20090529Lobb Direct.pdf

(-.BEFORE THE"
Y 29 12= 45
IDAHO PUBLIC UTILITIES COMMlSSl9N:
t ¡ ,l__ lJ
IN THE MATTER OF THE APPLICATION )
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-E-09-1/
AUTHORITY TO INCREASE ITS RATES) AVU-G-09-1
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC )
AND NATURAL GAS CUSTONERS IN THE )STATE OF IDAHO. )
)
)
DIRECT TESTIMONY OF RANDY LOBB
IDAHO PUBLIC UTILITIES COMMISSION
MAY 29,2009
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Randy Lobb and my business address is
4 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed?
6 A.I am employed by the Idaho Public Utilities
7 Commission as Utili ties Division Administrator.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science Degree in
11 Agricul tural Engineering from the Uni versi ty of Idaho in
12 1980 and worked for the Idaho Department of Water Resources
13 from June of 1980 to November of 1987. I received my Idaho
14 license as a registered professional Civil Engineer in 1985
15 and began work at the Idaho Public Utilities Commission in
16 December of 1987. My duties at the Commission currently
17 include case management and oversight of all technical
18 Staff assigned to Commission filings. I have conducted
19 analysis of utility rate applications, rate design, tariff
20 analysis and customer petitions. I have testified in
21 numerous proceedings before the Commission including cases
22 dealing with rate structure, cost of service, power supply,.
23 line extensions, regulatory policy and facility
24 acquisitions.
25 Q.What is the purpose of your testimony in this
CASE NOS. AVU-E-09-1/AVU-G-09-1OS/29/09
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1
1 case?
2 A.The purpose of my testimony is to introduce Staff
3 witnesses and the issues they address and describe Staff's
4 approach in evaluating the Company's request. I will also
5 discuss the various policy issues associated with this case
6 including establishing a test year, incorporating the
7 Lancaster Tolling Agreement and making changes to the
8 sharing percentages in the Company's Power Cost Adjustment
9 (PCA) .
10 Q.How is your testimony arranged?
11 A.My testimony is arranged as follows:
12 I. Recommendation Summary
13 II. Introduction of Staff witnesses
14 III. Case Evaluation
15 IV. Lancaster
16 V. The PCA
1 7 Recommenda tion Sumary
18 Q.Could you please summarize Staff's
19 recommendation?
20 A.Yes. Staff recommends an Idaho electric base
21 revenue requirement increase of $8.622 million or 3.91% and
22 a natural gas base revenue requirement increase of $1.894
23 million or 2.06%. Staff recommends an overall rate of
24 return of 8.55% and a return on equity of 10.5%.
25 Staff accepts the Company proposed historic test
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STAFF
2
1 year of October 31, 2007 through November 1, 2008 but
2 limits the proforma period for adjustments to 14 months
3 through December 31, 2009.
4 The primary rate base and revenue adjustments
5 proposed by Staff include a reduction in normalized power
6 supply costs of approximately $40.6 million (on a total
7 Company or system basis) from that proposed by the Company
8 and a reduction in the requested return on equity from 11%
9 to 10.5%. Other adjustments include elimination of rate
10 base additions and non power expense adjustments after
11 December 31, 2009 including the 2010 salary increase, cost
12 amortization of Montana Riverbed Agreement and removal of
13 costs associated with the Company's relicensing of its
14 Spokane River hydro facilities.
15 Staff proposes a uniform revenue spread to all
16 customer classes on the electric side with an across the
17 board increase in all energy rate components. Staff
18 further recommends that the Commission accept the Company's
19 proposed customer class revenue spread on the gas side as
20 adjusted for Staff's proposed revenue requirement and
21 approve an across the board increase in customer rate
22 components except the monthly customer charge. In an
23 effort to mitigate the impact of higher base rates, Staff
24 recommends that Purchase Gas Adjustment (PGA) and Power
25 Cost Adjustment (PCA) rates be reduced to offset the base
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STAFF
3
1 rate increases approved for gas and electric service in
2 this case.
