technologies at Colstrip did not meet the
14 targets set by the Montana Department of Environmental
15 Quality, but further optimization of the mercury control
16 systems is expected to meet the required emissions levels.
17 Full mercury control operations are expected to begin by
18 mid-2009 to provide enough time to fine tune the system
19 with Colstrip plant operations.
20 The largest expense involved with the mercury control
21 proj ect will be a significant increase in O&M costs.The
22 Company's share of the new O&M costs is expected to be
23 approximately $3 million per year.The current capital
24 budget for Colstrip is estimated to be sufficient to meet
25 the capital expendi tures for this proj ect .After some
Storro, Di 32
Avista Corporation
1 initial capital expenditures planned in 2009, the increase
2 in O&M costs is expected to start in December 2009.Ms.
3 Andrews has included the Idaho share of the pro forma
4 period expenses in her pro forma adjustments in this case.
5 Q.Does this conclude your pre-filed direct
6 testimony?
7 A. Yes it does.
Storro, Di 33
Avista Corporation
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL OF
REGULATORY & GOVERNENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKAE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
ED
2009 JåN 23 PH 12: 40
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-09-01
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-09-01
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURA GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 4
AN NATURA GAS CUSTOMERS IN THE )STATE OF IDAHO ) RICHARD L. STORRO
)
FOR AVISTA CORPORATION
(ELECTRIC AN NATUR GAS)
Integrated Resonrce Plan (lRP)
Compact Disc Exhibit
Also Available At
http://ww.avistautilities.com/inside/resources/irp/electriclPages/default.aspx
Exhibit No.4
Case Nos. A VU-E-09-01 and A VU-G-09-01
R. Storro, A vista
Schedule 1, P. 1 of 1
Exhibit No.4
Case No. A VU-E-09-01
R. Storro, A vista
Schedule 2, p. 1 of 2
Exhibit No.4
Case No. AVU-E-09-01
R. Storro, A vista
Schedule 2, p. 2 of 2
Lancaster Generating Facility Power Purchase
Agreement Evaluation Overview
April 11, 2007
Introduction & Summary
In early 2007 Energy Resources was asked to determine if Avista utilties would
benefit from acquisition of the 275 MW Lancaster Generating Facilty Power
Purchase Agreement ("Power Purchase Agreement" or "Lancaster") then owned
by Avista Energy.
The plant is an option to the utilty as part of Avista Corporation's proposed sale
of Avista Energy to Coral Energy. The Power Purchase Agreement is essentially
a "tollng arrangement" whereby the Lessee delivers natural gas to the plant and
receives the capacity and energy output in exchange for paying the Lessor fixed
and variable Power Purchase Agreement payments. The Power Purchase
Agreement expires on October 31, 2026.
Analyses based on the Avista IRP and Northwest Power and Conservation
Council's ("NPCC") planning assumptions indicate that the acquisition of an
existing gas-fired combined-cycle turbine (CCCT) is potentially more valuable
than the construction of a new gas-fired plant. Avista's 2007 Draft IRP had
identified a CCCT as a preferred resource. The analysis further shows that the
Power Purchase Agreement wil benefi Avista when compared both to new and
other existing CCCT plants that were recently transacted or constructed in the
Pacific Northwest region.
Assumptions
Assumptions in a number of different areas are necessary to complete the
Lancaster Power Purchase Agreement comparison, including alternative
resources the company might consider, natural gas supply, taxes and
transportation, electricity transmission, plant operating and maintenance costs,
end-of-Iife plant values, and rates for inflation and discounting. Because the
comparative resources are all newer-vintage natural gas-fired CCCTs with similar
heat rate and operating costs, natural gas supply and transportation costs and
operation costs were assumed to be the same for each plant; therefore, these
costs were not explicitly modeled in the comparative evaluation. One benefi not
modeled is the fact that the Power Purchase Agreement places some of the risk
of forced outages and maintenance on the Lessor, removing some of this risk
from Avista and its customers.
A brief discussion of the modeling assumptions is provided below.
Lancaster Generating Facilty Power Purchase Agreement Evaluation Overview
Exhibit No.4 Page 1 of 7
Case Nos. AVU-E-09-01 and AVU-G-09-01
R. Storro, Avista
Schedule 3, Page 1 of 7
Power Purchase Agreement Alternatives
Avista's 2007 IRP process provides guidance on the resources available to serve
customer needs. The IRP process shows that the Company needs up to 350
MW of gas-fired generation along with other renewable generation technologies
and conservation.
Given the significant component of gas-fired CCCT resources in the 2007 IRP,
the Power Purchase Agreement evaluation focuses on comparisons with other
potentially available CCCT options. The 2007 IRP estimates new, or
"greenfield", CCCT plant costs at $786/kW in 2007 dollars, or approximately
$850/kW in inflation-adjusted 2010 dollars. This later figure is used to represent
the cost of a new plant for the analysis.
The Power Purchase Agreement is also compared to an estimated cost of an
existing, or "brownfield", CCCT plant in the Northwest. Table 1 is a list of
Northwest CCCT plants. Plants not owned by regional utilities are highlighted.
Table 1 - Northwest CCCT Plants
Name
Coyote Spnngs 2
Freenckson
Utlity Owner
Utilty
Utilty
Capacity (M W)
287
256
Encogen 1
Total Non-Utilty (MW)
As shown, total non-utilty CCCT plant capacity is under 2,000 MW, including the
Lancaster Generation Facilty. Besides Lancaster, only 4 plants are not owned
by a utilty today. To Avista's knowledge, none of the plants are for sale. Two
are larger than the amounts recommended by the IRP process.
Acquiring another brownfield CCCT plant is therefore considered unlikely;
however, Avista chose to compare the Power Purchase Agreement economics
as if brownfield options were available to it. The following table provides a
summary of recently-completed CCCT transactions. The "2010 Price" escalates.
each transaction for inflation to 2010 dollars assuming 3% annual inflation.
Lancaster Generating Facility Power Purchase Agreement Evaluation Overview
Exhibit No, 4 Page 2 of 7
Case Nos, AVU-E-09-01 and AVU-G-09-01
R. Storro, Avista
Schedule 3, Page 2 of 7
Table 2 - Recent Pacific Northwest CCCT Plant Sales ($/kW)
Purchase Purchase 2010
Plant Name Buyer Year Price Price
Frederickson PUQet Sound EnerQV 2003 590 726
Coyote SDrinQS 2 Avista 2004 446 533
Goldendale PUQet Sound EnerQV 2007 480 525
Given the 2010 price range in Table 2, the company selected for this analysis
two cost estimates for brownfield sites: $550/kW and $500/kW.
Electric Transportation (Transmission)
The Lancaster Generation Facilty is located in Avista's Northern Idaho service
territory. It presently is interconnected into the Bonnevile Power Administration
("BPA") control area. Avista plans to explore the option to directly interconnect
the Lancaster plant to its transmission system to avoid most of the BPA firm
transmission costs. The interconnection cost is estimated at $3 milion.
Along with the Power Purchase Agreement the company wil receive a long-term
firm transmission path from the Lancaster point of receipt to John Day. Under
the assumption that Avista will be able to interconnect Lancaster directly to its
transmission system, it wil not require the BPA transmission during most of the
year. The BPA transmission can therefore be used to better optimize Avista's
resource operations or be sold to 3rd parties wanting to move energy across the
"West of Hatwai" constrained path. The analysis assumes that only 25% of the
existing firm transmission contract cost is not recovered through re-marketing of
the BPA transmission or otherwise optimized through other power transactions.
Greenfield and brownfield plants are assumed to require a transmission contract
with the Bonnevile Power Administration for their entire operating capacity, as
such a path would be necessary to move electrical energy from their respective
locations to Avista's service territory.
In the event Avista does not interconnect the Lancaster plant directly to its
system, it would not incur the $3 millon interconnection cost but would directly
utilize BPA transmission. In a worst case scenario where none of the BPA
transmission was re-marketed or otherwise optimized, the cost of the Power
Purchase Agreement would rise by approximately $66 milion on a present value
basis. However, since Lancaster is a dispatchable plant, it is reasonable to
assume that at least a portion of the BPA transmission costs could be recovered.
A 25% cost recovery is a reasonable assumption and represents a cost of
approximately $42 milion on a present value basis.
Lancaster Generating Facilty Power Purchase Agreement Evaluation Overview
Exhibit No.4 Page 3 of 7
Case Nos. AVU-E-09-01 and AVU-G-09-Q1
R. Storm, Avista
Schedule 3, Page 3 of 7
Power Purchase Agreement and Capital Recovery Payments
The Power Purchase Agreement includes a known set of payments. Brownfield
and Greenfield options would be owned by Avista and capital recovery would
occur over a defined schedule. The analysis uses the 2007 IRP capital recovery
factors applied to all owned plant options.
Ending Value
The Lancaster Generation Facilty Power Purchase Agreement expires on
October 31,2026. Avista wil retain no value from the plant after expiration. To
level the playing field with ownership options where residual, or ending, value
would apply; all ownership option comparisons (Le., all except the Lancaster
plant) assume an ending value. For brownfield comparisons, the ending value is
10% of what a new plant would cost in 2027, in line with industry estimates. A
greenfield plant ownership option would have a longer life due to its being
constructed as much as ten years later than the brownfield and Lancaster plants.
The greenfield residual value equals the brownfield ending value and the present
value of forecasted wholesale market values through the end of its 30-year
economic life after 2026.
Scenarios
It is unclear at this time when the Lancaster plant wil be made available to
Avista. There is also uncertainty over when the company wil be resource deficit
because of changing load forecasts.
Avista Loads and Resources Deficiency
The value of a new resource depends on the utility's loads and resources
balance. Where the company is long-Le., resources exceed loads-the value is
what can be generated through sales into the wholesale marketplace. When the
company is short-Le., loads exceed resources-it is reasonable to include not
only the market value of energy, but also the capital recovery and other fixed
costs associated with plant ownership. Both of these assumptions are consistent
with the I RP methodology.
The analysis considers two starting deficiency dates: 2011 based on work
performed in the 2007 IRP, and immediate based on regional work by the
Northwest Power and Conservation Council (NPCC). The first load deficiency
identified in the 20071RP process is in 2011. Loads, including a planning margin
equal to 10% of peak day load and 90 MW for reduced resource capabilties due
to river freeze ups and coal handling issues, are compared to expected peak-day
resource capability. The planning margin approximates 15%.
Lancaster Generating Facilty Power Purchase Agreement Evaluation Overview
Exhibit NO.4 Page 4 of 7
Case Nos. AVU-E-09-01 and AVU-G-09-01
R. Storr, Avista
Schedule 3, Page 4 of 7
The NPCC is leading an effort to better define the peak generating capabilty of
the Northwest. The NPCC planning criteria, based on a cross-functional work
effort including many Northwest utilties, is approximately 25% based on a 5%
loss-of-Ioad probabilty across the entire northwest electric system and loads.
Though the criterion is not yet finalized, the reserve level has remained
approximately the same throughout the work effort. To meet the NPCC target,
each Northwest utility would need to own or control resources capable of
generating at levels 25% greater than their expected peak load. Under this
criterion, Avista is capacity deficient immediately.
Power Purchase Agreement Availabilty Date
Because Power Purchase Agreement negotiations with Coral Energy are
ongoing, the company chose to evaluate the Power Purchase Agreement across
three start dates: 2009, 2010, and 2011. In the greenfield and brownfield
evaluations, the plants are assumed to begin in the actual year of resource
deficiency where the Power Purchase Agreement begins on the start date
irrespective of the load and resources balance. For example, in the scenario
where the Power Purchase Agreement is transferred to Avista in 2009 and the
IRP methodology identifies a 2011 deficit, Power Purchase Agreement costs and
benefits begin in 2009. Brownfield and greenfield plants, however, are not
brought into the mix until 2011. Because the analysis assumes that the sum of
the fixed and variable costs of the Power Purchase Agreement exceed the value
of power in the spot market, the early inclusion of the Power Purchase
Agreement prior to the deficit year decreases its value relative to other options.
