20090619Sterling Direct.pdf

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IDAHO PUBLIC UTILITIES COMMISSION \0,1\-0 ~~~S\ON
Ul'L\T\E.S '
BEFORE THE
IN THE MATTER OF IDAHO POWER )
COMPANY'S APPLICATION FOR A ) CASE NO.IPC-E-09-3
CERTIFICATE OF PUBLIC CONVENIENCE )
AND NECESSITY FOR THE LANGLEY )GULCH POWER PLANT )
)
DIRECT TESTIMONY OF RICK STERLING
IDAHO PUBLIC UTILITIES COMMISSION
JUNE 19,2009
ALLEGEDLY PROPRIETARY DATA HAS BEEN
DELETED FROM THIS DOCUMENT
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Rick Sterling. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as a Staff engineer.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science degree in
11 Civil Engineering from the University of Idaho in 1981
12 and a Master of Science degree in Civil Engineering from
13 the University of Idaho in 1983. I worked for the Idaho
14 Department of Water Resources from 1983 to 1994. In
15 1988, I received my Idaho license as a registered
16 professional Civil Engineer. I began working at the
17 Idaho Public Utilities Commission in 1994. My duties at
18 the Commission include analysis of a wide variety of
19 electric and large water utility applications.
20 Q.What is the purpose of your testimony in this
21 proceeding?
22 A.There are several primary purposes of my
23 testimony:
24 1) To address whether Idaho Power has
25 demonstrated a sufficient need for a new
CASE NO. IPC-E-09-0306/19/09
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gas - f ired base load plant,
2) To address whether there are other, better
alternatives to meeting future load than
building a new generating plant,
3) To address whether Idaho Power conducted a
fair Request for Proposals (RFP) process and
chose the best proposal,
4) To discuss the Company i s Benchmark Resource
proposal and the costs Idaho Power is
requesting be approved as a Commitment
Estimate,
5) To discuss the requirements of Idaho Code
§ 61-541 and whether Idaho Power has met
those requirements, and
6) To make recommendations regarding recovery
of costs associated with the Langley Gulch
project.
Q.Please summarize your testimony.
A.My testimony begins by reviewing Idaho Power's
20 2006 Integrated Resource Plan (IRP), which is the
21 Company's basis for contending that it needs to acquire a
22 gas-fired base load plant. I also consider whether
23 changes in loads, resources, fuel prices and other
24 factors since the 2006 IRP still support a new gas-fired
25 base load plant. Based on my reviews, I conclude that a
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 2
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1 gas-fired base load resource is needed.
2 Next, I discuss a variety of other options for
3 addressing Idaho Power's load requirements, including
4 non-Company-owned generation, conservation, demand
5 response, transmission upgrades and others. I conclude
6 that while these are viable al ternati ves, they cannot be
7 relied on exclusively, and should continue to be pursued
8 in conjunction with a new gas-fired base load plant.
9 Next, I review the RFP process followed by
10 Idaho Power. I discuss the method used to evaluate bids
11 and address the price and non-price differences between
12 the top-ranked proposals. Although I express concerns
13 that Idaho Power did not p~rmit any build and transfer
14 proposals to be submitted, I conclude that the evaluation
15 of the proposals that were considered was fair. I
16 recommend that the Benchmark Resource proposal for the
17 Langley Gulch proj ect be accepted as the winning bid.
18 Next, I discuss the Company's Benchmark
19 Resource proposal and the costs Idaho Power is requesting
20 be approved as a Commitment Estimate. I identify
21 components of the Company's proposed Commitment Estimate
22 that I do not believe should be recoverable from
23 ratepayers. I also discuss the requirements of Idaho
24 Code § 61-541, and identify other components of the
25 proposed Commitment Estimate that I do not believe are
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 3
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1 known with enough certainty to merit pre-approval under
2 the new legislation.
3 Finally, I make recommendations about those
4 portions of the expected proj ect costs that I believe
5 merit pre-approval. I recommend that an amount of $347.0
6 million plus AFUDC be pre-approved for recovery under
7 Idaho Code § 61-541, and that all additional amounts
8 spent on the proj ect including transmission, up to a
9 maximum amount of $376.6 million plus AFUDC be subject to
10 future audit and prudence review once the costs are known
11 and the plant begins providing service.
12 Because your testimony is lengthy, pleaseQ.
13 provide a table of contents for the aid of readers.
14 A. A table of contents is provided below:15 Subj ect Page16 BACKGROUND 517 APPROACH 6
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NEED FOR POWER 9
OTHER RESOURCE ALTERNATIVES 23
OVERVIEW OF THE REQUEST FOR PROPOSAL PROCESS 30
Proposals 39
Evaluation of Proposals 42
Short List Analysis . .49
Analysis of Final Candidate Proposals 50
LAGLEY GULCH PROJECT DESCRIPTION 52
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Operation.53
Fuel Supply and Transportation 54
Water Supply. .56
Electrical Interconnection 57
Proj ect Permits 57
Project Risks .59
Project Benefits 60
COMMITMENT ESTIMATE 60
IDAHO CODE § 61-541 78
TOTAL EXPECTED POWER COST 82
FUEL COSTS . .85
STAFF CONCLUSIONS 86
13 BACKGROUN
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15 in this case?
Q.What is Idaho Power seeking in its Application
A.On March 6, 2009, Idaho Power Company filed an
17 Application requesting a Certificate of Public
18 Convenience and Necessity (CPCN) authorizing Idaho Power
19 to construct, own, operate, and maintain the Langley
20 Gulch power plant (Langley Gulch or Project) and
21 authorizing inclusion of the Proj ect in Idaho Power IS
22 rate base. The Projec't is a natural gas-fired combined
23 cycle combustion turbine (CCCT) generating plant with a
24 nameplate capacity of approximately 330 megawatts. The
25 Company proposes to construct the Proj ect on a parcel of
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 5
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1 land on the south side of Interstate 84 in Payette County
2 approximately four miles south of the town of New
3 Plymouth, Idaho. Idaho Power commits to procure and
4 construct the Proj ect for an amount that will not exceed
5 $427,400,000 which it terms a "Commitment Estimate."
6 Idaho Power proposes that amounts incurred in excess of
7 the Commitment Estimate would be subject to a "Soft Cap,"
8 that is, excess costs could only be included in rates if
9 the Commission agreed the additional amounts expended
10 were prudent and should be included in fair, just, and
11 reasonable rates. As a part of this Application, the
12 Company is requesting that the Commission's Order issuing
13 the CPCN authorize Idaho Power to include the Proj ect ' s
14 prudently incurred costs for fuel, fuel storage, and fuel
15 transportation for recovery through the Company's
16 existing Power Cost Adjustment (PCA) mechanism.
17 APPROACH
18 Q.Please describe the approach you took in your
19 review of the Company's Application.
20 A.I began my review by considering whether Idaho
21 Power' s need for power was sufficient to justify a new
22 base load resource. I reviewed the Company's 2004 and
23 2006 Integrated Resource Plans (IRPs), its 2008 IRP
24 Update, and information I received during planning
25 meeting related to the 2009 IRP which will be submitted
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 6
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1 in December. I also reviewed updated load forecasts and
2 load/resources balances provided by the Company in
3 response to production requests. In my review, I also
4 considered whether a gas-fired base load resource was the
5 proper type of resource to pursue, and whether Idaho
6 Power had adequately considered other options for meeting
7 forecasted loads.