3 Finally, Staff recommends that the Commission
4 approve the Company's request to include the cost of the
5 Lancaster Tolling Agreement in the PCA as proposed.
6 However, Staff recommends that the Commission deny the
7 Company's request in this case to change the sharing
8 percentage from 90%/10% to 95%/5% in the PCA mechanism.
9 Introduction of Staff Witnesses
10 Q.Could you please describe Staff's filing in this
11 case?
12 A.Yes. Senior Staff Engineer Rick Sterling is
13 responsible for review of profroma test year adjustments
14 proposed by Company witness Johnson and review of the
15 Company's Aurora power supply model used to calculate
16 annual net power supply costs. As a result of his review,
17 Mr. Sterling proposes two modifications to the modeled
18 power supply costs addressed by Company witness Kalich.
19 The first adjustment is a reduction in forecasted natural
20 gas prices to reflect more current forward market prices.
21 This adjustment reduces the Company's requested annual net
22 power supply costs by $36.33 million on a system basis.
23 The second adjustment removes short-term fixed
24 and financial hedge transactions made under the Company's
25 risk management plan. The volume and price of these
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STAFF
1 transactions are a function of below normal weather and
2 market conditions and are not appropriate for normalized
3 power supply costs included in base rates. This adjustment
4 reduces Company requested annual net power supply costs by
5 approximately $4.3 million on a system basis.
6 Senior Staff Auditor Joe Leckie develops Staff
7 recommended test year electric rate base with proforma
8 adjustments. Mr . Leckie accepts the Company's calculation
9 of rate base using the 13-month average as adjusted for
10 Staff's proposed proforma period. Staff recommends Company
11 proposed plant additions through December 31, 2009, to
12 arrive at a recommended Idaho jurisdictional rate base
13 level of approximately $564.144 million.
14 Mr. Leckie also addresses the cost of the Coeur
15 d' Alene Tribe Settlement, the Montana Riverbed Agreement
16 ~nd Spokane River Relicensing. Mr. Leckie recommends that
17 the Commission accept the Company's proposed treatment of
18 costs associated with the Tribal Settlement with adjustment
19 limited to rate base averaging consistent with Staff's
20 proposed test year. He then recommends an adjustment to
21 remove the costs of Spokane River relicensing because no
22 FERC license has yet been issued and costs are therefore
23 not used and useful. He also recommends that the deferred
24 costs associated with the Montana' Riverbed Agreement be
25 amortized over the 8-year agreement without carrying
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STAFF
5
1 charges. This allows the Company to fully recover its
2 investment but not earn a return on the deferred expenses.
3 Staff Auditor Donn English provides the Staff
4 recommendation for rate base, expenses and revenue
5 requirement for natural gas service in Idaho. He proposes
6 several adjustments on a total Company basis that reduce
7 revenue requirement for both gas and electric service. His
8 adjustments include elimination of 2010 salary increases
9 and acceptance of actual 2009 salary increases with various
10 other adjustments in salary expense. He recommends an
11 adjustment based on reduced regulatory fees, a reduction in
12 Board of Director expenses and adj ustments in a variety of
13 other expense categories. Mr. English also addresses
14 Employee Pension expense liability. Adjustments on the
15 electric side are provided to Staff witness Vaughn for
16 derivation of the electric revenue requirement. For Idaho
17 natural gas service, Mr. English recommends a rate base of
18 $90.03 million and an Idaho revenue requirement increase of
19 2.06% or $1.894 million.
20 Staff Auditor Cecily Vaughn begins with actual
21 audited, total Company cost data for the historical 12-
22 month test year base period of October 1, 2007 through
23 September 30, 2008. She then applies the Company proposed
24 jurisdictional allocation methodology and Staff proposed
25 expense and rate base adjustments to develop an Idaho
CASE NOS. AVU-E-09-1/AVU-G-09-1
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STAFF
6
1 jurisdictional electric revenue requirement through
2 December 31, 2009. The resulting annual base revenue
3 requirement increase proposed by Staff is approximately
4 $8.622 million for an overall increase of 3.91%.