Results
The following summarizes the results of the analysis shown in Appendix 1 -
Study Results:
. The Lancaster Power Purchase Agreement is lower cost than the
greenfield plant being included in the Preferred Resource Strategy of the
20071RP. A greenfield project is the company's most realistic alternative
to Lancaster for acquisition of a CCCT resource.
. The Lancaster Power Purchase Agreement is less expensive than either
brownfield or greenfield plants under all cases where Avista carries
reserve margins in line with the NPCC reserve requirements.
. The only scenarios where a brownfield CCCT was shown be more
beneficial than the Lancaster Power Purchase Agreement was where the
plant was transferred to Avista prior to 2010, or where such brownfield
plant's purchase cost is below $550/kW.
. Transmission scenarios, where less than 75% of the BPA firm
transmission cost might be recovered in the market, have the effect on
reducing the positive values shown in Table 3. As stated earlier, the
maximum impact is estimated to be approximately $66 milion if none of
Lancaster Generating Facility Power Purchase Agreement Evaluation Overview
Exhibit No, 4 Page 5 of 7
Case Nos. AVU-E-09-01 and AVU-G-09-01
R. Storro, Avista
Schedule 3, Page 5 of 7
the BPA transmission is re-marketed or otherwise optimized. Because
Lancaster is a dispatchable CCCT, it is reasonable to expect that some
level of cost recovery, possibly up to 25%, wil be achievable even in the
case where the project is not interconnected to the Avista system and
remains on the BPA transmission system. A 25% transmission cost
recovery scenario adds approximately $42 millon to the Power Purchase
Agreement value (cost of Power Purchase Agreement). A greenfield plant
continues to be more costly than the Lancaster Power Purchase
Agreement in each of the three start date scenarios under this
transmission circumstance.
In summary, the study found that in most scenarios the Power Purchase
Agreement wil have a positive value to customers. In all base cases the
Lancaster Power Purchase Agreement provides a significant benefi relative to
constructing a new greenfield plant. The 2010 start date showed a positive
benefit to the Lancaster Power Purchase Agreement except in the case where
Avista were to have an opportunity to acquire a brownfield plant at a cost below
$550 per kilowatt. The Company is not aware of such a brownfield opportunity
available in the marketplace at this time.
Lancaster Generating Facilty Power Purchase Agreement Evaluation Overview
Exhibit No, 4 Page 6 of 7
Case Nos, AVU-E-09-01 and AVU-G-09-01
R, Storro, Avista
Schedule 3, Page 6 of 7
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Independent Valuation of
Lancaster Facility Tolling Agreement
October 30, 2007
Thorndike Landing, LLC
68 Thorndike Street
Dunstable, Massachusetts
Phone: [phone]
ww.thorndikelanding.com
Exhibit No,4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 1 of 31
Notice of Confidentiality and Limitation of Liabilty
Copyright
This report is protected by copyright. Use of this report for any purose other than those described
herein, including any copying, reproduction, performance or publication in any form without the express
wrtten consent of Thorndike Landing is prohibited,
Confidentiality
The following report represents an analysis performed by Thorndie Landing and contans confdential
information belonging to Thorndike Landing and confidential inormation which it received
(collectively, "Confdential Information") pursuant to its engagement agreement executed with A vista
Corporation ("Client"). Any person acquirg this report agrees and understands that the information
contained in this report is confdential and, except as required by law, wil tae all reasonable measures
available to it by intrction, agreement or otherwise to maintain the confidentiality of the Confidential
Information. Such person agrees not to release, disclose, publish, copy or communicate this Confidential
Information or make it available to any thrd part, including, but not limted to, consultants and financial
advisors, other than employees, agents and contractors of such person and its affliates and subsidiaries
who reasonably need to know it in connection with the exercise or the performance of such person's
business. Such person agrees that any disclosure of this Confidential Information in a maner
inconsistent with the above provisions may cause Thorndike Landing irreparable harm for which
remedies other than monetar relief may be inadequate, and such person agrees that Thorndike Landing
shall be entitled to receive from a cour of competent jursdiction injunctive or other equitable relief to
restrain such disclosure in addition to other appropriate remedies,
No Warranties or Representations
Any peron acquig ths rert agrees and undertads tht Thorndie Ladig maes no representations or
warties as to the accurcy or completeness of the inormtion contaed in this report. Some of the
assumptions used in the prepartion of ths report, although considered reasonable at the tie of prepartion,
inevitably will not materialze as projected as unticipated events and circumtaces occur subsequent to the
date of ths report Accordigly, ac outcomes will var frm projected outcomes and the varations may be
materal. There is no representation that our projections will be reaed. Any person reg ths report
acknowledges tht Thorndie Landig assues no responsibilty for the use of the reprt by tht peon. Such
person assues sole responsibilty for any use he or she maes of ths report or any reliance upon or decisions
made based upon ths report.
Limitation of Liabilty
In no event wil Thorndike Landing be liable for any direct, indirect, special, consequential or incidental
damages, costs or expenses, including but not limited to damages for loss of business profit, information,
use of the report or resulting products or services arising from use or inabilty to use the report or any
information contained therein, whether in tort, negligence, contract or otherwise even if Thorndie
Landing has been advised of the possibilty of such damages.
Exhibit NO.4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 2 of 31
Table of Contents
Executive Summary ......,...... ....,.............................................. .................................................... i
Objective and Purpose ,................, ,......................................... ......,.............,............................... 3
Description of Facility and Tolling Agreement .............................................................,........4
Thorndike Landing Approach ................, ......,...., ,........., "............,....,.....,...........,. ,..,...,... ,....... 6
Valuation of the Toll......,..,...................,.........................."........................,..........................................................6
Valuation of the Lancaster Facility ,.",.........................................,.............................................,.,.......".......,...10
Valuation of Select Assets Tranacted in Market....................,........ ,... ...... ............ ................. ...................., ...11
Transacton Market Comparables............"...............,....................................................,.,...............".............,.11
Other Considerations (Toll versus Owership) ........................,................,..........,.........................................13
Review of A vista Analytical Process..... ..... .......... .... ........ ................ ........ ......... ............ ......... 14
Overview of A vista Analytical Approach .............................,........................................................................14
Results of Thorndike Review ....",...",........,............,...........................,.....,.,......,.,..............",.,.",.,...,....,..........15
Results and Conclusions.... ,...........,.,...,........... ...............,....................................,...............,... 17
Base results.....,.,...,.....,......".......,...",.".....,............,...........,.,.,..........,.......",....,....,.....,.........,..........,..................,17
Sensitivities ..,..........................,..........,................,.......,........................,...,......................,......,.....,.........,..,.........,18
Conclusion ...................,...,.......................,.............................,.....................,.,...................,.................................19
Appendix A: Description of IECM .....,...................................................................................20
Obvious Advantages of Integration ......,............,........,......".,....".........,...,..,.,......,............,............,....,......",..20
Methodology..,."".......,............""...........,.......,...,.".,...""".........,.....".........,.......,.,...........".....,...........,...........,.,20
Emissions: Pollutants and Carbon Dioxide..........................,...............,..........................................................21
Extrnsic Value Drivers .......................,......,....................,..........".......,.........,..................,...,..,.........",...........",21
Key Assumptions and Results for the Various.Scenarios.......................................,......................................21
Appendix B: Conditions and Assumptions...........................................................................22
Appendix C: Lancaster Toll Forecasted Financials, Valuation...........................................24
Exhibit No.4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 3 of 31
Executive Summary
Thorndike Landing, LLC ("Thorndike Landing") was retained by Avista Corporation ("Avista") to
pedorm an independent valuation of the tollng arangement ("Toll") associated with the Lancaster
generating facility, a 262 MW gas-fired combined cycle plant ("Facilty") curently owned by a third
par. The Toll will become available to the portfolio of Avista's regulated utility, Avista Utilties, Inc.
as of Januar 1,2010,
For this effort Thorndike Landig looked at several different valuation metrcs and perspectives to derive
the valuation for the transaction contemplated by Avista. First, we pedormed a discounted cash flow
("DCF") analysis to determne the value of the Toll from the perspective of the Lessee under the ter of
the Toll and takng into consideration al of the key factors for that agreement. Second, we pedormed a
valuation of the Facilty under a purchase scenao. For this valuation, we used the DCF method to value
the Facility as of the valuation date (as more fully described herein) from the perspective of the owner
without the Toll (i.e" assuming merchant operations). The approach and assumptions for ths valuation
were consistent with that used in valuing the Toll, except for factors that were clearly not applicable for a
plant valuation versus a toll valuation (e.g., the useful life period was assumed to be 35 years versus the
term of the Toll, the tolling payments were excluded, etc.).
The next valuation metrc we employed was to identify a few select assets in the maket and pedorm
valuations of those simlarly-situted plants, For ths effort, Thorndike Landig pedormed valuations of
the Goldendale facility as purchased by Puget Sound Energy earlier ths year, the Coyote Sprigs 2 plant
as curently owned by Avista Utilties and the Port Westward facilty as being developed by Portland
General. We also employed the DCF method to value these comparable facilties. As a final valuation
reference check, Thorndike Landig reviewed tranaction market activity to identify simlar assets that
have transacted and to assess the value of these assets and whether they were comparble to the
contemplated transaction for the TolL. We recognze that this tranaction - a toll versus an asset
transaction - is fudamentally different than these comparables but these comparables served as an
additional reference for market value,
Based on these four differing, yet complimentar, valuation perspectives Thorndike Landing has found
that the Toll provides positive value to Avista and its customers (see Results and Conclusions section)
and the value of the Lancaster facilty appears consistent with-if not greater than-the value of other
Lancaster Valuation Page i Thorndike Landing, LLC
Exhibit No,4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 4 of 31
resources in that market.
Thorndike Landing also pedormed a review of Avista's analytical process and methodology to identify
any potential shortcomings or areas that may be improved to provide it with a better, more
comprehensive analytical process. Based on this review, we have found that Avista's analytical process
and methodology is a very contemporar approach to analyzing resources, We have found that Avista's
analytical process is sound and even surpasses processes used by many of their peers across the
industr.
As part of this review, Thorndike Landing also reviewed Avista's analysis of the Toll to ensure both the
methodology was appropriate and that the quality of the anlytics was reasonable, We identified two
areas in the Toll-specific analysis that waranted attention, but found neither of concern or to have a
material impact on the overall results.
Lancaster Valuation Pagt: 2 Thorndike Landing, LLC
Exhibit No.4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 5 of 31
Ob' ective and Pur ose
Thorndike Landing was retained by Avista to perform an independent valuation of the Toll associated
with the Lancaster generating facility curently owned by a third par. Avista has the opportnity to
add this toll to the portfolio of its regulated utility. Avista Utilties has performed its own valuation of
the TolL. The determnation of this independent valuation performed by Thorndike Landing, as set fort
in this report, wil be relied upon by Avista in connection with its efforts to add the Toll to its regulated
portolio.
Thorndie Landing has performed several tasks to aid in determning the value of the Toll to Avista
and its customers. First, we have reviewed information and data provided to us by A vista regarding the
Facilty, its financial parameters, its operations, and the Toll itself. Next, we have used the DCF
approach to assess the value of the Toll and we have also performed a valuation of the Facilty itself for
comparison puroses. Next, we have identified transaction values for other generating assets that have
sold in this market to establish a set of maket comparables and their values for comparison puroses.
Lastly, we have taken this comparables assessment fuer than is customarly done in these situations
and have performed valuations of relevant generating assets that have been constructed or have
transacted recently in this maket. Next, we reviewed Avista's analytical approach to determine if there
were any deficiencies and any areas that could be improved. Lastly, we prepared this report describing
the salient assumptions used, our approach and our findings regarding whether the Toll is of suffcient
value to Avista and its customers to wart being included in its regulated generating portfolio.