8 Next, I reviewed the RFP process conducted by
9 the Company. I thoroughly reviewed the RFP and the RFP
10 Evaluation Manual, including the price and non-price
11 criteria used for scoring proposals. I reviewed each of
12 the proposals that were submitted and examined the scores
13 assigned by the Company's evaluation team. Both the
14 busbar analysis and the Aurora analysis used by the
15 Company to rank proposals and develop a short list were
16 carefully scrutinized. Transmission studies, air
17 emission studies, and various site analyses were also
18 reviewed.
19 Next, I reviewed the Company' s Benchmark
20 Resource proposal. I examined contracts for purchase of
21 the steam and gas turbines, as well as purchase of water
22 rights needed for plant cooling. I reviewed the land
23 purchase option, assessed the site's permitting status,
24 and studied fuel storage, transport, and transportation
25 agreements.
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1 Next, I carefully analyzed the Commitment
2 estimate proposed by Idaho Power. I checked whether
3 costs included in the Commitment Estimate matched costs
4 included in the Benchmark Resource proposal. I
5 considered whether any costs added to the Commitment
6 Estimate but not included in the Benchmark Resource bid
7 were proper. I reviewed all of the underlying bases for
8 each cost item in the Commitment Estimate, and proposed
9 amounts to be included in either a "Hard Cap" or a "Soft
10 Cap" based primarily on the certainty with which each
11 cos t item was known.
12 Finally, I reviewed the requirements of Idaho
13 Code § 61-514 and the rate making treatment requested by
14 Idaho Power. In addition, I considered the rate making
15 treatment for fuel that will be needed by the plant.
16 In my review of the Application, I examined
17 responses to 103 production requests of the Commission
18 Staff, as well as an additional 123 responses to requests
19 made by intervenors. Besides the numerous contracts,
20 studies and analysis mentioned earlier, I reviewed
21 presentation materials for the Board of Directors and
22 management, meeting notes, and a great deal of
23 correspondence related to the Langley Gulch proj ect. I
24 believe that Staff's review of Idaho Power' s Application
25 was deliberate, thorough and fair.
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1 NEED FOR POWER
2 Q.What is the basis for Idaho Power's request to
3 construct a new base load generating plant?
4 A.The need for a new base load generating plant
5 can be traced back at least as far as the Company's 2004
6 IRP. That plan called for a 500 MW coal-fired resource
7 in 2011. Joint ownership was suggested because Idaho
8 Power' s need was mostly seasonal. One alternative
9 considered was a joint project with PacifiCorp to add
10 another unit at the Bridger plant in Wyoming.
11 In its 2006 IRP, Idaho Power reassessed its
12 need for new resources. The plan included more DSM, more
13 purchases from PURPA proj ects and other renewables, and a
14 transmission upgrade in 2012. In addition, the plan
15 included a 250 MW pulverized coal base load resource in
16 2013 and a 250 MW advanced or clean coal-fired resource
17 (integrated gasification combined cycle; IGCC) in 2017.
18 Idaho Power and Avista went so far as to conduct a joint
19 study to investigate possible alternatives for new coal-
20 fired generation. In the meantime, however, concerns
21 about the effects of fossil-fueled generation on climate
22 change began to build. Public perceptions, expectations
23 about future C02 policy, and the reluctance of the
24 financial sector to support such a proj ect led to a
25 belief that new conventional coal-fired generation would
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1 be too costly, too risky, or politically infeasible.
2 Avista was the first to abandon its investigations into
3 new coal generation options, followed soon after by
4 PacifiCorp and Idaho Power. Idaho Power' s focus then
5 shifted to gas-fired generation to satisfy its base load
6 generation needs.
7 In 2008, Idaho Power updated its 2006 IRP.
8 Exhibit No. 101 shows a comparison of the 2006 IRP
9 preferred portfolio and the 2008 updated portfolio (Table
10 11). The 2012 entry listed as "Southwest Idaho CCCT" was
11 the basis for the base load RFP in which Langley Gulch
12 was selected.
13 Q.Are there any other factors that helped support
14 the Company's need for base load generation in 2012?
15 A.Yes, there were several. Idaho Power had been
16 anticipating a considerable amount of new PURPA proj ect
17 development coming online, both because numerous
18 contracts had already been signed and because
19 anticipation of higher avoided cost rates led to an
20 expectation of many additional contracts. In addition, a
21 significant amount of non-PURPA cogeneration development
22 was expected. None of that cogeneration materialized,
23 however, and the majority of PURPA projects with signed
24 contracts during this time frame have also failed to come
25
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1 online.1
2 Another factor has been the Company's
3 difficulty in adding planned amounts of geothermal to its
4 portfolio. In a 2006 Request for Proposals, a bid from
5 U. S. Geothermal was accepted to provide 45. 5 MW and to
6 have facilities online between October 2007 and January
7 2011. So far, only 13 MW have been developed, and
8 contracts for the remaining amounts have not been
9 executed. In 2008, Idaho Power issued another RFP
10 seeking 50-100 MW of geothermal generation. Although
11 several bids were made, no contracts have emerged from
12 that RFP.
13 Another factor has been an anticipated shift in
14 flow augmentation releases with water from the federal
15 dams on the Snake River above Brownlee. As a consequence
16 of a Biological Opinion dated May 5, 2008, the Bureau of
17 Reclamation intends to shift its flow augmentation
18 releases from Milner and the Boise basin from summer to
19 spring. This shift in flow augmentation has been
20 incorporated in Idaho Power's stream flow forecasts,
21 Operating Plans, and its 2009 Integrated Resource
22 Planning studies. The effect of the planned shift in
23 1 From 2005 to the present, PURPA QFs with a total
24 capacity of 175.5 MW have signed contracts but have yet
to come online. A total of 21.6 MW of signed contracts25 have been terminated during this same time period.
Proj ects with a capacity of 107 MW have come online.
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1 releases will be a loss of approximately 140 MWa of
2 summertime energy.
3 Finally, Idaho Power cites the expression of
4 interest from several possible new customers with large
5 loads to locate in the Company i s service territory. All
6 of these factors, combined with the Company's most recent
7 load forecast led to the 2012 base load RFP initially
8 calling for between 250 and 600 MW of new generation, and
9 the acceleration of the online date for the base load
10 resource from 2013 to 2012.
11 Q.Has the Company prepared an updated load-
12 resource balance to show whether a new base load resource
13 is needed?
14 A.Yes, it has. Idaho Power uses two primary
15 criteria in its planning to assess the need for new
16 resources - one is based on energy needs and the other is
17 based on capacity needs. The water and load conditions
18 used to determine the energy and capacity needs that
19 justified issuance of the 2012 Base Load RFP were 70th
20 percentile water and load for average energy, and 90th
21 percentile water and 95th percentile load for peak-hour
22 capacity needs. After the 2006 IRP was released, a
23 series of surplus/deficit spreadsheets were periodically
24 updated to reflect known or expected changes in resources
25 ór loads and the associated impact on forecast
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1 surplus/deficit position. Annual surplus/deficit
2 spreadsheets for energy and peak hour planning conditions
3 from March 2008 are included as Exhibit No. 102. The
4 load forecast used in these spreadsheets was from August
5 2007. Note that at the time these spreadsheets were
6 prepared, the Company was expecting both energy and
7 capacity deficits from 2008 onward.