5 Dr. Vaughn's revenue requirement proposal is
6 based on the expense adjustments of Staff witnesses
7 English, the rate base and expense adjustments of Staff
8 witness Leckie, the power supply expense adjustment of
9 senior Staff witness Sterling and the cost of capital
10 recommendations of Staff Accounting witness Carlock.
11 Deputy Administrator and Audit Section Supervisor
12 Terri Carlock addresses cost of capital and return on
13 equi ty . Ms. Carlock recommends a return on equity of
14 10.50% and a capital structure of approximately 50% debt
15 and 50% equity for an overall recommended rate of return of
16 8.55%.
17 Senior Staff Engineer Keith Hessing addresses the
18 electric class cost of service (COS) methodology, class
19 revenue spread and several Company proposed modifications
20 to the power cost adjustment (PCA) mechanism including
21 tracking transmission expense, modifying the retail revenue
22 credit and inclusion of the production tax credit (PTC).
23 Based on his review, Mr. Hessing recommends that the
24 Commission accept the Peak Credit Cost of Service
25 methodology proposed by the Company but spreads revenue
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STAFF
7
1 uniformly in this case to all customer classes until
2 current class COS load studies are completed. Using the
3 Staff proposed jurisdictionally allocated Idaho revenue
4 requirement, Mr. Hessing recommends a uniform base rate
5 increase for all electric customer classes of 3.91%. Mr.
6 Hessing recommends that the Commission approve the
7 Company's proposed changes to the PCA to track variations
8 in the Production Tax Credit and third party transmission
9 costs/revenues included in base rates. Mr. Hessing further
10 recommends that the Commission approve the Company's
11 proposal to establish the retail revenue adjustment in the
12 PCA using the Commission approved average cost of
13 production and transmission subsequently established in
14 this case. Finally, Mr. Hessing evaluates the expected
15 level of PCA deferral balances over the next 18 months and
16 recommends a PCA rate reduction of 0.361 cents per kWh that
17 will offset the impact of the Staff's proposed base rate
18 increase without unduly increasing the risk of higher PCA
19 deferral balances in the future.
20 Staff Economist Matt Elam recommends that the
21 Commission accept the Company's gas cost of service based
22 revenue spread to the various customer classes. Using the
23 Staff proposed revenue requirement, the increases range
24 from a 2.0% increase for Schedule 131 to a 3.0% increase
25 for Schedule 111. Schedule 101, which is mostly
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STAFF
8
1 residential, will receive an increase of 2.9%. Mr. Elam
2 further recommends that only the commodity charge be
3 increased in each class to recover the proposed base
4 revenue increase. Finally, Mr. Elam recommends that the
5 PGA rate per therm be decreased by 0.02599 cents to offset
6 impact of the base rate increase and reflect the lower
7 forecasted cost of natural gas.
8 Staff Economist Bryan Lanspery recommends that
9 the revenue assigned to the various electric customer
10 classes as proposed by Staff witness Hessing be recovered
11 solely from the energy component. In addition Mr. Lanspery
12 utilizes the PCA rate reduction provided by Mr. Hessing to
13 offset the base energy rate increase for a net change in
14 rates ranging from an increase of 1.2% for General Service
15 Schedule 11 to a decrease of 2.01% for Potlatch (now known
16 as Clearwater Paper) Schedule 25. Residential customers
17 will see a net change of 0.61% under Mr. Lanspery's
18 recommendation.
19 Staff Economist Lynn Anderson addresses the
20 prudency of demand side management (DSM) expenditures made
21 by Avista from January 2008 through November 2008. Mr.
22 Anderson recommends that the Commission defer consideration
23 of the Company's DSM program expenditures until sufficient
24 information is provided to evaluate prudency. Mr. Anderson
25 points to a lack of post implementation program evaluation
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STAFF
9
1 and plans of the Company to improve its evaluation programs
2 as justification for deferring a finding of prudency in
3 this case.