For this effort, Avista has provided Thorndike Landing with specific instructions regarding this effort:
(a) we are to use the analytical methods curently and customarily used in the market for valuation
puroses; (b) we are to value the Toll as an independent, third-par would value it; (c) we are to
remain independent at all times and are to use our best judgment regarding assumptions to be used; and
(d) when reviewing their analytical process we are to remain independent and are to offer all
constrctive feedback with the goal of improving this process in every way possible.
The remainder of this report describes the approach Thorndie Lading has used in determning the
value of the Toll, the salient assumptions used, our assessment of Avista's analytical process and our
results and conclusions.
Lancaster Valuation Page 3 Thorndike Landing, LLC
Exhibit No.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 6 of 31
Descri tion of Facil and Tollino A reement
The Facility is a 262 MW, gas fired combined cycle generation facilty located on a IS-acre site
approxiately 2.5 miles from Rathdr, Idao.
Table 1: Facility Charactenstics
Category Description
Location Rathdr, il
Capacity 262 megawatts
Priar fuel Gas
In-service date September 2001
Turbine manufactuer, tye GE7FA
Employees 20
Average net heat rate (2006)6,925 btuWh
Average equivalent availabilty (2006)92.9%
Power offe was originlly contracted to Avista Energy under a long-term tollig agreement (the
"Toll"). On July 1,2007 the Toll was assigned to an unelated thd par ("Seller" or "Lessor"). The Toll
wil become available to Avista Utilities, Inc. as of Janua 1,2010, or the "Valuation Date" for puroses
of our analysis.
Under the terms of the Toll, Avista Utilities ("Purchaer" or "Lessee") would have cal rights to energy
and capacity from the Facilty over the term of the agreement. As consideration for those rights, Avista
would pay the Seller a capacity charge and an energy charge as described in more detail below. Avista
would also remain responsible for gas supply, as well as electrc tranmission, Specific key term of the
tollng agreement include the following:
. Term: For puroses of our analysis, the staring date will be Janua 1,2010. The Toll expires
on October 31,2026.
. Capacity:
a Includes both "standad" capacity (baseload) and "supplemental" capacity (duct-fired)
. Payments:
a Capacity payment comprised of a capital charge and an O&M charge
. Capital charge: $4.352/kW -month in 1998 dollars, escalated at 1 % per year
Lancaster Valuation Pag.:4 Thorndike Landing, LLC
Exhibit No.4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 7 of31
. Operations and Maintenance (O&M) payment: $1.302IkW-month in 1998
dollar, escalated with a specified anua inflation measur thereafter
a Energy charge: $1.463 per MW in 1998 dollars, escalated with a specified anual
infation measure thereafter
a Star payment: $6,000 per sta for sta greater than 100 in a contract year.
. Other key term:
a Avaiabilty: Seller has a 97% availabilty target. Capacity payments related to periods
with realized availability less than 97% are reduced on a pro rata basis.
a Guaranteed heat rate was specified
The facilty contiues to be maaged under an O&M agreement with a thrd par. Ths agreement is
effective though September 2026.
Electrc transmission service is available though an agreement with Bonneville Power Administration
("BPA"). Key terms of this agreement are as follows:
. Term: July 1,2001 though June 30, 2026
. Point of delivery: John Day
. Pricing is consistent with that under the published BP A taff
. Transmission rights under the BP A agreement will tranfer to Avista Utilities Januar 1, 2010
Lancaster Valuation Page 5 Thorndike Landing, LLC
Exhibit NO.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 8 of 31
Thorndike Landin A roach
Ths section of the report describes the anlytical methods used to perform the varous valuations and
assessments conducted for this effort. The results of these analyses are presented in the Results and
Conclusions section of this report.
For this effort, we looked at severa different perspectives to derive a valuation for the traction
contemplated by Avista. Firt, we perormed a valuation of the Toll, tag into consideration all of the
key factors for that agreement. Second, we performed a valuation of the Facility under a purchase
scenaro. Next, we identified comparable assets in the Nortwest market and performed valuations of
those to get a sense as to what the values of those assets are. Lastly, we reviewed comparble tranactions
in the generation market and assessed the average values of those deals in the most appropriate maet.
Valuation ofthe Toll
In order to value the Toll, Thorndie Landig developed a discounted cash flow ("DCF") analysis of the
Lancaster facilty from the perspective of the Lessee under the ters of the toll. For puroses of our
valuation, the applicable valuation date is Januar 1,2010 ("Valuation Date''). As noted above, this is the
date at which Avista would expect to assume the rights and obligations under the tolL. The DCF analysis
is based on projections of the Lessee's forecasted anual after-ta free cash flows though the end of the
lease term, discounted at Avista's after-ta weighted average cost of capitaL. The cash flows accruing to
or paid by the Lessee would include all margins from sales of energy and capacity, lease payments, and
operating costs expected to be borne by the Lessee (and not the Lessor/Seller) under the term of the toll.
Our approach to forecasting the components of free cash flows and the related key assumptions are
discussed below,
General assumptions
. Valuation Date: January 1,2010
. Term of analysis: Januar 1,2010 - October 31,2026
. Capacity: Average anua plant capacity was assumed to be 262 MW, of which 25 MW was
assumed to be related to duct-fied peakg capacity. The total capacity was based on the average
(sumer / winter) capacity as reported by the Energy Inormation Admnistrtion ("EIA")
. Forced outage rate: 5%
Lancaster Valuation 'Pagc 6 Thorndike Landing, LLC
Exhibit No.4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 9 of 31
Energy margins and capacity revenues
Energy magins and capacity revenues were forecasted using Thorndike Landing's proprieta Integrted
Energy and Capacity Model ("IECM"), a production cost model which dispatches regional resources
(including the Facilty) against forecasted hourly load on an economic basis to derive market clearg
energy pricing and unt dispatch / margin. The IECM alo derives regional capacity values based on: (a)
supply and demad dynamics, (b) new build economics, and (c) derved energy margins. The Facilty
revenues and magis derived from IECM ar based on merchant (uncontrcted) dispatch and are net of
varable production costs including:
. Delivered gas costs including costs associated with gas commodity, delivery costs (excludig
fied gas trsporttion), gas trsporttion losses, fuel taes (if any), etc.
. S02 costs
. C02 costs
Note that our analysis included thee pricing scenaos for puroses of valuing the toll: base, low and
high, See additional discussion ofIECM methodology, assumptions and results in the Appendi.
Toll paments
Payments made under the Toll for capacity, energy and sta charges were based on the term as described
in the Description of the Facilty and Tolling Agreement section above. Additionay, escalation rates
used for payments under the toll were as follows:
. Capita charge: 1 % per the term of the agreement
. O&M and Energy charges:
a From 1998 to 2007: 2.4%. This was derived from our review of the associated
referenced Gross Domestic Product Implicit Prce Deflator.
a From 2007 though 2026: 2.5%
Gas costs
Modeled gas costs include both fixed and varable components, as requested by Avista gas personnel on
staff, to derive our forecasts for both these fixed and varable components.
. Fixed gas trsportation costs: According to Avista, gas for the Facilty is sourced from 2
delivery points-Alberta and Malin. As such, there are gas tranporttion contrcts for both of
these paths.
a From Albert:
. 27,841 GJ per day though October 31, 2017
Lancaster Valuation Page 7 Thorndike Landing, LLC
Exibit No.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 10 of 31
· Price: $.1 87 per mmbtu (in 2007 dollar)
a From Malin:
· 26,388 GJ per day though October 31, 2017
· Price: $.26 per mmbtu (2007 $)
Note that the tota gas tranportation exceeds the total gas need of the plant when operating at
ful capacity by approxiately 20% (approxiately $550,000 in 2007). It appears that the
additional capacity was obtained to allow the Facilty to arbitrage between the gas supply points.
Note that we did not include the cost for the excess gas supply, which was assumed to have been
remaketed or otherwise utilized for utility service at cost. We also did not include the offsetting
the arbitrge opportty between Albert and Mal hubs in our anlysis, In order to estimte
the impact of ths arbitrage opportty, we anlyzed gas data for the Mal and Albert hubs
from the prior 3 years. Given the gas tranportation litations for both hubs (as shown above)
and assumng perfect optimzation of pricing between the hubs, the blended gas price for
Lancaster would be approximately $.25/mmbtu (1.9%) lower than pricing at the Albert hub
alone. Furer, note that it would also be possible for Avista to derive additional value from
monetizig gas trporttion for periods in which the Facilty is down either for maitenance or
for economic reasons. If the gas tranporttion necessar to meet daly gas requirements could be
remarketed or otherwse utilized at cost, ths would represent an additional value of
approximately $9,000 pre-ta per day ($6,000 after-ta).
. Varable gas costs: (these are included in the energy margins modeled by the IECM)
a Gas commodity: Priced at Albert hub
a Deliver costs:
· Commodity fee: $.01 per mmbtu
· Fuel tranporttion fee: 2.03%
a Gas taes: None for the Lancaster Facilty. Unle the state of Washigton, Idao does
not curently have such a ta. For those comparble facilties located in the state of
Washington, a fuel tax of 3.852% was applied. Based on our analysis, the impact of a
. 3.852% fuel ta on the value of the Toll would be approxiately $26 millon.
Both fixed and variable costs were escalated at an anua rate of 1,5%
Electric transmission
The Facility curently taes electrc transmission services under a services agreement with BP A, under the
BPA transmission tarff. Refer to taff rates under the Description of Facility and Tolling Agreement
Lancaster Valuation Page 8 Thorndike Landing! LLC
Exhibit NO.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 11 of 31
above. However, Avista estimates that it could diectly interconnect the Facilty to its own system at a
total cost of approxitely $3 millon, thereby negating the need to tae service though BP A. For
puroses of our analysis, we have assumed that A vista penorms the interconnection work. The
tranmission agrement with BP A in this case wil be utilzed in other ways, We have assumed that a
porton (75%) of the electrc trmission capacity under the BPA agreement is remaketed at cost-or
otherwise used for utilty load service-and therefore not bome by the Facilty / Lessee. We note that the
utility's customer avoid BPA's charge for electrc losses of 1.9% once the facilty is interconnected
directly with Avista's system. As compared to an otherwise identical unt that would incur this cost, the
Facility reflects higher margins (1.9% of market clearng prices) in all hours when both facilties would be
dispatched, In addition, the Facilty would also be dispatched in additional (lower margin) hour relative
to its peer when it is at-or close to-the margin. Based on our analysis, the value of a 1.9% loss factor
on the value of the Toll is approxiately $12.5 millon.
Tr¡ Depreciation
Capital expenditues-specificaly the interconnection cost-were depreciated based on 20-year
MACRS.
Taxes
Combined state and federal ta rate was assumed to be 39.94%
Discount rate
After-ta free cash flows were discounted based on Avista's after-ta weighted average cost of capital of
7.41%.
Costs Associated with Imputed Debt
Rating agencies generally consider long-term power purchase contracts to be equivalent in some regards
to long-term debt. Ai such, they impute a value for debt that they apply to the power purchaser's balance
sheet. This imputed debt places downward pressure on the credit quality of the "borrower" and upward
pressure on financing costs. In order to tae into account the costs associated with the imputed debt, we
included a cost of equity that would be necessar to neutrlize the reduction in credit qualty from the
imputed debt.
Rating agencies have differig methodologies for imputig debt. For puroses of our analysis, we have
utilzed the process employed by Stadad & Poor's, The calculation begins with the determation of the
Lancaster Valuation Page 9 Thorndike Landing, LLC
Exhibit No,4
Case No. AVU-E-09-01
R. Storra, Avista
Schedule 4, Page 12 of 31
fixed obligations associated with the demand payment. This payment stream is then discounted at the
utilty's average cost of debt. A risk factor is then applied to the net present value of the stream of fied
obligations to arve at the amount of imputed debt.
The incremental cost applied to the Toll is based on the amount of equity that would need to be issued to
maintai the utilty's existing capital strctue. The anual cost is then based on the utilty's cost of
equity applied to the calculted additional equity required.