8 Monthly average energy and peak hour
9 surplus/deficits are shown in Exhibit No. 103, both with
10 and without the Langley Gulch project included. Note
11 that with the Langley Gulch proj ect assumed in 2012, the
12 Company still projects energy deficits in some summer
13 months. Peak hour deficits, however, are nearly
14 eliminated by Langley Gulch after 2012.
15 Q.Do you believe that a new base load plant is
16 justified?
17 A.Yes, it is justified based on the information
18 and analysis in Idaho Power's 2006 IRP and 2008 IRP
19 Update, the Company's load-resource balance under various
20 water and load conditions, and transmission constraints
21 that limit its ability to import power during critical
22 times of the year . However, significant changes have
23 occurred since the Company's last IRP was prepared.
24 Q.What changes have occurred since the 2006 IRP
25 and the 2008 IRP Update were completed?
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1 A.One of the most obvious changes has been the
2 economic recession. The economic conditions have likely
3 stalled load growth expectations in nearly all customer
4 sectors. In response to production requests, Idaho Power
5 stated that in December 2008 it adjusted the residential
6 and commercial sector load forecast to reflect a
7 prolonged slowdown in housing and consumér spending.
8 Residential new customer growth rates (initially forecast
9 to decline until the first quarter of 2009) were extended
10 by Idaho Power to continue the decline into 2010 and
11 later rebound to the point of the original new customer
12 forecast in 2011. On a total customer (new plus
13 existing) basis, the Company's revised forecast returns
14 to the same value as the original forecast in 2016.
15 Commercial customer growth estimates were lowered
16 consistent with adj ustments made to the residential
17 class. Use-per-customer forecasts were not modified from
18 the original forecast.
19 In May 2009, the Company further revised its
20 load forecast to incorporate changes in special contract
21 forecasts. In addition, the Company updated the forecast
22 to include all DSM program impacts as of May 2009,
23 including new demand response programs for Irrigation,
24 Commercial, and Industrial customers proposed in the 2009
25 IRP process. The Company's most recent load resource
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1 balance is shown in Exhibit No. 104. Page 1 of the
2 exhibi t shows the load resource balance based on energy
3 planning criteria. Page 2 of the exhibit shows the load
4 resource balance based on peak hour planning criteria.
5 Exhibit No. 105 shows the amounts by which the load
6 forecasts have been changed compared to forecasts
7 included in the Company's 2008 IRP update.
8 Utilizing the May 2009 load forecast, along
9 with the forecast peak-hour DSM contributions and the
10 assumed level of purchases from the Pacific Northwest,
11 Idaho Power is still proj ecting peak-hour deficits during
12 July of 2009 through July of 2012 of 40 MW,21 MW,91 MW,
13 and 183 MW, respectively. From an average energy
14 perspective, using the May 2009 load forecast along with
15 the forecast DSM contributions to reduce average energy
16 requirements and the assumed level of purchases from the
17 Pacific Northwest, Idaho Power is still projecting
18 average energy deficits during July of 2009 through July
19 of 2012 of 397 MW, 418 MW, 465 MW, and 535 MW,
20 respectively.
21 Idaho Power is reportedly working on developing
22 a new load forecast, but does not expect it to be
23 available until late summer of 2009. The Company states
24 that the revised load forecast will be reflective of the
25 most current economic forecast drivers, the most recent
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1 input from the Company's large power representatives and
2 their contacts, energy efficiency impacts, and the latest
3 forecast of retail electricity prices.
4 Q.Are there any other recent changes you are
5 aware of that would affect Idaho Power's loads and
6 resources?
7 A.Yes, there are a few. This section of Staff's
8 direct testimony contains confidential information
9 subject to protective agreement. In addition, on May 28,
10 2009 the Company made a filing to delay the start of the
11 Hoku contract in 2009. As part of the agreement to delay
12 the contract start, Idaho Power is requiring Hoku to
13 reduce its July and August 2012 loads by 40 MW below the
14 original limits in the contract. Idaho Power has also
15 recently modified its Irrigation Peak Rewards Program to
16 encourage greater participation. As a result of the
17 program modifications, a much greater reduction in
18 summertime loads is expected than was originally
19 anticipated. Finally, the 2012 scheduled completion date
20 of the Boardman to Hemingway project that is expected to
21 add 255 MW of additional transmission capacity to the
22 Northwest has been pushed back to 2015. These changes
23 are reflected in Exhibit No. 104.
24 Q.Wi th so much economic uncertainty right now,
25 how can the Commission be certain that the proposed
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1 Langley Gulch proj ect is still needed?
2 A.With so much uncertainty, the Commission cannot
3 be certain that the proj ect will be necessary at exactly
4 the online date planned by the Company. For proj ects
5 with relatively long lead times, there will always be at
6 least some uncertainty about whether the planned online
7 date will exactly match the load growth forecasts. Load
8 will almost always occur at a faster or slower' rate than
9 planned.
10 Q.What would be the consequences if it turned out
11 that the online date of the Langley Gulch proj ect could
12 be delayed due to prolonged effects of the current
13 recession or other factors?
14 A.If the planned online date of the plant was
15 delayed, there would likely be costs, benefits and risks
16 that should all be considered and weighed against each
17 other. First, delaying the online date would likely
18 cause Siemens to either charge cancellation fees
19 (approximately $8.7 million for the gas and steam
20 turbines), or negotiate contract extensions wherein Idaho
21 Power would be responsible for increased costs. In
22 addition, the Engineering, Procurement and Construction
23 (EPC) contractor would likely increase its costs for
24 labor, materials and other services due to inflation.
25 The six month delay in online date already planned by
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1 Idaho Power is estimated to cost $6.8 million in the
2 Commitment Estimate. In addition to cancellation fees,
3 penalties and inflationary increases, delaying
4 construction could cause Idaho Power to incur higher
5 costs to purchase replacement power, and would also
6 likely cause Idaho Power to forego any revenues from
7 surplus sales that the plant might be able to make if it
8 were available.
9 On the other hand, delaying the online date
10 would also cause some savings. Delaying a $427 million
11 investment by one year reduces the proj ect' s net present
12 value by roughly $23 million.
13 Q.Would there be risks in delaying construction
14 if it were possible?
15 A.Absolutely. If the planned online date was
16 delayed and it turned out that the plant was actually
17 needed sooner, it could be just a cost risk if
18 replacement power could be found. However, because Idaho
19 Power is transmission constrained under high load
20 conditions during certain times of the year, it may not
21 be able to obtain replacement power at any price.
22 Ultimately, the risk could be mandatory curtailments.
23 By comparison, the risks of bringing the plant
24 online sooner than needed are completely financial. In
25 fact, bringing the plant online earlier than needed could
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1 even be beneficial if certain load and market pricing
2 conditions were to occur. In my opinion, the risks of an
3 early online date versus a late online date are not
4 symmetric. The costs and risks of bringing the plant
5 online too late far outweigh the costs of bringing the
6 plant online too soon.