4 Finally, Consumer Investigators Marilyn Parker
5 and Curtis Thaden address a broad range of consumer issues.
6 Ms. Parker discusses the number and tenor of customer
7 comments received by the commission in this case. She also
8 addresses the monthly residential customer charge, and
9 opposes any increase. She concludes by addressing reduced
10 telephone service level standards, increasing customer
11 complaints and the various improvements that the Company
12 has made in service quality technology.
13 Mr. Thaden provides information on customer
14 demographics, low income financial assistance programs,
15 payment programs and low income energy efficiency programs.
16 Case Evaluation
17 Q.What has been your role in this case?
18 A.My role as Staff Administrator has been to
19 oversee the preparation of the Staff case with respect to
20 identification of issues, coordination of positions on
21 those issues and development of Staff policy.
22 Q.What are the important policy issues in this
23 case?
24 A. In my opinion, the most important policy issues
25 include: establishing the rate case test year ¡identifying
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STAFF
1 revenue requirement adjustments i assigning cost of service
2 responsibili ty, and applying appropriate rate designs
3 including mitigation using the PGA and PCA. Additionally,
4 modification of PCA sharing percentages is an important
5 policy issue in this case.
6 Q.Please describe Staff's approach in evaluating
7 the Company's rate increase request.
8 A.Staff's approach in evaluating the Company's rate
9 request in this case was consistent with methods used many
10 times in general rate cases over the last few years. Staff
11 audited the actual costs booked in the test year, evaluated
12 the Company's proposed proforma adjustments to historic
13 costs and identified costs that were believed to be
14 inappropriate. Because Avista is an electric and natural
15 gas company operating in several state jurisdictions,
16 actual costs and proforma adjustments were evaluated on a
17 total Company basis. Any cost adjustments in the Company's
18 case identified by Staff were then allocated to gas and/or
19 electric service on an Idaho jurisdictional basis.
20 Q.Did Staff focus on any specific issues in its
21 review?
22 A.Yes. As in all cases, Staff focused on cost of
23 capital and the level of test year operation and
24 maintenance expense including employee compensation. Staff
25 also focused on the big ticket expense changes and capital
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STAFF
1 additions since the last rate case. Finally, Staff focused
2 on the "known and measurable" and "used and useful"
3 proforma adjustments to historic test year costs and the
4 period beyond the historic test year that adjustments
5 should be allowed.
6 Q.What proforma period does the Staff recommend be
7 allowed to adjust actual test year results of operations?
8 A.The Company uses an actual historic test period
9 of October 1,2007 through September 30,2008. Staff
10 recommends that known and measureable proforma adjustments
11 be allowed through December 31, 2009. Staff believes that
12 the 15 -month proforma period beyond the end of the 12 -month
13 test year assures that expenses and plant additions are
14 both known and measurable and used and useful. The
15 exception is in the calculation of net power supply costs
16 because these costs are already normalized using a
17 forecasting model. Staff does not oppose allowing a
18 forecast of power supply costs through June 30, 2010 and
19 inclusion of any production plant used in the calculation.
20 Q.How does this compare to the most recent Order
21 issued by the Commission regarding historic test year and
22 proforma period?
23 A.The most recent Commission decision on
24 appropriate test year came in Order No. 30722 in Case No.