Valuation of the Lancaster Facilty
As a reference check, we also performed a valuation of the Facilty as of the Valuation Date from the
perspective of the owner without the toll-in other words, the value of the Facilty assumng merchant
dispatch. For this effort, we used the discounted cash flow ("DCF") method. The approach and
assumptions used for this analysis were largely consistent with those of the analysis of the Toll above,
Key differences include the following:
. Forecastig period / useful life, The facilty was assumed to have a useful life of 35 year
(though 2036). The value of the cash flows accrug to the project over its useful life were
calculted as follows:
a Jan. 1,2010 - Dec. 31, 2030: Anual cash flows modeled though the use of IECM
forecasting modeL.
a Jan. 1,2031 - Dec, 31,2036 (end of useful life): Anual free cas flows assumed to be
consistent with IECM terml year (2030).
a Residual value (post-2036): Assumed to be $0. Implicitly, the value of the site and
associated scrap value of the equipment, etc. are assumed to be equal to the cost of
dismatlement and any necessar site remediation.
. Tollng payments: By defition, excluded from this anlysis
. O&M, including Major Maintenance - Based on estimated actual charges expected to be incured
for the Facility (not prescribed O&M fee per the term of the Toll).
. Propert taes and insurance - Projected costs were included. In accordace with the term of
the Toll, these costs had previously been excluded from the Toll valuation,
. Tax depreciation: Based on both the historical constrction cost of the Facilty as well as
additional capita (interconnection, major maitenance). The implicit assumption is that
ownership of the Facility would be tranferred via a purchase of the thd par's equity (e.g., a
stock purchase) and not a purchase of the underlying assets themselves (e.g., an asset purchase),
Lancaster Valuation Page 10 Thorndike Landiiig, LLC
Exhibit No,4
Case No. AVU-E-09-01
R. Storm, Avista
Schedule 4, Page 130f31
Valuation of Select Assets Transacted in Market
Thorndike Landig performed a valuation analysis for a few selected assets that compete against the
Facility within the local or regional maketplace. Specifically, we valued the Goldendae facility as
purchased by Puget Sound Energy earlier ths year, the Coyote Sprigs 2 as owned by Avista Utilities and
the Port Westward facilty as being developed by Portland General. Given that these assets were not for
sale, ths exercise was intended to merely assess what the potential values of these assets would be if they
were to tract and, hence, be available to Avista instead of the Toll.
For ths assessment, we used the same DCF approach and general assumptions as outlined above.
Transaction Market Comparables
As a final reference check, we have also reviewed tranaction market activity to identifY similar assets
that have tracted and to assess the value of these assets and whether they were comparble to the
contemplated transaction for the Toll. We recognze that this transaction - a toll versus an asset
tranaction - is fundamentaly different than these comparables; thus while ths information has been
reviewed as yet another reference point it has not been relied upon extensively to determine our
conclusions. There are several factors to consider when reviewing and applying comparble tranactions
as a reference for a parcular transaction: (a) similar fuel and technology tye facilties; (b) salient
attbutes of the situation, such as whether the asset has an off-tae agreement for the output, etc., if
known; (c) geography and, specifically, the market the asset competes within; and (d) the period in which
the tranaction was executed.
For the first factor, it is importt to filter the information and data and isolate those tranactions that were
for assets of a similar fuel and technology tye; in this case gas-fied combined-cycle facilties.
Dependig on the number of transactions available for comparson puioses, occasionally portfolios of
assets can also be applied if that portfolio is largely of a simlar fuel and technology tye. There is no set
parameter or theshold of how many assets in the portolio are simlar or what percentage of the
portfolio's capacity is simlar, but it is generally acceptable to use a portolio that is nearly all of similar
fuel and technology tye. Conversely, if there are a suffcient number of single-asset trsactions those
are generally preferred as a comparson set.
The second factor to consider is whether there exists any extenuating circumstances or attbutes of a
given transaction, The clearest example would be if an asset had an off-take agreement for a porton or all
of its output. Depending on the prices and term of that agreement (i.e" higher-than-maket pricing vs.
Lancaster Valuation Page 11 Thorndike Landing, LLC
Exhibit NO.4
Case No. AVU-E-09-01
R. Storm, Avista
Schedule 4, Page 14 of 31
lower-than-market pricing), the value of the traction can be skewed. Specifically, if an asset had an
off-tae agreement that had pricing that was signficantly grater than curent maket views, the value of
that asset (including the contract) to a buyer would be greater than if it were a merchant facilty. These
detas are not always known,
The third factor to consider when selecting a comparable set of tractions is geography. This
geographical parameter is most easily identified by power pool or maket (e,g., PJM, ERCOT, etc.). In
this case, the specific market is less defied as the Toll is with a project in WECC which is a large control
area versus a tightly-manged iso as in other makets.
The four factor to consider when selecting a comparable set of tranactions is the timg or era of the
tranactions to be included in the comparson set. Again, ths is largely drven by the number of
tranactions available and there is no specific rule or theshold to use, It is common to use a term of
between 18 and 24 month prior to the assessment if there is sufcient data and tractions available.
This period is based on the premise that fudaenta drvers to trsactions (i.e., fuel prices and trends,
credit markets, etc.) remain consistent for a period of tie but do eventually change. As these
fudamentals change, so do the resulting trsaction activity and the values in ths maket. Lastly, if the
number of tractions or data for those tranactions is limited, it is common to use a period of up to thee
years to gauge comparable tractions,
Durng the past few yeas there have been several transactions that would be considered comparable to
this proposed deal; again, using the general aforementioned criteria of simlar tyes of plant, market, etc.
Below is a sumar of the publicly-available trsactions that have occured in this market durg this
three year period.
Date Tola/Prlce Value
Announced Ast(S)Slates)Fuel Typ MWXfe Sel/er Buyer (MM$)($
12117/2004 Coyte Sptings 2 (50%)OR Gas CC 140 Mirant Avisla $63 $46
511812005 La Paloma CA Gas CC 1022 Citibank lender cosoum Complete Enery Parters $610 $597
511912005 EI Dordo (50%)NV Gas CC 240 Reliant SiBl Pacic Resource $132 $550
611/2005 Silverhaw NV Gas CC 427.5 Pinnacle West Nevada Power $208 $487
51111206 Griffth AZ Gas CC 300 PPL LSPowr $115 $383
2112007 Goldendale WA Gas CC 250 Calpine Puget Sound Ener $120 $480
911312007 Klamath Falls cogeneration OR Gas CCcoen 506 City of Klamath Falls PPM $290 $573
As shown, durng this period, there have been seven tractions averaging $533/kW. Durg this same
period, there have been approximately 25 similar tractions executed thoughout the remainder of the
U.S., resulting in an average value of $465/kW. The relatively small divergence in these numbers is
drven by several factors, including location/market, whether there exists an off-tae agreement and, if so,
what term exists for the contract, each specific buyer's view to commodity prices, cost of capita, etc,
Lancaster Valuation Page 12 Thorndike Landing, LLC
Exhibit No.4
Case No. AVU-E-09-01
R. Storr, Avista
Schedule 4, Page 15 of 31
It may be more appropriate to utilze a shorter period of time to assess comparable transactions, given that
there has been a fairly signficant change in several factors durg the past thee years in this sector;
namely finacing costs and commodity costs. The data set gets much smaller durg ths time and
includes just the Puget acquisition of Goldendale and the PPM acquisition of the Klamath Falls
cogeneration facilty. The results of ths period, however, remain very consistent with that of the thee
year period, Specifically, the average value of these tractions in this maket is $542/kW as compared
to $503/kW for the remaider of the U.S. durng that same one-year period.
Other Considerations (Toll versus Ownership)
We have derived values for the Toll, the Facilty and other indicators as described above. As mentioned,
the Toll-although it conveys many of the rights and obligations of ownership-remain fudaentay
different from actul ownership. Some of the priar considerations of a toll versus ownership include:
. Term of "ownership": Beyond the term of the Toll, the Lessee has no rights of ownership and the
full value of any "termnal" or "residual" value revert back to the Lessor/Seller.
. Operational risk: Under the provisions of the Toll, the Lessor/Seller has guaranteed a stipulated
forced outage rate (approximately 3.0%), as well as a realized heat rate. Any costs associated
with not meeting the operationa pareters are borne entiely by the Lessor/Seller, For instace,
in the event of an extended forced outage, the Lessee / Purchaser is entitled to replacement power
(as defied) at the Lessor/Seller's cost, thereby mitigating such risk under a Toll arangement.
. Limted risk of cost escalation: Cost escalation under the term of the Toll is lited to i %
anualy for the capital charge and to an inflationar index for the O&M and energy rates, AB
such, there is little risk for cost overr associated with regional or plant-specific impacts such
as (local) labor costs, propert taes, insurance, etc, The Lessor/Seller bears the risk of such cost
escalation in excess of economy-wide increases.
. Intial capital outlays: For purposes of our analysis, we derived the value of assuming the Toll as
of the Valuation Date. We also determined the total value of certin facilities as of the Valuation
Date, Note, however, in the case of the latter, we expressly excluded any capital costs associated
with owners' acquisition of the facilties (e,g., constrction costs, acquisition costs). Such intial
capital outlays would be required to be made in the case of tag ownership but not in the case
of the Toll since the tolling payments themselves is consideration for the use of the Facilty over
the Toll term.
Lancaster Valuation Page 13 Thorndike Landing; LLC
Exhibit NO.4
Case No. AVU-E-09-Q1
R. Storro, Avista
Schedule 4, Page 16 of 31
Review of Avista Analvtical Process
Thorndike Landing has performed a review of Avista's analytical process and methodology to identify
any potential shortcomings or areas that may be improved to provide it with a better, more
comprehensive analytical process. Our review consisted of a meeting and discussion session to review
the overall methodology, ways in which they addressed contemporar issues (e,g., emissions, etc,), and
a discussion surounding the modeling platform and softare used and how they interacted thoughout
the analytical process. We did not review the assumptions used by Avista in their analysis, other than to
ensure that they had used curent perspectives when deriving their assumptions. This section reviews
Avista's curent analytical approach, as well as the results of our review.
Overview of A vista Analytical Approach
Avista utilizes a dynamic and interactive modeling approach to resource planing and analyzing new
resources for its system. This approach considers and analyzes both the Avista system, as well as its
interaction with the broader Western Electrcity Coordinating Council ("WECC"), analyzes and
determnes the risk associated with varous scenaros and resources, and determes the optimal
resource portfolio for its system based on power supply expenses, incremental capital costs and
operating risk.
To accomplish this level of analytical rigor, Avista employs several distinct modeling platforms. First,
it uses AURORAp to perform the market modeling, generate the capacity expansion plans and
forecast electrc maket prices. Avista curently plans to a capacity plang taget. Specifically, the
scenaros within AURORAp introduce resources into the system to cover adverse or short load
conditions; in essence, addig resources to exceed average needs. This philosophy ensures that
resources are in the system and ready and available to meet system requiements in all but the most
extreme conditions. Ths approach reflects sound utility planng in the market today, especially in
WECC where many paricipants are still feeling the rafications of the power crisis a few short years
ago. The generic resources that the model calls upon for the capacity expanions include gas-fired
combined-cycle combustion turbines, single-cycle combustion turbines, pulverized coal plants,
integrated gasification combined-cycle coal plants with and without sequestration and wind tubines.
This wide array of resources provides Avista's plang process with significant diversity when
assessing varous scenaros and the advantages and disadvantages of each with respect to both cost and
risk.
Lancaster Valuation Page 14 Thorndike Landing, LLC
Exhibit NO.4
Case No, AVU-E..9-01
R. Storro, Avista
Schedule 4, Page 17 of 31
A vista also uses AURORAxmp for risk assessment by pedorming stochastic analyses to determine the
volatility of prices and potential resource valuations. Several salient assumptions are modeled
stochastically, including hydroelectrc conditions, natural gas prices, load conditions, wind production,
forced outages of the facilities and the cost of emissions compliance. The Avista team reviews and
determines the input assumptions for these and other variables into AURORAp and reviews the
output of this model to ensure the results of logical and correct. By performing this stochastic analysis,
A vista incorporates a measure of volatilty for the projected electrcity market prices and the resulting
resource values to A vista and its customers.