7 Nevertheless, while there is no assurance that
8 the plant will come online at precisely the optimum time,
9 I do believe that the plant will still be needed in
10 approximately the time frame planned. If normal load
11 growth resumes and load forecasts return to pre-recession
12 levels, there is some risk that the plant would not be
13 available in time if construction were to be delayed now
14 based on current load growth rates. Because construction
15 of a CCCT has approximately a three-year lead time, the
16 Company does not have the luxury of waiting to see how a
17 recovery from the recession will unfold before making a
18 decision when to proceed on development of a new
19 generating resource.
20 Q.But given the uniquely high degree of
21 uncertainty Idaho Power is currently faced with, do you
22 think it is wise to make a decision now on such a maj or
23 resource addition?
24 A.Ideally, Idaho Power would only have to make
25 resource decisions when all factors are known.
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1 Unfortunately, that is just not realistic. There will
2 always be uncertainty, but perhaps current economic
3 conditions make the uncertainty seem greater than it has
4 been in the past. Doing nothing until there is more
5 certainty is very risky and simply not an option in my
6 opinion.
7 Q.In the 2012 Base Load RFP issued on April 1,
8 2008, Idaho Power was seeking proposals for between 250
9 and 600 MW of dispatchable energy. On June 25, 2008, the
10 RFP was revised to request 300 MW. Why did Idaho Power
11 revise the RFP to request a much smaller amount?
12 A.At the time the RFP was being prepared, Idaho
13 Power was discussing plans with two potential new
14 customers that could have added over 400 MW of new load
15 to Idaho Power's system. If these customers' proj ects
16 proceeded as anticipated, or if any other new customers
17 with significant electrical loads decided to move into
18 Idaho Power's service territory, Idaho Power was going to
19 need more resources to serve the new load. With this in
20 mind, the RFP was initially released with a quantity
21 range indicating that Idaho Power anticipated acquiring
22 between approximately 250 MW and 600 MW of dispatchable
23 energy. Although discussion with the two companies
24 continued, no final agreement was reached. Ultimately,
25 Idaho Power elected to set the RFP quantity at
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1 approximately 300 MW due to uncertainty about the size
2 and likelihood of potential new large loads.
3 After the release of the RFP, the economy
4 continued its steep downturn. In hindsight, the decision
5 to reduce the size of the RFP was probably a good one.
6 The smaller size of the RFP significantly reduces the
7 risk that loads will not recover enough in time to fully
8 utilize the full capacity of the plant, and lessens the
9 cost and risk if the plant's online date turns out to be
10 earlier than needed.
11 Q.As proposed and evaluated in the RFP process,
12 qualifying proposals were required to be capable of
13 commencement of energy deliveries not later than June 1,
14 2012, yet the proposed Langley Gulch facility has an
15 expected online date of December 1, 2012. Why is the
16 proj ect being delayed?
17 A.Idaho Power has explained that after the
18 Benchmark Resource proposal was recommended as the
19 winning bid, the Company's senior management questioned,
20 given the current financial crisis, whether the project
21 could be financed. The Company believed that the
22 Benchmark Resource proposal would provide substantial
23 cost savings for customers; consequently, management felt
24 that the best way to preserve those cost savings was to
25 defer the online date to see if the Commission was
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1 willing to provide ratemaking assurances that would
2 enable the Company to finance the proj ect in a way that
3 would preserve the significant cost savings for
4 customers.
5 Q.Do you believe it was a wise decision to delay
6 the required online date of the project?
7 A.I was aware of the Company's concerns that it
8 would not be able to finance a self-build project without
9 certain ratemaking assurances from the Commission.
10 Absent those assurances, I believe the Company thought it
11 might not be able to obtain financing for the project. I
12 also believe that the Company strongly wanted the
13 Commission to be able to consider approval of a CPCN
14 under legislation that was still pending at the time. It
15 makes sense that the Company would want to wait until it
16 was confident that the legislation would be passed before
17 deciding whether to proceed with the self -build proposal.
18 On the other hand, all other bidders were willing and
19 able to meet the online date required by the RFP.
20 Presumably they were confident they could finance their
21 proposals without a delay in the online date. The need
22 to delay the proj ect' s online date appears to only have
23 been an issue for the Company's Benchmark Resource
24 proposal.
25
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1 OTHER RESOURCE ALTERNATIVES
2 Q.Do you believe that Idaho Power has adequately
3 considered other alternatives to adding a new base load
4 plant?
5 A.Yes, I do. As discussed previously, Idaho
6 Power prepares an Integrated Resource Plan every two
7 years as required by the Commission. Because of the
8 plan's complexity, integrated resources planning has
9 become an almost ongoing process. In the planning
10 process, all new resource options are considered,
11 including renewable resources such as wind, geothermal,
12 and solar. Upgrades to existing hydro plants are also
13 considered. New gas-fired thermal generation options,
14 both simple cycle and combined cycle, are also on the
15 menu of possible choices, as are clean coal options such
16 as integrated gasification combined cycle (IGCC) and
17 supercritical pulverized coal. Nuclear options are also
18 considered for the outer years of the planning period.
19 Finally, a wide variety of demand-side options are also
20 considered.
21 Idaho Power's preferred resource portfolio
22 already includes some of these generating resource
23 options in addition to a base load gas-fired resource in
24 2012. An RFP for additional geothermal resources was
25 issued in 2008 and an RFP for up to 150 MW of additional
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 23
STAFF
1 wind generation was issued on May 18, 2009, just one
2 month ago. Clearly, Idaho Power is pursuing a variety of
3 other generating resource options besides just gas-fired
4 generation.
5 Q.Do you believe that PURPA projects (QFs) are a
6 viable means of meeting future base load needs of Idaho
7 Power?
8 A.No, I do not believe they can be planned on as
9 a reliable option for meeting base load needs. Nearly
10 all of the recent PURPA development has been small wind
11 projects. It is unknown how much additional capacity
12 might be developed and when such development might occur.
13 The maj ority of proj ects for which contracts have been
14 signed in recent years have yet to come online and have
15 had their contractual online dates extended. The recent
16 substantial increase in avoided cost rates for PURPA
17 proj ects will likely stimulate some new development, but
18 the amount and timing of new projects is unknown. The
19 timing and pace of PURPA development is not within Idaho
20 Power's control and is not dictated by the Company's need
21 for new generation.
22 Furthermore, because nearly all new QFs are
23 wind proj ects, it is unlikely that they could prove to be
24 an acceptable substitute for a new base load resource
25 even if they could be timely developed. Because wind
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 24
STAFF
1 generation is intermittent, there is no guarantee that
2 the generation would be available during all of the hours
3 when it would be needed.
4 Q.Are market purchases a reasonable alternative
5 for meeting future base load requirements?
6 A.Long-term market purchases or bilateral
7 contracts with other utilities can be good options in
8 some cases, but they require that transmission be
9 availablè to import the energy. It might be possible to
10 purchase a product from a marketer or another utility in
11 the Northwest, but such a purchase would require
12 transmission from Mid-C across one or more of the
13 Bonneville Power, PacifiCorp, Avista or NorthWestern
14 transmission systems, in conjunction with transmission
15 across Idaho Power's transmission system from the Hells
16 Canyon Complex to its load center. Because one or more
17 of these paths are frequently subject to congestion,
18 energy purchased at Mid-C cannot be used at all times to
19 meet the load requirements of Idaho Power.