25 IPC-E-08-10. In that Order the Commission approved
CASE NOS. AVU-E-09-1/AVU-G-09-1OS/29/09 LOBB, R. (Di) 12
STAFF
1 modification of Idaho Power's historic 12-month test period
2 with limited adjustment into the future for anticipated
3 capi tal additions and expense changes. The proforma
4 adjustment period was limited to 12 months beyond the end
5 of the historic test period. The Commission did allow a
6 forecast of normalized power supply costs beyond the 12
7 month proforma period. Staff believes its recommended test
8 year and proforma period is consistent with the
9 Commission's Order in the Idaho Power case.
10 Q.Is Staff's recommendation to reduce the Company's
11 electric revenue increase request from $31.23 million to
12 $8.622 million and gas revenue requirement increase from
13 $2.74 million to $1.894 million in response to the weakened
14 economy and the level of opposition expressed by the
15 Company's customers?
16 A.Not necessarily. The impact of Company rate
17 increases on customers is always a concern of the
18 Commission Staff. In a weakened economy as described by
19 Staff witness Thaden, I believe customers expect Staff to
20 more aggressively evaluate the Company's request. However,
21 Staff believes it is always thorough in its audit review,
22 and this case is no exception. Staff believes its
23 recommendation to use PGA and PCA rate reductions to
24 mitigate base rate increases is a reasonable response to
25 current economic conditions.
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STAFF
1 Staff also believes it has continued to recommend
2 adjustments in those areas that are fair to the Company but
3 pass through only those costs that are necessary at this
4 time. For example, the lion share of the revenue
5 requirement adjustments come from three areas: 1) limiting
6 the test year proforma periodi 2) granting a reasonable
7 return on equity to shareholders, and 3) reducing the
8 requested electric power supply costs to reflect more
9 accurate prices available in the market place. The
10 justification for adjustments in these areas is fully
11 described in the testimony of the appropriate Staff
12 wi tnesses .
13 Q.Shouldn't even greater reductions in revenue
14 requirement have been proposed by Staff given the current
15 economic conditions?
16 A.Staff does not believe it is fair or reasonable
17 to the Company or its customers to propose a reduced
18 revenue requirement beyond that recommended by Staff in
19 this case. Based on its review of Company O&M expenditures
20 and capital additions, Staff concludes that its recommended
21 revenue requirement is appropriate and necessary to provide
22 adequate service.
23 Staff' believes that a further reduction in O&M
24 expenses could reduce service quality and reliability
25 beyond the point acceptable to most Avista customers.
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STAFF
1 Additionally, Staff believes that disallowing capital
2 investment for plant replacement actually completed could
3 impact Avista's earnings, financial ratings and ability to
4 borrow money at reasonable interest rates. Finally,
5 failure to allow the Company to include costs of
6 replacing/protecting aging or existing infrastructure could
7 reduce such investment in the future, again diminishing
8 reliability and service quality. Staff does not believe it
9 is appropriate at this time to sacrifice service quality to
10 assure marginally lower rates.
11 Q.Company witness Andrews states in her testimony
12 (page 9, lines 9-21) that costs associated with the
13 Coeur d' Alene Tribal Settlement and Spokane River
14 Relicensing were reviewed and approved for recovery in Case
15 No. AVU-E-08-01. Do you agree?
16 A.No. In the last case, the agreement between the
17 Coeur d' Alene Tribes and the Company had not been completed
18 and its costs were not finally known and measurable. Staff
19 agreed as part of the Settlement and the Commission
20 approved to defer all costs with a carrying charge until
21 the next rate case. Staff did not complete its review of
22 these issues in Case No. AVU-E-08-01 because final costs
23 were not known. The same is true for the Spokane River
24 relicensing i these costs were not known and measurable
25 because FERC had yet to approve the new license. Likewise,
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STAFF
1 these costs could not and were not approved in that case
2 for automatic recovery in this case.
3 Q.Were there indications in the last rate case that
4 costs associated with these two issues were incomplete?
5 A.Yes. Company witness Norwood states, on page 8
6 of his testimony filed in Support of the Settlement in Case
7 No. AVU-E-08-01, that a final license for Spokane River has
8 yet to occur. On page 9 he states that confidential
9 litigation (the Coeur d' Alene Tribe Settlement) is still
10 pending and has yet to be finally resolved. Moreover, the
11 Stipulation at page 5 states that issuance of the FERC
12 license "has yet to occur." And on page 6, the parties
13 acknowledge that settlement of the Coeur d' Alene Tribal
14 litigation "is still pending and has yet to be finally
15 resolved..."
16 Q.Is the Staff prohibited from making cost recovery
17 adjustments on these issues in this case?