A vista also uses another model, The Preferred Resource Strtegy Model, or PRiSM, which is a
proprietar model developed by Avista to aid it in selecting its preferred resource strategy. PRiSM
quantifies the cost and risk associated with Avista's curent resource portolio and that of new potential
resource additions. The PRiSM model uses a linear programng approach. Ths method enables
complex decision-makng in situtions or processes that often have one- or multi-diensional
objectives, such as resource planng for both cost and reliability measures and goals. This model relies
upon several factors to arve at an optial resource portfolio, including the base case assumptions as
used in AURORAmp, Avista load requirements for capacity and energy, capital costs associated with
new resources, local transmission costs, and the market and cost values of each new and existing
resource as modeled in AURORAmp. PRiSM determnes the preferred resource strategy based on
several resource and portfolio metrcs, including present value of the expected power expenses,
incremental capital costs and operating risk to A vista.
Results of Thorndike Review
Thorndike Landing has reviewed Avista's analytical methodology and has found that Avista's
analytical process and methodology is a very contemporar approach to analyzing resources. In fact,
the utilty industr in general has been slow, as compared to other industres, to adopt risk analysis into
its process and it wasn't until the power and sector crises of 2001-02 that even some utilties began to
incorporate risk into their processes. Today, we find that many utilties do factor risk analyses into their
processes, but many stil do not. Additionally, Avista's process is also grounded on sound resource
plannng using multiple scenarios and a robust vs. static process though which the company is able to
assess multiple scenaros and resource portfolios, not just a single resource in isolation. For these
reasons, we have found that Avista's analytical process is sound and even surasses processes used by
many of their peers across the industry. Therefore, we have not identified any area or aspect of its
Lancaster Valuation Page 15 Thorndike Landing, LLC
Exhibit No.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 18 of 31
process generally for which we would suggest modification at this time. We do recommend, however,
that A vista continue to review its methodology as it has for the past several years as analytical
approaches continue to evolve with new technques and information and Avista needs to maintain a
curent process given the challenges that inevitably lie ahead in our industr.
With respect to the analysis of the Lancaster Toll specifically, we likewise found the approach to be
appropriate. However, we did identify items that waranted fuer consideration:
. Exclusion of gas transportation costs: We noted that gas transportation costs had been
excluded from Avista's preliminar analysis of the Toll despite the fact that Avista would incur
such costs after assumption of the Toll. Based on our discussions with Avista personnel, it
appears that the internal assessment of gas transportation costs had not been completed as of
the date of the preliminary analysis. We noted that these costs were excluded for both the Toll
and the "off system ce" comparative analysis. As a result, any comparative results would only
be impacted by any differences in gas transportation costs. Likewise, any upside from sourcing
from dual gas hubs was also excluded from the A vista analysis.
. Exclusion of costs associated with imputed debt: Due to the fact that rating agencies impute
debt associated with power purchase agreements such as the Toll, there is a cost associated
with entering into such agrements. In connection with our analysis, we calculated such cost as
described in the Valuation of the Toll section above. We noted that Avista did not include such
costs in their analysis.
The items listed above do impact absolute values but did not have a material impact on relative values
or overall conclusions, We noted no other material issues with Avista's process generally or its
analysis of the Lancaster Toll specifically.
Lancaster Valuation Page 16 Thorndike Landing, LLC
Exhibit No.4
Case No. AVU-E-D9-01
R. Storr, Avista
Schedule 4, Page 19 of 31
Results and Conclusions
Base results
Based on the aforementioned analyses, reviews and assessments, Thorndike Landing has determned
the following base case results for the Toll, the Lancaster Facilty and other comparative facilties.
Table 2: Summary of Toll Valuation Results
Value
Description $OOOs $/kW
NPV excluding imputed debt $40,500 $155
Cost of imputed debt (24,000)í2
NPV including imputed debt 16,500 64
The valuation of the Lancaster Facilty is shown in Table 3 below.
Table 3: Sumary of Lancaster Facility Ownership Valuation Results
Value
Description SOOOs $/kW
The valuation of the other similar combined cycle facilties in the region is shown in Table 4 below.
Table 4: Summary of Comparable Combined Cycle Ownership Valuation Results
Value
Approach / Asset $OOOs $/kW
DCF Analysis
Coyote Springs 2 169,500 652
Port Westward 236,000 528
Goldendale 84,000 365
Transaction Comps Analysis nJa 530
Lancaster Valuation Page 17 Thorndike Landing, LLC
Exhibit No,4
Case No. AVU-E-09-01
R. Storro. Avista
Schedule 4, Page 20 of 31
These values do not provide a direct comparison of each plant's (net) value to Avista. Instead, the
values represent the value to A vista if it could assume the rights and obligations of the plant's curent
owner at no cost. For example, if the Goldendale plant were made available to Avista at no cost its
value would be $84 milion-or, in other words, A vista could pay up to $84 millon for the plant. In
the case of the Lancaster Toll, given our assumptions regarding the specific financial obligations and
benefits as previously described in this report, the contract available to Avista is wort $16.5 millon
more than its costs. As such, A vista could pay up to $16.5 millon for the contract and it would stil
represent a positive NPV (retu) investment.
Sensitivities
As discussed above, we also ran high and low cases for the value of the Toll and for the Facilty. These
scenaros are derived by assuming distinct market drvers that are in the range of potential futue
market developments, As the subject of this report is a combined-cycle (cq related product we
focused on the two drivers that would produce relevant upside or downside to these tyes of plants. The
core drvers we varied were (1) a doubling of assumed futue CO2 prices, and (2) the introduction of an
additional 5,000 MW of combined-cycle capacity thoughout WECC. Higher CO2 prices result in a
substantial relative benefit to CC's, while the CC overbuild simulated for the low case leads to a
merchant margin depression. The results are as follows:
Table 5: Summary of Results
Value - $000 ($/kW)
Description Toll Facilty
Base Case $16,500 ($64)$177,500 ($677)
Low Case 500 (2)155,500 (594)
High Case 20,500 (78)181,500 (692)
We also ran sensitivities around Avista's abilty to re-market the excess electrc transmission under the
BPA contract that would be available after completion of the interconnection to Avista's system. For
our base case values, we have assumed that 75% of the BPA transmission costs would be recouped
though remarketing. However, given the materiality of the costs, we ran sensitivities based on the
percentage of costs that would be recovered though thd part sales,
Lancaster Valuation Page 18 Thorndike Landing, LLC
Exhibit No.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 21 of 31
Table 6: Lancaster Base Case Toll Values As a Function of BPA Transmission Costs Remarketed
% of Costs Value Value
Remarketed $OOOs S/kW
0%(7,500)(29)
25%500 2
33%3,000 12
50%8,500 33
67%13,750 52
75%16,500 64
100%24,750 94
Conclusion
In conclusion, Thorndike Landing believes that the transaction for the Toll is reasonable and that the
value Avista would remit for the Toll is reasonable and would result in a net benefit to Avista and its
customers. Furer, based on our anysis and assumptions, the value of the Lancaster Facilty appears
to be greater than that of other recently constrcted or tranacted facilties in the region. This greater
value appears to be primarly drven by one or more of the following:
. Lower electrc transmission costs
. Lower gas tranporttion costs
. Lower gas taes (the state ofIdao has no fuel tax)
. Dual sourcing of fuel (Albertalin vs. Sumas)
Lancaster Valuation Page 19 Thorndike Landing, LLC
Exhibit No.4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 22 of 31
A endix A: Descri tion of IECM
Thorndike Landing uses its proprietar model, the Integrated Energy Capacity Model ("IECM"). The
IECM is an economic forecasting tool that derives capacity and energy forecasts by combining a set of
sophisticated market simulation algoriths into one integrated piece of softare. Unlike most other
standard forecasting software, capacity markets are integrated into the forecast rather than being
modeled as an add-on, which aids greatly with the validity of retu requirement calculations needed to
add futue resources to the modeL.
The model works in power markets that follow the rules of economic dispatch in the energy markets
and that have a formal capacity market, a regulatory resere margin requiement, or a bilaterally traded
capacity maket. This makes the IECM useful in most curent domestic power markets.
Obvious Advantages of Integration
The real market linkage between energy and capacity markets is undisputed and is most relevant for the
very important new build and retirement asset decisions (i.e" even markets with low spark spread
forecasts and little incentive from an energy market perspective to intall new plants or keep aging unts
operating wil, in real life, encourage retirement delays or even new builds). The IECM allows the
forecaster to easily integrate assumptions and results in both markets to arrve at conclusions to
typically difficult questions, such as: "Does the capacity market in my region lead to new combustion
turbines or does it put a new combined-cycle or coal plant into my new build assumption? Is there a
difference under a carbon regime?"
Methodology
For the energy module, the IECM uses an hourly chronological merit order dispatch approach to arve
at a 20 year energy price forecast. These 175,000 price points are one part of the economic assessment
for new and old resources. For the capacity module, the model applies the appropriate capacity market
constrct, e.g. a demand cure or a bilaterally trded market, to the same resources used in the energy
module to derive an annual capacity market price point for the same 20 year period, Both the 175,000
energy and the 20 capacity price points enter the retirement and new build assumptions that then circle
back into the two forecasts in an iterative fashion,
Lancaster Valuation Page :W Thorndike Landing, LLC
Exhibit No.4
Case No. AVU-E-09-01
R. Storr, Avista
Schedule 4, Page 23 of 31
Emissions: Pollutants and Carbon Dioxide
The cost of emission allowances is an important adder to the marginal cost of fossil generators. In the
case of CO2, there is even uncertainty around such basic rules as allocation mechanisms and price caps.
The IECM incorporates our standard forecasts for emission allowances and allows for scenaros around
fuel and emission market dislocations.
Extrinsic Value Drivers
Models such as the IECM that use a fudaental approach to forecast energy prices typically exhibit a
weakness when it comes to estimating the energy margin from plants that can be dispatched flexibly,
based on market conditions. E.g., the average daily price on the same weekday in the same month may
be very similar in the fudamental dispatch model, as it is likely based on similar load and fuel price
conditions, In real markets, there are many parameters that shift the daily prices up or down, While the
average wil be roughly the same, this introduction of volatilty into the pricing enhances the energy
margins of the above mentioned flexible plants. In WECC, flexible plants, such as combustion tubines
(CT) and combined-cycle (CC) plants are important as they form an importt par of the new build
economics, The model, if it did not include volatilty in its output, would understate CC and CT retu,
with the importnt impact that it would delay new build decisions, leading to exaggerated market
heatrte forecasts. The IECM therefore, as a final step, after fudamental intrnsic prices are derived,
introduces volatilty into the generated pricing, not changing the absolute pricing levels, but introducing
just enough volatility, on a simple mean-reverting basis, to result in appropriate retus for the flexible
plants.
Key Assumptions and Results for the Various Scenarios
Note that gas prices refer to the AECO, and power prices to the Mid-C pricing points.
Co ..ur n.2011 2012 201.201S 201.2017 2011 201.
S6.96M BTU S7.1OJMUBTU$7 S7.38JM BTU $7.53M BTU S7.68U BTU $7.84M BTU $7.99M BTU $8.151M BTU
son $9 S9 $'0I $,3f $,M $19./$22
son $'M $'"$20n $26 S3 $3 ..,-,-'00%,-,-,-
Ie 1651 m 8760 I....05 ....457 9572......9116 9247 .36 .....m 9.824
.,54 9,574 .,59 9,835 10.114 10,452 10174 11017
Lancaster Valuation Page 21 Thorndike Landing, LLC
Exhibit No.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 24 of 31
A endix B: Conditions and Assum tions
This report developed by Thorndike Landing shall be received and accepted with the accompanying
limiting conditions and assumptions:
)i This report has been prepared solely for the puroses stated and should not be used for any
other purose. The use and distribution of this report and the conclusions contained herein are
limted as stated in the report and the related engagement letter.