20 Another al ternati ve would be to make firm
21 wholesale purchases and to acquire the necessary
22 transmission to deliver the energy to the east side of
23 Idaho Power's system. Although such purchases may be
24 available from time to time, long term reliance on east-
25 side transmission capacity is probably not feasible at
CASE NO. IPC-E-09-0306/19/09
STERLING, R (Di) 25
STAFF
1 least until completion of the planned Gateway West
2 project (a 500 kV transmission line across southern Idaho
3 and Wyoming). I do not believe it would be wise to rely
4 on east-side purchases indefinitely to meet either base
5 load or peak hour needs, especially during a time when
6 surplus generation may be in short supply. Moreover,
7 firm wholesale purchases delivered to the east side of
8 Idaho Power's system would use an increment of import
9 capacity that, because it is being used for a purchase,
10 would be unavailable in the event of a system emergency.
11 Q.If Idaho Power could, do you believe it would
12 be wise for the Company to rely on the market to meet its
13 base load needs?
14 A.Even if Idaho Power could rely on the regional
15 power market as an alternative to building new
16 generation, I believe that relying on the market carries
17 greater risk. Over the long term, the market could
18 arguably be the least cost source for new supply.
19 However, most customers are unable or unwilling to
20 tolerate the price volatility that comes with
21 significant exposure to the market. Moreover, besides
22 its effect on customers, the risk of over-reliance on
23 the market can potentially weaken the financial strength
24 of utilities if extreme price excursions occur.
25 Q.Idaho Power has contended that the primary
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 26
STAFF
1 reason for needing new generation to be located near its
2 load center is because of transmission constraints on
3 imports from the Northwest. Are transmission upgrades a
4 viable alternative to a new base load power plant?
5 A.I would characterize transmission upgrades as a
6 necessary component, rather than an alternative, in idaho
7 Power's plans to meet future load requirements. The
8 Company has been upgrading portions of its transmission
9 system to reduce constraints. The Brownlee to Oxbow
10 proj ect was completed in late 2003. It increased the
11 Brownlee East capacity by approximately 100 MW. Idaho
12 Power also completed an upgrade of the Borah-West path in
13 May 2007. This upgrade increased the Borah-West
14 transmission capacity by 250 MW. The increased
15 transmission capacity is available to serve Idaho Power's
16 native load requirements with new generating resources
17 located east of the Borah-West constraint (eastern
18 Idaho). Even with these improvements, however, Idaho
19 Power's transmission system is still constrained at
20 certain times for imports of energy from the Pacific
21 Northwest.
22 In its 2006 IRP and 2008 IRP Update, Idaho
23 Power has expanded its analysis of possible transmission
24 proj ects, associated costs, and potential risks. Based
25 on its analysis, the preferred portfolio incorporates a
CASE NO. IPC-E-09-03
06/19/09
STERLING, R (Di) 27
STAFF
1 transmission upgrade from northeast Oregon to southwest
2 Idaho. Cal led the Boardman to Hemingway proj ect, the 500
3 kilovolt (kV) transmission line would increase
4 transmission capacity from the Northwest by 225 MW. In
5 addition, Idaho Power and PacifiCorp are proceeding with
6 the Gateway West proj ect, a plan to build more than 1,000
7 miles of 500-kV transmission lines across Wyoming and
8 southern Idaho.
9 Q.Do you believe that conservation is a viable
10 alternative to adding a new generating resource?
11 A.A diverse resource portfolio should include
12 cost effective energy conservation. Conservation is part
13 of Idaho Power's resource planning strategy. The Company
14 has several DSM programs that have been underway for many
15 years. Other programs have been recently expanded or
16 modified, while a few new programs are just now being
17 introduced. The programs are aimed at both energy
18 savings as well as peak demand reduction. Programs are
19 available for all customer classes.
20 For long-term planning of energy conservation
21 and demand response programs Idaho Power relies on the
22 IRP process, consultation with its Energy Efficiency
23 Advisory Group and participation in regional energy
24 efficiency organizations. The goal of the processes is
25
CASE NO. IPC-E-09-03
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STAFF
1 to identify opportunities, evaluate them, and pursue all
2 of those that are cost-effective.
3 Staff believes that Idaho Power has
4 strengthened its commitment to achieving all cost-
5 effective energy efficiency and demand response
6 potential. The Company primarily uses the tariff
7 Schedule 91 Energy Efficiency Rider (Rider) to fund DSM
8 programs. Recently, the Commission in Case No.
9 IPC-E-09-05, Order No. 30814 increased the Idaho Rider
10 from 2.5 percent of base rate revenues to 4.75 percent.
11 The increase is intended to fund new and expanded energy
12 efficiency and demand response programs as well as
13 address a negative balance in the Rider account.
14 Conservation programs of the past, as well as
15 programs planned and underway now, have certainly proven
16 that energy usage can be reduced cost effectively.
17 However, even the most successful conservation programs
18 have historically been unable to keep pace with the
19 increasing load growth that must be met. In my opinion,
20 conservation programs by themselves cannot achieve enough
21 demand reduction to realistically satisfy the Company's
22 immediate need to meet growing loads.
23 Q.Do you believe that the other resource
24 alternatives that you just discussed can collectively
25 substitute for a new base load plant?
CASE NO. IPC-E-09-0306/19/09
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STAFF
1 A.No, I do not. While I believe each of these
2 other alternatives is important, all of them are either
3 already being pursued and are a part of the Company's
4 plan going forward, or they cannot be counted on with
5 certainty. There may be some opportunities for increased
6 efforts as more options become cost effective,
7 particularly with regard to conservation and demand
8 response, but I believe a new base load resource is still
9 necessary.
10 OVERVIEW OF THE REQUEST FOR PROPOSAL PROCESS
11 Q.Please provide a brief overview of the request
12 for proposals (RFP) issued by Idaho Power.
13 A.As called for in its 2006 IRP, Idaho Power
14 issued the RFP on April 1, 2008. The RFP sought
15 proposals for between 250 and 600 MW of dispatchable
16 energy. The RFP specified that only power purchase
17 agreements (PPAs) or tolling agreements (TAs) to supply
18 firm or unit contingent energy would be considered.
19 Proj ects were required to commence energy deliveries not
20 later than June 1, 2012. At a minimum, proposals were
21 required to include a 15-year term with at least one 5-
22 year contract renewal option; however, different contract
23 terms and options were encouraged.
24 Q.What did the RFP say with regard to
25 participation by Idaho Power or its affiliates?
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 30
STAFF
1 A.The RFP specified that proposals from any Idaho
2 Power affiliates would not be accepted. However, it also
3 clearly stated that Idaho Power would submit and evaluate
4 a natural gas-fired combined cycle combustion turbine
5 (CCCT) 'to be constructed by Idaho Power as one of the
6 resource alternatives. This proposal was designated as
7 the Benchmark Resource.
8 Q.Did the RFP specify the types of generating
9 resources that would be considered?