18 A.No, not in my opinion. Neither Staff nor the
19 Commission in the last case evaluated the prudency of the
20 Coeur d' Alene Tribal Agreement or the Spokane River
21 Relicense. The Commission simply approved the Settlement
22 deferring the costs for accounting purposes. The
23 Settlement in no way authorized automatic, undisputed cost
24 recovery in this case based on the proposal of the Company
25 in Case No. AVU-E- 08 - 01.
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STAFF
1 Q.Why does the Staff recommend a reduction in the
2 PGA and PCA rates to mitigate proposed base rate increases?
3 A.Staff believes that the PGA rate reduction is
4 justified because the current weighted average cost of gas
5 (WACOG) embedded in rates is much higher than the forward
6 cost of gas in the market place. Even with the reduction,
7 the WACOG will likely decrease again this year as part of
8 the Company's annual PGA f i ling.
9 Staff's proposed PCA rate reduction is reasonable
10 but relies on future water conditions that are unknown and
11 might impact future PCA deferral balances. Staff witness
12 Hessing provides more information on future PCA deferral
13 balances with the proposed PCA rate reduction in this case.
14 Nevertheless, Staff believes that the risk of higher PCA
15 rates in the future is justified to moderated rate
16 increases for customers today.
1 7 Lancaster
18 Q.What is your understanding of the Lancaster
19 Tolling Agreement?
20 A.The Lancaster power plant is a 275 Mw gas fired,
21 Combined Cycle Combustion Turbine (CCCT) located in
22 Rathdrum, Idaho. The Lancaster Tolling Agreement between
23 Avista Utili ties and Rathdrum Energy LLC came about as part
24 of Avista Corporations sale to Coral Energy of Avista .
25 Energy (an Avista Utilities affiliate). Avista Energy
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STAFF
1 owned the output, under long term agreement (through 2027)
2 of the Rathdrum plant that came online in 2001. Avista
3 Utilities simply assumed the Avista Energy tolling
4 agreement originally signed with Rathdrum Energy LLC in
5 1998.
6 Beginning on January 1, 2010, Avista Utilities
7 has agreed to purchase all of the plant output through
8 2027. The generating plant will be owned and operated by
9 Rathdrum Energy LLC but dispatched as specified by Avista
10 Utilities. In return for the right to dispatch and utilize
11 plant output, Avista will pay a capacity charge, a fixed
12 O&M charge, a variable O&M charge and will purchase and
13 deliver all natural gas to fuel the plant. Avista will
14 also incur fixed costs for gas pipeline capacity and
15 transmission rights to Avista' s system over BPA lines.
16 Capacity and O&M charges will escalate at specified fixed
17 and variable rates over the remaining life of the contract.
18 Q.Is the Lancaster Tolling Agreement reasonable?
19 A.Yes, based on my review of the information
20 available at the time Avista utilities signed the Agreement
21 (April 2007), I believe purchase of the output from the
22 Lancaster CCCT was reasonable.
23 Q.How did you come to that conclusion?
24 A.I came to that conclusion by reviewing Avista' s
25 2007 Integrated Resource Plan (IRP) and comparing the cost
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STAFF
1 of the Lancaster Agreement to the cost of generation
2 alternatives available to meet anticipated loads. At first
3 glance, the tolling agreement looks somewhat self serving
4 when viewed as part of the sale of Avista Energy.
5 For example, although the preferred portfolio
6 identified in Avista's 2007 IRP called for up to 350 Mw of
7 new combined cycle generating capacity by 2012, the Company
8 did not issue a request for proposals (RFP) or obtain any
9 competitive bids to acquire a CCCT resource. In addition,
10 assumption of the tolling Agreement by Avista Utilities
11 seemed to be a concession by Avista Corporation in order to
12 sell its affiliate, Avista Energy. Finally, Avista
13 Utili ties did not hire an independent third party
14 consultant to evaluate the economic benefit of acquiring
15 the Lancaster output until after the transaction had
16 already occurred.