)i Our analysis: (i) assumes that as of the date of ths report the Facilty and its assets wil
continue to operate as configued as a going concern; (ii) is based on the past and present
financial condition of the Facilty and its assets; and (ii) assumes that the Facilty had no
undisclosed real or contingent assets or liabilties, no unusual obligations or substantial
commitments, other than in the ordinar course of business, nor had any litigation pending or
theatened that would have a material effect on our analyses.
)i We have relied on information supplied by Avista without audit or verification. We have
assumed that all information furnished is complete, accurate, and reflects Avista's good faith
efforts to describe the statu and prospects of the Facilty at the date of this report from an
operating and a financial point of view. As par of this engagement we have relied upon
publicly-available data from recognzed sources of finncial information which have not been
verified in all cases. Nothing came to our attention to mae us believe that any of the
information provided by Avista was other than reasonable.
)i Any use of Avista's projections or forecasts in our anlysis does not constitute an examation
or compilation of prospective financial statements in accordance with stadads established by
the American Institute of Certfied Public Accountats ("AICPA"). We do not express an
opinion or any other form of assurance on the reasonableness of the underlying assumptions or
whether any of the prospective financial statements, if used, are presented in conformty with
AICPA presentation guidelines. Furher, there wil usually be differences between prospective
and actual results because events and circumstances frequently do not occur as expected and
these differences may be materiaL.
)i The terms of our engagement are such that we have no obligation to update this report or to
revise our assessment because of events and transactions occurng subsequent to the date of
this report.
)i We assume no responsibility for legal matters including interpretations of either the law or
contracts. We have made no investigation of legal title and have assumed that the owner(s)
claim(s) to propert are valid. We have given no consideration to liens or encumbrances except
as specifically stated, We assumed that all required licenses, permts, etc. are in full force and
effect, and we made no independent on-site tests to identify the presence of any potential
environmental risks. We assume no responsibilty for the acceptability of the valuation
approaches used in our report as legal evidence in any paricular cour or jursdiction. The
suitabilty of our report for any legal foru is a matter for the client and the client's legal
advisor to determne.
Lancaster Valuation Page 22 Thorndike Landing, LLC
Exhibit No.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 25 of 31
~ Neither Thorndie Landing, nor any individual associated with this report shall be required to
give testimony or appear in court or other legal proceedings unless specific arangements have
been made in advance.
~ We have not investigated the extent of any hazardous substances that may exist, as we are not
qualified to test for such substances or conditions. If the presence of such substances, such as
asbestos, urea formaldehyde foam insulation, or other hazardous substances or environmental
conditions may affect the valuation of the Facilty, the valuation was estimated predicated on
the assumption that there is no such condition on or in the propert or in such proximity thereto
that it would cause a loss in value. No responsibilty is assumed for any conditions, or for any
expertise or engineerig knowledge required to discover them.
~ We assume no liability whatsoever with respect to the condition of the Facilty or for hidden or
unapparent conditions, if any, of the subject propert, subsoil or strctues, and fuher assume
no liabilty or responsibilty whatsoever with respect to the correction of any defects which
many now exist or which may develop in the futue. Equipment components considered, if any,
were assumed to be adequate for the needs of the Project's improvements, and in good workig
condition, unless otherwise reported.
Lancaster Valuation Page 23 Thorndike Landing! LLC
Exhibit NO.4
Case No. AVU-E-09-01
R. Storm, Avista
Schedule 4, Page 26 of 31
A endix C: Lancaster Toll Forecasted Financials, Valuation
Lancaster Valuation Page 24 Thorndike Landingi LLC
Exhibit NO.4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 4, Page 27 of 31
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A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
Executive Summary
Avista Utilities plans to acquire the Power Purchase Agreement for the 275 MW Lancaster
Generating Facility ("Lancaster") combined cycle combustion tubine (CCCT), which is located
in the company's servce terrtory near Rathdr, Idaho. Acquisition of the Lancaster Power
Purchase Agreement is consistent with Avista's 2007 Integrated Resource Plan Preferred
Resource Strategy, which calls for a natual gas fired CCCT to meet base 10ad needs by 201 i.
The Lancaster CCCT Power Puchase Agreement acquisition was found to be cost-effective
compared to similar CCCT base load resources.
Background and Summary
In Februar 2007, Avista Utilties was informed ofthe possibilty to acquire the Power Purchase
Agreement (tollng) rights for Lancaster sometime between 2009 and 201 1. The Power Purchase
Agreement acquisition opportity presented itself durng Avista Corporation's negotiation for
the sale of Avista Energy.
In April 2007, the utility completed an initial assessment of the potential Lancaster Power
Purchase Agreement acquisition. A vista Utilties Resource Planng staff performed an analysis
based upon the 2007 Integrated Resource Plan (IR) models. It had been determined, as par of
the IRP process, that there was a need for energy and capacity within the relevant time frame as
evidenced by load and resource tabulations which showed an expected annual average energy
deficiency startng in 201 1. An analysis of the average Ql, Q3, and Q4 (no Q2) quarers
indicated deficits beginning in 2010. Capacity deficits stared at 146 MW in 2011 and grew into
the futue. Furhermore, guidance from the 2007 IR indicated 350 MW of natua 1 gas baseload
resource as part of the Preferred Resource Strategy (PRS) over the first 10 years of the plan
(2008-2017).
On April 17, 2007, A vista Corporation anounced an agreement with Coral Energy to sell A vista
Energy. As par of the agreement with Coral Energy, Avista Corporation would assume the
Lancaster Power Purchase Agreement beginning Januar 1,2010. The draft 2007 IR Preferred
Resource Strategy (PRS) that was presented to the Technical Advisory Committee members on
June 6, 2007 included a discussion of the Lancaster Power Puchase Agreement opportity and
its fit with the PRS.
The sale of A vista Energy to Coral became effective on July 1, 2007 thereby transferrg the
Lancaster Power Purchase Agreement to Avista Utilties on Januar 1,2010. In August 2007,
A vista Utilities contracted for an independent assessment of the Lancaster Power Purchase
Agreement relative to other utilty gas-fired options. Thorndike Landing, LLC completed the
study and assessment work in late October 2007. Thorndike Landing found the Lancaster Power
Purchase Agreement acquisition favorable relative to other natual gas-fired CCCT generation
options generally available to utilities in the Pacific Nortwest.
This white paper provides an overview of the Lancaster Power Purchase Agreement as well as
analysis and assessment documentation addressing the prudence criteria as articulated by the
Washington Utilities and Transporttion Commission (Eleventh Supplemental Order and the
Nineteenth Supplemental Order both in Docket No. UE-920433) and by the Idaho Public
Page 1
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2,2007
Exhibit No.4
Case No, AVU-E-09.01
R. Storm, Avista
Schedule 5, Page 1 of 14
A vista Utilities - Lancaster CCCT Power Puchase Agreement Acquisition
Utilities Commission (Order No. 28876 in Case No. A VU-E-Ol-11, dated October 12,2001, and
its Order No. 29130 in Case No. A VU-E-02-6, dated October 11,2002).
Lancaster - Overview of the Agreements
The 275 MW Lancaster CCCT entered into service in 2001. As a combined-cycle combustion
tubine, it is among the most effcient natual gas-fired plants in the Northwest. The plant is
located in the utility's service area, near Rathdr, Idaho. The Lancaster plant is configued
with as a 245 MW natual gas-fired CCCT with an additional 30 MW of duct firing capabilty.
In addition to the Lancaster plant Power Purchase Agreement rights, the company will receive
long-term natual gas transportation rights necessary to fuel the plant as well as long-term
electrc transmission rights for power off-take.
The following is a summary of each of the agreements:
1) The Lancaster Generating Plant and Power Purchase Agreement
The Lancaster plant Power Purchase Agreement is available to the company
January 1, 2010 though October 31, 2026. In exchange for payments outlined in
the Power Purchase Agreement agreement, the utility wil have the right to
dispatch the Lancaster plant. As such, the company is responsible to arange and
pay for natual gas fuel procurement and transportation to the Lancaster plant and
is entitled to the entire plant electric capacity and energy output. The company
will also be responsible for electrc transmission to move power from the
Lancaster plant.
2) Natural Gas Transportation Associated With Lancaster
The Lancaster plant is interconnected with the Gas Transmission Nortwest
(GTN) natual gas pipeline system. As par of the agreement with Coral, on
January 1,2010, the company wil receive permanent assignent of firm natual
gas transportation capacity on the TransCanada Albert and TransCanada BC
systems and temporary assignent of firm natual gas transportation capacity on
the GTN system. The GTN temporar assignent of firm tranportation capacity
on the GTN pipeline by Shell Corporation terminates on October 31, 2017. These
firm transporttion arangements wil allow for deliveries of approximately
26,000 Dthd from the AECO trading hub on the Albert system and
approximately 26,000 Dthd from either the Stanfield or Malin trading hubs south
of the plant off of the GTN system.
3) Electric Transmission Associated With Lancaster
The Lancaster plant is interconnected electrically with the Bonnevile Power
Administration (BP A). There is a transmission agreement, held by the company in
Page 2
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No.4
Case No. AVU-E-09-01
R. Storr, Avista
Schedule 5. Page 2 of 14
A vista Utilties - Lancaster CCCT Power Purchase Agreement Acquisition
the name of Avista Energy, with BPA for 250 MW oflong-term transmission
capacity rights from the Lancaster point of receipt to the John Day point of
delivery that was assigned to Coral on a short term basis through December 31,
2009. Effective Januar 1,2010, there wil be a permanent assignent of the
10ng-term transmission rights to A vista Corporation.
The Lancaster CCCT Power Purchase Agreement Is Needed for Utity Service
The company was engaged in the process of finalizing its Integrated Resource PIan in April 2007
when the Lancaster Power Puchase Agreement option was evaluated for potential acquisition by
Avista Utilities. At that time the tabulation of the company's loads and resources (L&R)
positions showed energy and capacity deficits beginning in 2011; the energy deficit was 73 MW;
the capacity deficit was 146 MW. Those needs increased substantially in the years 2012 and
beyond. The February 2007 L&R tabulation is shown in Table NO.1 below.
Table No.1
February 23, 2007 L&R Tabulation
2008 2009 2010
131 88 42
148 94 5
The company submitted its 2007 IR on August 31, 2007. There was only a small increase in
amount of the energy deficit for 2011, The 2007 IR L&R tabulation is shown in Table NO.2.
Table No. 2
2007 IRP L&R Tabulation
2008 2009 2010
121 79 33
148 94 5
The utilty's curent October 25, 2007 L&R tabulation (without the Lancaster Power Purchase
Agreement included) continues to show energy and capacity deficits beginning in 2011 (20
aMW, 83 MW). The updated L&R tabulation was based on the company's latest load forecast
and assessment of resource capabilties and maintenance, The October 25,2007 L&R tabulation
is shown in Table No, 3.
Table No. 3
October 25, 2007 L&R Tabulation
2009 2010
125 94
116 43
Page 3
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No.4
Case No. AVU-E-09-01
R. Storro. Avista
Schedule 5, Page 3 of 14
A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
The company's 2007 IRP process indicated that 350 MW of additional base-load CCCT
capabilty (nameplate MW) should be included in the overall PRS for the first 10 years (2008-
2017) of the 20-year planning horizon. The IR process considers not only the cost of certain
resource options, but also their contribution to meeting other planing goals such as reducing
portfolio risk and meeting renewable portfolio standards, The 2007 IRP evaluated numerous
options available to the utility, including gas-fired CCCTs, wind plants, biomass plants, and
varous coal-fired technologies. Given these options, the IRP identified a preferred mix of futue
resource alternatives.