10 A.No, it required only that proposals use
11 commercially viable dispatchable technology.
12 Nevertheless, I think it was quite clear that the Company
13 was seeking proposals for gas-fired CCCTs. First, the
14 RFP was designated as a "base load RFP." It also
15 referred to the 2006 IRP' s initial identification of the
16 need for coal-fired base load generation and the
17 Company's subsequent decision to pursue the development
18 of a gas-fired CCCT instead. The requirement that the
19 project be dispatchable eliminated just about all
20 technologies except gas- fired generation.
21 Q.Did the RFP specify where proposed proj ects
22 must be located?
23 A.No, but it did make clear that the preferred
24 point of delivery was a direct connection with Idaho
25 Power's transmission system near the Treasure Valley load
CASE NO. IPC-E-09-0306/19/09
STERLING, R (Di) 31
STAFF
1 center.
2 Q.Why did Idaho Power amend its RFP from an
3 initial request of from 250 to 600 MW down to a request
4 of up to 300 MW?
5 A.Although the RFP initially stated that Idaho
6 Power anticipated acquiring between approximately 250 MW
7 to 600 MW, it made clear that the higher amount would be
8 used to serve potential new load and that a final
9 decision on the quantity sought would be made later. On
10 June 25, 2008, Idaho Power issued an addendum reducing
11 the RFP requested quantity to approximately 300 MW. The
12 Company indicated that the lower amount was based on a
13 revised assessment of its needs and its discussions with
14 companies proposing new large loads.
15 Q.What is a tolling agreement (TA)? How does it
16 differ from a power purchase agreement (PPA)?
17 A.In the electric industry, a tolling agreement
18 is an arrangement in which fuel is purchased by the
19 utility and delivered to a non-utility owned plant, then
20 burned or "converted" to generate electricity in exchange
21 for a pre-established tolling charge. The utility may be
22 responsible for procuring the fuel and arranging for its
23 delivery, and is required to assume all price risk
24 associated with its purchase. The power plant owner must
25 own and maintain the plant, and operate according to a
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 32
STAFF
1 schedule determined by the utility.
2 In a power purchase agreement, the utility does
3 not own the plant and is not responsible for purchasing
4 the fuel or arranging for its delivery. All fuel price
5 risk is normally assumed by the plant owner. The utility
6 is able to dispatch the plant, and energy is purchased at
7 an agreed upon price.
8 Q.The RFP stated that all bids would be compared
9 to a "Benchmark Resource" proposal. What was the
10 Benchmark Resource proposal?
11 A.The Benchmark Resource was a proposal made by a
12 team of Idaho Power i s own employees for a CCCT to be
13 constructed by the Company. The RFP did not divulge any
14 details of the Benchmark Resource, including its size,
15 where it would be located, or the exact type of equipment
16 it would use. At the time the RFP was issued, it was my
17 understanding that although development of the Benchmark
18 Resource proposal was already underway, it was still a
19 work in progress. Because the Benchmark Resource
20 proposal was ultimately selected as the winning proposal,
21 I will discuss it in much more detail later in my
22 testimony.
23 Q.Do you believe utilities should permit self-
24 build proposals to be made in RFPs?
25 A.Yes, in most cases. As long as the utility has
CASE NO. IPC-E-09-0306/19/09
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STAFF
1 the resources and experience to carry out its proposal, I
2 believe it should be allowed to compete with other
3 bidders. In some cases the utility may be able to make a
4 proposal that is less costly and better suited to meeting
5 the needs of its customers. To prohibit self-build
6 proposals would be to deny ratepayers an opportunity for
7 possibly the best proj ect at the lowest cost.
8 If self -build proposals are allowed in RFPs,
9 however, I also believe that safeguards should be in
10 place to guard against impropriety. The RFP process
11 should insure that the utility does not have an unfair
12 advantage and that all proposals are evaluated fairly.
13 Q.Why was the RFP restricted to only power
14 purchase agreements and tolling agreements? Why were
15 build-and-transfer proposals not allowed?
16 A.The Company's reasons for not allowing build-
17 and- transfer proposals are discussed in the direct
18 testimony of Idaho Power witness Bokenkamp. In short,
19 the Company believed that it would have needed detailed
20 design specifications in order to eliminate significant
21 design differences between proposals and to avoid a
22 complicated and subjective evaluation process. The
23 Company believed that, due to its earlier decision to
24 accelerate the online date from 2013 to 2012 and the
25 lead-time required for obtaining major equipment, the
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 34
STAFF
1 Company did not have enough time to prepare a detailed
2 design specification and release the RFP in time to meet
3 the 2012 online date.
4 Q.Do you believe Idaho Power 's rationale for not
5 allowing build and transfer proposals is reasonable?
6 A.I understand the Company's concerns about
7 needing detailed design specifications in order to insure
8 that the Company would receive quality equipment, exactly
9 the design features it wanted, and that the facility was
10 easy to operate and maintain. I also understand the
11 advantages of having direct control over proj ect design
12 and construction, and the possible difficulties that
13 might be encountered in proposal evaluation if proposals
14 contained design differences. Nevertheless, by not
15 allowing build-and transfer proposals, Idaho Power may
16 have locked potential bidders out of the process and
17 ultimately denied ratepayers of the possibility of a high
18 quali ty, lower cost plant.
19 Although I understand the timing difficulties
20 explained by Idaho Power, I think the excuse of not
21 having time to prepare detailed design specifications is
22 a weak one. Construction of a new base load plant has
23 been anticipated for many years, and it was no surprise
24 that a proj ect of this size and type would have a long
25 planning and construction lead time. The proj ect has a
CASE NO. IPC-E-09-0306/19/09
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STAFF
1 20-year net present value of roughly $2.7 billion and
2 will be expected to be in service for 35 years. Given
3 the magnitude of the proj ect, I do not think it would
4 have been unreasonable for Idaho Power to have built
5 several additional months into its RFP schedule for
6 detailed design specifications to be prepared so they
7 could be used as the basis for build-and transfer
8 proposals. Much of the time Idaho Power may have "saved"
9 during the RFP stage by not preparing a detailed proj ect
10 design will be made up later when detailed design work
11 must be done before construction begins. Moreover, the
12 Company ultimately delayed the project online date for
13 other reasons.
14 Q.Do you believe that build-and-transfer
15 proposals would have been submitted if the RFP would have
16 allowed them?
17 A.Yes, I do. I was personally contacted by two
18 potential bidders who expressed concern and frustration
19 that the RFP was not allowing build-and-transfer
20 proposals to be submitted. Other Staff were contacted by
21 two additional bidders expressing similar concerns. The
22 potential bidders stated that their business is building
23 new power plants, not owning and operating them. Unless
24 they could partner with another entity willing to own and
25 operate the plant, they could not participate in the RFP.
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 36
STAFF
1 Rather than seeking a partner, they indicated that they
2 would probably choose to not even submit a bid. It is
3 difficult to be reassured that the winning proposal in
4 the RFP is the best proposal if some interested bidders
5 chose to not submit bids because they were shut out of
6 the process by the Company.
7 Q.Do you know of any other concerns that
8 potential bidders may have had that caused them not to
9 participate?