17 Regardless of appearance, the real question is
18 whether the transaction meets the reasonably anticipated
19 needs of customers at reasonable price. While the tolling
20 agreement was associated with an affiliate transaction and
21 outside the usual RFP competitive bidding process, Avista
22 had a demonstrated need and the Company's internal
23 evaluation and that of an independent third party
24 consultant provided extensive economic analysis of the
25 transaction as compared to other alternatives.
CASE NOS. AVU-E-09-1/AVU-G-09-1
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STAFF
1 As part of its evaluation, Staff reviewed the
2 underlying tolling agreement, the internal net present
3 value (NPV) comparison of alternatives performed by Avista,
4 the discounted cash flow (DCF) comparative analysis of
5 alternatives performed by Thorndike Landing LLC, the
6 Northwest Power and Conservation Council forecasts of CCCT
7 development costs and past and present CCCT surrogate cost
8 estimates used to set Idaho published avoided cost rates.
9 In each case, the price paid for Lancaster over
10 the life of the Agreement was lower than available CCCT
11 alternatives. Moreover, when the price is compared to
12 other more recent combined cycle resource acquisitions in
13 the region, the purchase agreement appears even more
14 valuable and beneficial to ratepayers.
15 Q.Did Avista show a need in 2007 for a resource of
16 this size by 2010?
17 A.Pages 2-19 and 2-20 of Avista's 2007 IRP, shows
18 proj ected capacity and energy short falls beginning in
19 2011. These pages also show the effect of Lancaster output
20 on the Company's net positions through 2027.
21 Q.What does the tolling agreement cost Avista and
22 its customers and how does that compare to other CCCT
23 alternatives?
24 A.The net present value and DCF analysis performed
25 by Avista and Thorndike , respectively, compared the
CASE NOS. AVU-E-09-1/AVU-G-09-1
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STAFF
1 Lancaster tolling agreement to other theoretical tolling
2 agreements based on capital construction costs of existing
3 regional CCCT resources. The analysis also compared the
4 agreement to expected costs to construct a new CCCT in the
5 region.
6 The analyses show that the tolling agreement is
7 essentially equivalent to a Company owned Greenfield plant
8 with a capital cost of about $530/kW. Further analysis
9 shows that the value of the tolling agreement is equivalent
10 to paying up to $677 /kW. The cost of the Tolling Agreement
11 compares favorably to all estimates of new construction
12 costs that likely would be incurred for a similar sized
13 plant. For example, Avista' s 2007 IRP shows new CCCT
14 capital costs of $786/kW, PacifiCorp's 2007 IRP shows new
15 cost ranging from $758 to $870/kW and Idaho Power's 2006
16 IRP estimates CCCT capital costs at $732/kW.
17 More recent examples of comparable CCCT
18 transactions include the purchase by PacifiCorp of the
19 existing 500 Mw Chehalis CCCT at a cost of approximately
20 $610/kW. Recent RFPs issued by PacifiCorp and Idaho Power
21 returned CCCT capital costs in the range of $1000 to
22 $1300/kW. Current surrogate CCCT costs (which are based on
23 current costs as reported by the Northwest Power and
24 Conservation Council) used to establish the Idaho published
25 avoided cost rate is $1100/kW.
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STAFF
1 According to the Company, 2010 fixed costs are
2 expected to be $20.87 per Mwh at a 69% capacity factor. At
3 gas prices ranging from $5 to $7/MMbtu, a heat rate of
4 about 7000 kWh/MMbtu and variable O&M charges, 2010
5 generation cost could range from $58 to $72/Mwh.
6 Q.Has the Company included Lancaster Tolling costs
7 in base rates?
8 A.No. Avista has requested that costs associates
9 with the tolling agreement be passed through the PCA when
10 the Company begins purchasing the output on January 1,
11 2010. Staff witness Hessing will address treatment of
12 these costs through the PCA.
13 The PCA
14 Q.Has the Company proposed any changes to the PCA?
15 A.Yes, Company witness Johnson has proposed four
16 changes to the PCA in this case. The first three changes
17 dealing with tracking variations in third party
18 transmission expense/revenues, tracking variations in PTC
19 and the method of calculating the retail revenue credit
20 will be address in the testimony of Staff witness Hessing.