The company used the PRiSM decision support softare to help guide its resource planng
decisions. The PRiSM model brings together the intrnsic and extrnsic values of Avista's
existing portfolio of resources, its 10ad obligations, and resource opportities available to meet
futue 10ad requirements. To captue the optionality inherent in each resource option (listed in
the 2007 IRP, Table 8.1) available to the company, the results from 300 Monte Carlo rus were
considered. Capital, transmission and fixed operations and maintenance costs attibutable to
each new resource option were evaluated, PRiSM was used to review the existing resource
portfolio and select an optimal mix of new resources from the available options. Alternative
resource mixes, including the PRS mix, were subjected to additional comparison and testing to
assess the optimum balance of risk and cost. The PRS was selected on a comparative basis
taking into account the balance of risk and costs of different resource mix strategies,
The resulting PRS for the first 10-year period of the 2007 IR shows a need to add 772 MW of
new resources consisting of the following resource tyes: 350 MW - Combined Cycle
Combustion Turbine; 300 MW - Wind Generation; 35 MW - Other Renewable; 87 MW -
Conservation. The Lancaster CCCT fills a portion of the PRS mix.
The Lancaster Plant Is Cost-Effective
April 2007 Analysis:
The April 2007 analysis of the Lancaster Power Puchase Agreement, along with associated
natual gas transportation and electric transmission agreements, showed the acquisition of the
Lancaster Power Purchase Agreement to be cost-effective compared to other alternatives.
Because a firm transfer date for the Lancaster Power Purchase Agreement had not been set as
par of the overall negotiations concerning the sale of Avista Energy to Coral Energy, the
analysis initially 100ked at thee potential sta dates of Januar 18t of 2009, 2010 or 2011. The
Januar 1,2010 date ultimately became the agreed upon transfer date.
The company analyzed Power Puchase Agreement start date alternatives from two planing
scenaros. The first scenario was based on the load and resource tabulation that was developed
as par of the ongoing 2007 IRP process which indicated anual average deficits beginning in
2011. This load and resource tabulation was based on the company's traditional planing margin
criteria, which is approximately 15% of peak load. The second scenaro was an adjusted load
and resource tabulation based on the Northwest Planning and Conservation Council (NPCC)
planning reserve margin level of 25% of peak 10ad. This load and resource tabulation indicated
an immediate 2008 planing deficit.
Page 4
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No.4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 5, Page 4 of 14
A vista Utilties - Lancaster CCCT Power Purchase Agreement Acquisition
For the Januar 1,2010 Power Purchase Agreement transfer date, the analysis demonstrated the
Lancaster Power Purchase Agreement was less costly than either a new "greenfield" or a
potential existing "brownfield" natual gas-fired CCCT plant alternative. The Lancaster Power
Purchase Agreement was estimated to save customers $4 milion under the traditional planng
reserve scenario and $22 milion based on the NPCC planng reserve scenario, on a present
value basis when compared to a brownfield site. A similar comparison to a greenfield site
indicated present value saving of$62 milion under the traditional reserves planning scenario and
savings of $78 milion based on the NPCC planing reserve scenario.
Lancaster's 10cation in the company's Idaho service territory has the advantage of avoiding the
nearly 4% Washington state fuels tax. However, that comparative savings was not considered in
the April 2007 analysis. The comparative benefit from the lack of fuel tax in Idaho is estimated
to add an additional $2 million in anual savings, or approximately $15 millon on a present
value basis. Another factor in favor of the Lancaster Power Purchase Agreement that was not
explicitly included in the economic comparson to other new plant alternatives was the absence
of constrction risk.
2007 Integrated Resource Plan - Lancaster Assessment:
The 2007 IR had already developed assessments of resource alternatives and had determined
the PRS for the company at the time that the Lancaster Power Purchase Agreement opportity
was made to the utility. As stated earlier, the IR considers not only the cost of certin resource
options, but also their contrbution to meeting varous other planing goals such as reducing
portolio risk and meeting renewable portfolio standards. After assessing the costs and benefits
of varous resource mix options, a PRS was selected in the 2007 IRP process which included the
addition of350 MW of new gas-fired CCCT generation as part of that resource mix within the
first ten years of the plan.
Subsequent to the anouncement concerning the sale of A vista Energy to Coral energy on April
17,2007, the company made the IR Technical Advisory Committee aware ofthe Lancaster
Power Purchase Agreement and the timing of its transfer to A vista Corporation on Januar 1,
2007. Lancaster was identified as a technologic match with the 350 MW ofCCCT that was part
of the PRS. Given that and because the Lancaster was available to the utility in the same
timeframe as the PRS, there was not a need to update the strategy in the 2007 IRP. The 2007
IR explained that the Lancaster Power Purchase Agreement reduced costs by 2.3% relative to
the original PRS that included 350 MW of new gas-fired CCCT generation as shown in Table
NO.4 below. The document states, on page 8-30, that "savings are created by acquirng a more
cost-effective plant (relative to a greenfield plant) and an adjustment to new resource additions
(changing the timing of other new resource additions)."
As explained earlier, the preferred resource strategy is selected based on a balance between
resource mix cost and risk. A graphical depiction from the final 2007 IR shows how Lancaster
provides a similar risk profie while being 10wer-cost than the PRS absent the Lancaster Power
Purchase Agreement.
Page 5
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No,4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 5, Page 5 of 14
A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
Table No.4
2007 Integrated Resource Plan
Figure 8.32: Effcient Frontier with Lancaster Plant
1,450
220
1,550
2008 to 2017 Total Cost Net Present Value ($Milions)
1,650 1,750 1,850 1,950 2,050 2,150 2,250
90i1 II ,No Additns see & Green Tags i :I i CC& i i I I
- - - . - - i - - - - - - -, · - - - - Green Tags - ; - - - - - - - ; - - - - - - - -: - - - - - - - -:- - - - - - - -: 0% Rik ~i .:: ::i I i I I_ _ _ _ _ _ _ ~ _ _ _ _ _ _ _ ~ _ _ . _ PR No Fixed Gas Wind 20% _ _ _ _ _ _ _ _,_ _ _ _ _ _ _ _:_ _ _ _ _ _ ___
I i. I () Cant. to PM Renew abies i
: : ~ . Coal Allowed . & cr :
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: : : PRwKh 50% Rik 100% Rik :: : : Lancaster :
íi"" i:.. 0c: =75N =.. :Eo lßi: -0..:¡ :g60.! 0ãi ::Q ã.
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2008 to 2017 Total Cost Percent Change from 75% Cost25% Risk
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Thorndike Landing, LLC - Independent Valuation:
In August 2007 the company retained an independent consulting firm to pedorm an assessment
of the Lancaster Power Purchase Agreement acquisition. Thorndike performed a _ year
discounted cash flow (nCF) analysis to determine the intrnsic and extrnsic value of the Power
Purchase Agreement under Base, High and Low case scenaros. The base case assumes that
Lancaster can be interconnected to the A vista tranmission system and that the tranmission wil
be remarketed or otherwise optimized to recover 75% of the cost. The high case scenao
included a doubling of C02 prices. The low case scenario included the addition of 5,000 MW of
combined cycle capacity thoughout the WECC, which negatively impacts margins. The total
value of the Lancaster Power Purchase Agreement, as dispatched against the market, was
positive in all three cases.
Table No.5
Lancaster Power Purchase Agreement Value vs. Market
Power Power
Purchase Purchase
Agreement Agreement
Value Value
DescriDtion ($000)($/kW)
Base Case $16,500 $64
Low Case $500 $2
Hb!h Case $20,500 $78
Page 6
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 5, Page 6 of 14
A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
Because the transmission cost assumption had a material impact on the Lancaster valuation,
Thorndike Landing performed sensitivity analyses based on the percentage of the BP A 250 MW
transmission cost that would be recovered through remarketing it to third parties, The analyses
show the Lancaster Power Purchase Agreement has positive value in all cases except where none
of the transmission is remarketed.
Table No.7
Transmission Impact On Lancaster Power Purchase Agreement Value
Percent of Power Power
BPA Purchase Purchase
Transmission Agreement Agreement
CostRe-Value Value
marketed ($000)($/kW)
100%$24,750 $94
75%$16,500 $64
67%$13,750 $52
50%$8,500 $33
33%$3,000 $12
25%$500 $2
0%($7,500)($29)
Based on the above valuation perspectives, Thorndike stated that they "found that the Toll
provides positive value to A vista and its customers,., .and the value of the Lancaster facility
appears consistent with - if not greater than - the value of other resources in the market."
Thorndike fuer performed a review of Avista's analytic process and methodology to identify
any potential shortcomings or areas that might be improved to provide the company with a
better, more comprehensive analytical process. Thorndike identified two items (exclusion of
natual gas transporttion costs and exclusion of costs associated with imputed debt) to warant
furter consideration by A vista. They concluded that those items did not have a material impact
on the calculated values or the overall conclusions with respect to the Lancaster Power Purchase
Agreement. Thorndike found that "Avista's analytical process and methodology is a very
contemporary approach to analyzing resources." Thorndike fuers stated that "(w)e have found
that A vista's analytic process is sound and even surasses processes used by many of their peers
across the industr."
Avista's initial April 2007 assessment, the 2007 IRP analysis, and the Thorndike Landing
independent review all indicate that the Lancaster Power Purchase Agreement is cost-effective
compared to other resource options under base case conditions as well as under various different
scenarios.
The Lancaster Facilty is Highly Dispatchable
Page 7
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09),doc
November 2, 2007
Exhibit No.4
Case No. AVU-E-09-01
R. Storro, Avista
Schedule 5, Page 7 of 14
A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
The Power Purchase Agreement for the Lancaster plant provides its owner the abilty to operate
the plant in a flexible maner as if the utility owned the plant itself.
Gas-fired CCCT plants are one of the most dispatchable electrcity-generating technologies
available to utilities. Relative to other viable options, only simple-cycle gas-fired tubines can
have more operational flexibility. Gas-fired CCCTs are capable of providing energy and
capacity on short notice. The plants also can provide capacity for both spinning and non-
spinning reserves, Many utilities use a portion of CCCT plant capacity to provide regulation
services. Gas-fired CCCTs with the "duct-firing" capability of Lancaster provide additional
flexibilty to meet changing 10ad and market conditions. CCCTs, by their inherent design,
operate significantly more efficiently over a range of operating levels when compared to simple-
cycle CTs.
The IRP modeling process dispatches all resource options to the wholesale marketplace. Where
a resources' cost is 10wer than purchasing power from the market, the model causes that plant to
run and the savings, as compared to market, are tracked for the portfolio. The modeling accounts
for start-up costs, plant heat rates, and minimum up and minimum down times when it considers
whether or not to dispatch a resource. The model also accounts for minium and maximum
generating levels, as well as hourly ramp rate capabilties. In the case of CCCT plants like
Lancaster, the IRP dispatch model also separately dispatches duct-firig capabilties using each
plants' unique heat rate, operating characteristics, and costs, bringing that capacity on-line when
market conditions support it.
Electric Transmission
The Lancaster plant is curently interconnected only to the BP A transmission system. As stated
above, the utility wil receive assignent of 250 MW of firm transmission capacity on the BP A
transmission system as part of the acquisition of the Lancaster Power Puchase Agreement
beginning Januar 1,2010. The transmission point of receipt is Lancaster and the point of
delivery is John Day at the head of the Southern Interte.
Compared to other CCCT projects in the region, Lancaster is unique as it is 10cated within the
company's service area. The utility plans to investigate whether the Lancaster project can be
directly interconnected to the A vista transmission system in the Rathdrm area, The BP A
interconnection agreement for Lancaster is held by the project owners (Cogentrx/Goldman
Sachs and Energy Investors Funds Group).
The cost of the BP A transmission was explicitly included in the Lancaster modeling and analyses
by both A vista and by Thorndike Landing. The base case assumes that Lancaster can be
interconnected to the A vista transmission system and that the transmission will be remarketed or
otherwise optimized to recover 75% of the cost.
A vista and Thorndike did consider an alternative, due to economics or other factors, where the
Lancaster plant is not directly interconnected to the company's transmission system. In that
case, a smaller portion of the transmission would be remarketed principally at times when the
plant is not operating. However, because the firm transmission curently has John Day as a point
Page 8
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No.4
Case No, AVU-E-09-01
R. Storro. Avista
Schedule 5. Page 8 of 14
A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
of delivery, there may be opportity to captue additional value for customers by sellng power
at that point or at COB. Firm power sales into California can often command a higher price
compared to purchasing replacement power for delivery within the Nortwest region.