10 A.Yes, one potential bidder who contacted me was
11 concerned that Idaho Power was allowing a self -build
12 proposal to be submitted. Their concern was that the RFP
13 process might be a sham just to satisfy Commission
14 requirements, and that in the end, Idaho Power would
15 select its own self-build proposal regardless of any
16 other bids that might be submitted.
17 Q.Do you know for sure whether any of the bidders
18 who contacted Commission Staff ultimately decided not to
19 submit bids?
20 A.No, I do not. In fact, Staff never asked any
21 of the potential bidders who expressed concerns to
22 identify themselves, so it would have been impossible to
23 know whether they submitted a bid~ I do know, however,
24 that not all of the potential bidders who attended the
25 Pre-Bid conference submitted bids.
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 37
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1 Q.Idaho Power stated that it hired RW Beck as an
2 independent consultant to assist with the RFP. What role
3 did the consultant play?
4 A.The RFP informed bidders that Idaho Power
5 planned to use RW Beck Inc. as an independent consultant
6 to help ensure that the RFP was conducted fairly and
7 properly and that all offers were treated objectively and
8 consistently. Possible tasks of the independent
9 consul tant were listed as follows:
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
. Consult with Idaho Power in preparing the RFP
and evaluation criteria.
. Consult with Idaho Power on evaluation of
proposals;
. Independently score all or a sample of the
proposals to determine whether the selection of
the short-list is consistent with the scoring
criteria.
. Compare the results of the independent
consultant's scoring with Idaho Power's scoring
and work with Idaho Power to attempt to
reconcile and resolve scoring differences.
· Prepare reports as requested by Idaho Power
including reports to the Idaho and Oregon
Commissions as requested by Idaho Power.
Q.Did the independent consultant perform all of
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 38
STAFF
1 the possible tasks that were identified?
2 A.No, R. W. Beck was only used to assist in
3 preparing the RFP and evaluation criteria, and to provide
4 guidance to the evaluation team. R. W. Beck was not asked
5 to independently score any of the proposals because of
6 cost considerations and the likelihood in the Company's
7 estimation that it would simply duplicate the scores of
8 Idaho Power.
9 Proposals
10 Q.Please summarize the response Idaho Power
11 received to its RFP.
12 A.Idaho Power received proposals from six bidders
13 by the October 17, 2008 RFP deadline. One proposal was
14 immediately rej ected because the bidder failed to submit
15 a Notice of Intent to Bid as required by the RFP. The
16 remaining five bidders proposed 13 alternative projects,
17 differing primarily by generating technology, equipment,
18 project configuration and location. All of the proposals
19 were for either gas-fired simple or combined cycle
20 proj ects. Obviously, one of the bids was the Benchmark
21 Resource proposal. Only one of the alternatives was for
22 a PPA. That proposal was eliminated during the initial
23 screening stage, however, for not meeting the requirement
24 to deliver energy and capacity to Idaho Power's system.
25 Except for the Benchmark Resource proposal, all of the
CASE NO. IPC-E-09-03
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1 remaining proposals were for tolling agreements. Each
2 proj ect proposed, by itself, would have satisfied Idaho
3 Power's need for approximately 300 MW, and none would
4 have needed to be combined with other proj ects or
5 proposals.
6 Q.Do you believe that the number and variety of
7 proposals received was sufficient to give reasonable
8 assurance that all realistic options could be considered
9 and that a competitive price could be obtained?
10 A.As I stated earlier, I have concerns that some
11 potential bidders may have chosen to not participate
12 because the RFP did not solicit build-and-transfer
13 proposals or because of concerns that all proposals would
14 not be evaluated fairly. This section of Staff's direct
15 testimony contains confidential information subject to
16 protective agreement.
17
18 I would have
19 certainly liked to see more bidders participate. There
20 were fewer bids received in this RFP than in previous
21 RFPs for the Bennett Mountain and Danskin projects.
22 Obviously, more bids would have increased the chances
23 that a proposal superior to the Company's Benchmark
24 Resource proposal would have been selected.
25 The fact that only one PPA proposal was
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 40
STAFF
1 submitted is neither surprising or of much concern to me.
2 Few developers are willing to take all of the gas price
3 risk for such fuel intensive projects, especially given
4 the length of the proposed agreement and the historical
5 volatili ty of natural gas prices.
6 Of the bids that were submitted, however, all
7 of them were made by qualified developers. Furthermore,
8 in my opinion, all of the bids that made it to the final
9 round of screening were extremely competitive.
10 Q.Do you believe that Idaho Power's Benchmark
11 Resource proposal had an advantage over other proposals?
12 A.I do not believe that it had an actual
13 advantage, but I definitely believe there was a
14 perception amongst some prospective bidders that it did
15 have an advantage. At the Pre-Bid Conference, some
16 bidders expressed concern that Idaho Power's Benchmark
17 Resource proposal had an advantage over other potential
18 bids because the Company had already made reservation
19 agreements with Siemens for gas and steam turbines. The
20 reservation agreements required a deposit of $8.7 million
21 to Siemens that would be forfeited if Idaho Power
22 canceled the equipment reservation or did not assign the
23 equipment to someone else. Idaho Power informed
24 potential bidders that it would not be willing to allow
25 another bidder to purchase the equipment from the Company
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 41
STAFF
1 if that other bidder IS proposal was selected in the RFP.
2 By locking up equipment before the RFP was issued, Idaho
3 Power was taking a risk that it would lose its deposit if
4 it was not the winning bidder. Other potential bidders
5 were not willing to make such a large potentially
6 nonrefundable deposit. Some felt that they would be at
7 greater risk of losing an equipment deposit because Idaho
8 Power could argue that the deposits were necessary
9 regardless of whether they made the winning bid and that
10 the Company could seek recovery of lost deposits through
11 the Commission.
12 I do not believe that the potential bidders'
13 concerns were warranted because Idaho Power did not
14 obtain any cost advantage by reserving equipment early,
15 nor were any points awarded in the proposal scoring for
16 having reserved equipment. Nevertheless, I think some
17 other potential bidders had a perception that Idaho
18 Power's self -build proposal had an advantage from the
19 start, which may have deterred some of them from
20 participating.
21 Evaluation of Proposals
22 Q.Please briefly describe the bid evaluation
23 process used by Idaho Power.
24 A.To review and score proposals, Idaho Power
25 assembled an evaluation team consisting of eight
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STAFF
1 employees from various business units of the Company,
2 including Power Production, Planning, Operations,
3 Finance, River Engineering, and Pricing and Regulatory
4 Services. In addition, advisors from the Company's Legal
5 Department and R. W. Beck, a third party consultant,
6 provided guidance to the evaluation team.
7 The evaluation team ranked the proposals using
8 the procedures and criteria outlined in an Evaluation
9 Manual prepared prior to the receipt of bids. Idaho
10 Power prepared the Evaluation Manual with the assistance
11 of R. W. Beck, its consultant. The Evaluation Manual
12 identified the criteria upon which the proposals would be
13 scored, assigned a maximum number of points to each
14 criterion, and provided a scoring guide to be used in
15 determining how points would be awarded for each
16 criterion.