21 I will address the Company's proposal to change
22 PCA sharing from the current 90%/10% split to a 95%/5%
23 split.
24 Q.What justification does the Company provide to
25 support such a change in the sharing percentage?
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 22
STAFF
1 A.Company witness Johnson was the only Company
2 witness to address this issue. His one page justification
3 was a description of how energy prices went from $88/Mwh in
4 April of 2008 to $25/Mwh in June and how volatility in gas
5 prices will become more significant for Avista with the
6 addition of the Lancaster plant.
7 Q.Is the justification provided by the Company in
8 this case sufficient to warrant a change in the PCA sharing
9 percentage?
10 A.No, not in my view. While the Company has
11 pointed to the volatility in gas and electric prices in
12 2008, it has not provided any information on how PCA
13 sharing percentages have affected the Company over the life
14 of the deferral mechanism. There is no demonstration of
15 negative financial impact or how that might change if
16 sharing percentages are modified. Idaho currently
17 represents only about 36 percent of Avista's electric
18 service with 64 percent of its services provided in
19 Washington. Any financial benefit to the Company or its
20 customers from changes in the Idaho PCA could be completely
21 offset by actions in its Washington jurisdiction. Finally,
22 the Company has not provided any rationale or supporting
23 justification showing why current PCA sharing unduly
24 penalizes the Company or why reducing its share of
25 extraordinary power supply costs is appropriate at this
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09
LOBB, R. (Di) 23
STAFF
1 time.
2 Q.Does this conclude your direct testimony in this
3 proceeding?
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Yes, it does.A.
CASE NOS. AVU-E-09-1/AVU-G-09-1
OS/29/09 LOBB, R. (Di) 24
STAFF
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 29TH DAY OF MAY 2009,
SERVED THE FOREGOING DIRECT TESTIMONY OF RANDY LODD, IN CASE
NOS. AVU-E-09-1 & AVU-G-09-1, BY ELECTRONIC MAIL TO THE FOLLOWING:
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL
AVISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220
E-MAIL: david.meyer(iavistacorp.com
DEAN J MILLER
McDEVITT & MILLER LLP
PO BOX 2564
BOISE ID 83701
E-MAIL: joe(imcdevitt-miler.com
CONLEY E WARD
MICHAEL C CREAMER
GIVENS PURSLEY LLP
PO BOX 2720
BOISE ID 83701-2720
E-MAIL: cew(igivenspursley.com
mcc(igivenspursley.com
BETSY BRIDGE
ID CONSERVATION LEAGUE
710 N SIXTH STREET
POBOX 844
BOISE ID 83701
E-MAIL: bbridge(fwildidaho.org
CARRE TRACY
1265 S MAIN ST, #305
SEATTLE WA 98144
E-MAIL: carre(fnwfco.org
KELLY NORWOOD
VICE PRESIDENT - STATE & FED. REG.
AVISTA UTILITIES
PO BOX 3727
SPOKANE WA 99220
E-MAIL: kelly.norwood(favistacorp.com
SCOTT ATKINSON
PRESIDENT
IDAHO FOREST GROUP LLC
171 HIGHWAY 95 N
GRANGEVILLE ID 83530
E-MAIL: scotta(iidahoforestgroup.com
DENNIS E PESEAU, Ph.D.
UTILITY RESOURCES INC
SUITE 250
1500 LIBERTY STREET SE
SALEM OR 97302
E-MAIL: dpeseau(fexcite.com
ROWENA PINEDA
ID COMMUNITY ACTION NETWORK
3450 HILL RD
BOISE ID 83702-4715
E-MAIL: Rowena(fidahocan.org
BRAD M PURDY
ATTORNEY AT LAW
2019 N 17TH ST
BOISE ID 83702
E-MAIL: bmpurdy(ihotmail.com
J.~
SECRETARY
CERTIFICATE OF SERVICE