Optimization through sellng power at COB or John Day and buying power in the region may be
an alternate method of covering some of the cost of the BP A transmission if an interconnection
with the Avista transmission system is not reasonably achievable.
Natural Gas Transportation
The Lancaster plant benefits from firm gas tranporttion from AECO to the Malin trading hubs.
This transportation can serve the entire needs of Lancaster, including duct firing (approximately
46,168 Dthd). This firm transportation wil allow for deliveries of up to 26,256 Dthd from the
AECO trading hub on the Albert system and up to 26,388 Dthld from either the Stanfield or
Malin trading hubs south of the plant. This dual source approach gives the company the ability to
fuel the plant at an overall lower cost than if the firm transportation was solely from the AECO
trading hub to the plant intae. Furher, this transporttion arangement allows the company to
make use of any excess transportation for other gas-fired generation resources such as the Coyote
Springs 2 project duct firing, the Rathdr combustion tubine project and/or the Boulder Park
generation project. Durng periods where Lancaster is not dispatched and the transportation is not
utilized for other Avista gas-fired facilities, the utility may be able to optimize the transportation
value by purchasing gas at the lowest priced trading point on the tranportation path and selling
gas at the highest-priced trading point on the transportation path. Durng extended periods where
the plant is offine, the company also has the option of releasing the transportation capacity in the
capacity reP ower Purchase Agreement market.
The transportation capacity on the GTN pipeline segment, in both the north-to-south and the
south-to north directions, is under a contract held by Shell Corporation that wil be temporarily
assigned to Avista Corp for the period January 1, 20 i 0 through October 31, 2017. Shell
curently holds roll-over rights to that capacity. The company expects to be able to acquire
transportation capacity necessar to replace that temporar assignent of firm capacity on the
GTN system prior to October 31, 2017.
Comparison To Other Combined Cycle Combustion Turbine Plants
The Lancaster Power Purchase Agreement opportity was made available to the utilty as part
of the sale of Avista Energy to Coral Energy. The company made comparisons to other similar
resources based on industr data available at the time. In addition, the company had requested
Thorndike Landing to perform comparisons to other combined cycle plants as par of their
independent analysis.
A vista IR - Comparative Analysis:
As stated earlier, the company's 2007 IRP selected 350 MW of combined cycle combustion
tubine resource for acquisition by 2017. The IRP used generic resource assumptions to provide
a roadmap with regard to the tye of resources that A vista should procure. The company
Page 9
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No,4
Case No. AVU-E-09-01
R. Storr, Avista
Schedule 5, Page 9 of 14
A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
developed the generic CCCT plant cost from a combination ofNPPC data, purchased plant
modeling data, and other publically available plant cost data. The generic CCCT plant is
assumed to be located in Idaho, resulting in lower fuel costs, and connected to Avista's
transmission system thereby avoiding third-par wheeling charges. The expected cost for the
generic CCCT resource was $786 per kW in 2007 dollars ($850 per kW in 2010 dollars) and
escalated at 2.8% per year. Using the plant and market data from the 2007 IRP, a generic
resource beginning service in 2010, was estimated to cost $83.64 per MW (2010 nominal
dollars, levelized over the period 2010-2040 and excluding the cost to firm natual gas
transporttion)! .
A vista - Plant Comparisons:
Shortly after Avista Energy's sale to Coral, Goldman Sachs anounced that it was selling its
interest in Lancaster along with a substantial porton of its Cogentrx's resource portfolio. The
Lancaster Generation Facility, along with 13 other facilities across the countr, was put up for
auction. Avista responded to Goldian's anouncement with a proposal for the purchase of
Lancaster. Goldman later sold 80% of its Cogentrix resource portfolio interest, including
Lancaster, to Energy Investors Funds Group for an undisclosed amount.
A vista performed several Lancaster valuation studies in preparation for making a purchase
proposal, which included a comparson to similar combined cycle combustion turbine plant
transactions in the Northwest. The analysis included comparisons between Coyote Springs 2,
Port Westward, Goldendale, and Lancaster. The comparative analysis calculated the levelized
cost of each plant as if Avista owned the resource. Table No.8 shows the levelized costs in
nominal 2010 dollars for each resource studied. This table shows that the Lancaster Power
Purchase Agreement is slightly more expensive than Avista's previous acquision of Coyote
Springs 2. The Port Westward and Goldendale plants would be signficantly more costly to
A vista because of fuel costs and other costs associated with the locations of the facilities. Port
Westward and Goldendale both have fuel supplies based on higher Sumas prices whereas
Lancaster and Coyote Springs 2 are based on AECO prices. Goldendale is also at a financial
disadvantage because it must pay the Washington state fuel tax and has a higher heat rate
because of its hybrid cooling technology, The Port Westward project is a greenfield facility
which has relatively higher capital requirements,
Table No.8
Lancaster Levelized Cost vs. Other Regional CCCT Projects
Levelized Cost
Plant (2010-2026)
$/MWh
Coyote Sorim!:s 2 78.37
Goldendale 97.72
Port Westward 92.80
Lancaster Power Purchase 79.37
1 The 2007 IR at page 6-19 shows a CCCT cost estimate of$6S.l4 per MWh in 2007 levelized real dollars over the
plant life, This amount is equivalent to the $83,64 per MWh in 2010 levelized nominal dollars.
Page 10
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No.4
Case No, AVU-E-Q9-01
R. Storro, Avista
Schedule 5, Page 10 of 14
A vista Utilties - Lancaster CCCT Power Puchase Agreement Acquisition
I Agreement
For each plant, the levelized cost consists of all fuel costs, variable O&M, transmission cost and
losses, emissions costs (based on 2007 IRP), fixed O&M, fuel transport, outage risk, site value,
propert taxes, income taes, state fees, and Power Purchase Agreement payments and debt
equivalent charges. The levelized cost values shown are based on the plants operating at their
maximum availability. In reality, the plants would not operate during all periods of the year, and
would be displaced with lower cost market purchases.
The levelized cost results shows that the Lancaster project Power Purchase Agreement is
comparable to the Coyote Springs 2 project and a better alternative than either the Goldendale or
Port Westward projects would have been for Avista's customers.
Thorndike Landing - Plant Comparison:
Thorndike also performed a valuation of Lancaster under an ownership scenario which was then
compared to ownership values of other recent plant transactions. This represents the present
value of the difference between the variable dispatch costs, fixed O&M, insurance, and taxes for
each plant compared to the project market net revenue. (Note that the varable dispatch cost
does not include the Power Puchase Agreement cost in the case of Lancaster or the recovery of
capital or fixed costs in the case of other plants.) The comparson indicates that the Lancaster
project has a greater value than other recently constrcted or transacted facilities in the region.
Though Avista does not own the Lancaster plant, this comparison is a strong indication that a
similar Power Purchase Agreement (or toll) opportity at one of these other plants would be
somewhat less favorable economically to the company than the Lancaster opportity. Plant
values are sumarized in the following Table NO.9
Table No.9
Lancaster Plant Value vs. Other Regional CCCT Projects
Plant Plant
Value Value
Descrintion ($000)($!kW)
Lancaster $177,500 $677
Coyote Snrigs 2 $169,500 $652
Port Westward $236,000 $528
Goldendale $84,000 $365
Thorndike Landing attbutes the greater relative value of the Lancaster project to the following
primary drivers:
. Lower electrc transmission costs;
. Lower natual gas transportation costs;
Page 11
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09),doc
November 2, 2007
Exhibit No.4
Case No, AVU-E-09-01
R. Storra. Avista
Schedule 5, Page 11 of 14
A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
. Lower natual gas taxes (the state of Idao has no fuel tax); and
. Dual sourcing of fuel (Albertalin vs. Sumas).
Self-Build Alternatives
As described in the cost-effectiveness section, self-build options were expected to be more
expensive than the Power Puchase Agreement agreement. The Power Purchase Agreement was
estimated to be between $62 and $78 millon dollars less than an equivalent greenfeld project.
Thorndike Landing concured with this conclusion.
Page 12
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 5, Page 12 of 14
A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
Revenue Requirement Impact
While the Lancaster project becomes available one year prior to the company's annual average
resource need in 201 1, as indicated in the company's 2007 IRP, it is a timely opportnity to
acquire a base-load resource at a cost lower than a new greenfield project and at a 10wer cost for
A vista than similar projects transacted in the region. Even when compared to an alternative
greenfield combined cycle combustion turbine plant that would come on-line with perfect
timing, the Lancaster plant has a 10wer revenue requirement impact.
Table No. 10 shows the expected anual revenue requirement impact over the period 2010
through 2026 for Lancaster and a greenfield and browneld plant, along with the decreased
revenue requirement for the Lancaster plant compared to other capacity alternatives. The
revenue requirement impact is calculated by subtracting the spot market energy value of the plant
from the total plant cost. The remaining revenue requirement impact represents the capacity cost
of acquirig a new resource.
As shown in Table No, 10 below, a greenfield plant coming on-line in 2011 would be expected
to cause a levelized revenue requirement impact that is $ 1 1.3 milion/year greater than Lancaster
over the period 2010 to 2026. Acquisition of a similar browneld plant located outside of the
utilty's service territory (at a cost of$500/kW as shown in the April 2007 analysis) is calculated
to have a levelized revenue requirement impact that is $300,000/year greater than Lancaster over
the period 2010 to 2026,
Table No. 10
Annual Revenue Re uirement 1m
Reveri Reuiirent ~act
Year
2010 0,0 0,0 12,9 (12.9)(12.9)
2011 31.18.3 14,2 17,1 4.2
2012 32,8 18,7 13.0 19.8 5.7
2013 32,9 19,2 14.3 18,5 4,9
2014 33,1 19,9 15.8 17.3 4.1
2015 27.4 14,7 11.16.1 3.3
2016 25.4 13.1 10.5 14,9 2.6
2017 24,9 13,0 11.13.8 1.9
2018 25.3 13,8 12,6 12,7 1.2
2019 24,6 13.4 12,9 11.6 0.5
2020 25,5 14,7 14.9 10,5 (0.2)
2021 24,9 14.6 15.5 9.4 (0.9)
2022 23,2 13.3 14,9 8.4 (1.6)
2023 24.3 14,8 17.1 7.3 (2.3)
2024 21.0 11.8 14.8 6,2 (3.0)
2025 18.8 10,0 13,7 5.1 (3,7)
2026 23,0 14,6 19,0 4,0 (4.4)
Levelid 25.5 14.5 14.1 11.0.3
Page 13
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09),doc
November 2, 2007
Exhibit NO.4
Case No, AVU-E-09-01
R. Storro, Avista
Schedule 5, Page 13 of 14
A vista Utilities - Lancaster CCCT Power Purchase Agreement Acquisition
Sensitivity Analyses
Several sensitivity analyses were performed as part of the Lancaster assessment process. The
company's IRP analysis process provided figues for both the intrnsic and extrnsic values of the
Lancaster plant over 300 Monte Carlo iterations of market conditions (varied for natual gas
price, hydroelectric generation levels and forced outages) durng the term of the Lancaster Power
Purchase Agreement. 2007 IR results for the range of value attbuted to a gas-fired CCCT are
show in Table No. 11 below.
Table No.n
Lancaster Plant Value - Sensitivity Analysis
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Thorndike Landing valued the Lancaster tollng arrangement under Base Case, Low Case and
High Case conditions as explained in their report and the results of which are previously
summarzed in Table NO.5. That sensitivity analysis indicates that the Lancaster plant performs
well against the market due largely to circumstace that natual gas-fired generation is the
marginal resource in the regional marketplace.
Page 14
Storro Exhibit_ 4-Schedule_5 (AVA-Jan09).doc
November 2, 2007
Exhibit No.4
Case No. AVU-E-09-1
R. Storro, Avista
Schedule 5, Page 14 of 14