17 Idaho Power used a three-stage screening
18 process in evaluating bids. In the first stage,
19 proposals were examined for responsiveness and to verify
20 that all minimum requirements set forth in the RFP had
21 been adequately addressed. This section of Staff's
22 direct testimony contains confidential information
23 subject to protective agreement.
24 In the second stage, proposals were compared
25 and ranked strictly on a cost basis to determine if any
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1 were substantially more expensive than the others. The
2 obj ecti ve at this stage was not to provide a precise
3 indication of the potential value of the proposals, but
4 rather to provide a good relative comparison of the
5 proposals to each other. Cost comparisons were made
6 between proposals based on the information provided in
7 the bids and on other costs deemed by Idaho Power to be
8 assignable to each proposal. Both fixed and variable
9 costs were included, and costs were calculated at various
10 assumed capacity factors. This section of Staff's direct
11 testimony contains confidential information subject to
12 protective agreement.
13
14 At the Stage 3 screening level, price and non-
15 price factors were scored for each proposal using a
16 weighted scoring system. The factors along with the
17 maximum scores allocated to each category are summarized
18 below:
19 PRICE CRITERIA (60 POINTS)
20 This section of Staff's direct testimony contains
21 confidential information subject to protective agreement.
22
23 Total 60 points
24 NON-PRICE CRITERIA (40 POINTS)
25 A. Project Development 8 points
CASE NO. IPC-E-09-03
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1
2
3
4
5
6
B. Proj ect Characteristics 8 points
C. Product Characteristics 8 points
D. Proj ect Locations 8 points
E. Environmental 8 points
F. Credit Factors & Financial Strength 8 points
Total 40 points
7 This section of Staff's direct testimony
8 contains confidential information subject to protective
9 agreemen t .
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Q.How were non-price scores determined?
A.To evaluate the bids based on non-price
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1 criteria, Idaho Power's evaluation team reviewed the
2 proposals and each member of the team awarded a score to
3 each proposal in each non-price category. All team
4 members' scores for all factors were then averaged for
5 each bid. The process was repeated following face-to-
6 face meetings between the team members and the bidders.
7 Q.Do you believe that the non-price criteria used
8 in the evaluation were reasonable?
9 A.I believe the evaluation criteria were
10 reasonable and not intended to favor one proposal over
11 another. The criteria were established prior to the
12 receipt of bids with the guidance and assistance of a
13 third-party consultant. Some of the non-price criteria
14 required subjective judgment in point factoring, but that
15 is difficult to avoid.
16 Q.Were all of the exact evaluation criteria and
17 the points associated with each made known to bidders in
18 advance?
19 A.Yes, I believe they were made very clear. The
20 RFP informed prospective bidders that price factors would
21 comprise 60 percent of the evaluation criteria and non-
22 price would comprise 40 percent. In addition, the RFP
23 included a list of all of the non-price factors that
24 would be considered. Exhibit No. 106 is a copy of the
25 scoring criteria that was included in the RFP.
CASE NO. IPC-E-09-03
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1 In some cases, additional explanations and
2 cautions were provided to inform potential bidders of
3 special concerns. For example, the RFP included the
4 following warnings: "Idaho Power is concerned about the
5 impact of degradation of air quality in the Treasure
6 Valley on the long-term availability of energy from
7 generation proj ects developed in the Treasure Valley.
8 Proposals using generation resources, located in Ada or
9 Canyon Counties, will be stringently scrutinized and may
10 not receive full points for this category. The Company
11 will also consider whether community opposition to a
12 proposed generation facility will delay the completion of
13 necessary facilities."
14 Q.Were transmission costs considered in
15 evaluating bids?
16 A.Yes, transmission costs were considered when
17 evaluating all bids. The transmission cost estimates
18 were based on studies performed by Idaho Power's
19 Transmission business unit for each bid that was
20 submitted.
21 Q.Did the RFP inform bidders of the likely
22 transmission constraints that might be encountered based
23 on where projects might be located?
24 A.Although no specific transmission cost
25 information was included, the RFP did inform bidders that
CASE NO. IPC-E-09-03
06/19/09
STERLING, R (Di) 47
STAFF
1 the preferred point of delivery for power is a direct
2 interconnection with Idaho Power's transmission system,
3 located near the Treasure Valley load center. In
4 addition, the RFP made clear that most of Idaho Power's
5 long-term rights to transmission are already dedicated to
6 existing resources. Respondents were directed to assume
7 that Idaho Power has no un-utilized, long-term firm
8 transmission rights that are available to be re-directed
9 to transmit proposed resources to Idaho Power's service
10 terri tory.
11 Q.What natural gas price was used in performing
12 the price analysis?
13 A.Idaho Power initially proposed to use the 2007
14 median forecast of the Northwest Power and Conservation
15 Council. However, believing that the forecast was low
16 compared to prices at the time, Idaho Power revised the
17 forecast to include substantially higher prices. A copy
18 of the revised forecast was available to all prospective
19 bidders as an addendum to the RFP. Gas prices were
20 assumed to be $9.39 per MMBtu in 2012 and were escalated
21 to $14.29 in 2030. In its sensitivity analysis of short-
22 listed proposals, Idaho Power used a high gas forecast in
23 which prices were assumed to be 150 percent of expected,
24 and a low forecast in which prices were 50 percent of
25 expected.
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 48
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1 Q.Were the gas prices assumed in the cost
2 analysis critical to the results?
3 A.Because the same gas price was utilized for all
4 project proposals, projects with lower guaranteed heat
5 rates (i.e. higher efficiencies) had lower fuel costs on
6 a cost per MWh basis. In the Aurora analysis, more
7 efficient units were dispatched more often than less
8 efficient ones under all gas price scenarios.
9 Consequently, more efficient units were also able to
10 generate more energy for surplus sales to the regional
11 market, and thus had lower overall costs at both high and
12 low gas prices. As a result, the price ranking of the
13 short-listed proposals remained the same under all price
14 assumptions.
15 Short List Analysis
16 Q.Please describe how Idaho Power developed a
17 short list of proj ects and completed further analysis of
18 the short list proposals.
19 A.After the Stage 2 screening was completed, the
20 top proposals from two bidders and the Benchmark Resource
21 team were short-listed and meetings with representatives
22 of the short-listed entities were held in January 2009.
23 Through these meeting and follow-up phone calls and
24 correspondence, Idaho Power was able to clarify bids,
25 such as definitively determining what things were or were
CASE NO. IPC-E-09-03
06/19/09
STERLING, R (Di) 49
STAFF
1 not included in the bid. All short-listed bidders were
2 permitted to refresh their bids following meetings with
3 Idaho Power's evaluation team. Final negotiations were
4 pursued with all three of the short-listed bidders.
5 Analysis of Final Candidate Proposals
6 Q.Please briefly describe the proj ects that made
7 the final short list.
8 A.This section of Staff's direct testimony
9 contains confidential information subject to protective
10 agreemen t.
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CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 50
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1
2
3 also one of the short-listed finalists. i will discuss
Idaho Power's Benchmark Resource proposal was
4 that proposal in more detail later in my testimony.
5 Q.How did the overall scores compare for the two
6 top-ranked proposals?
7 A.This section of Staff's direct testimony
8 contains confidential information subject to protective
9 agreemen t .
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Q.
A.
Please explain the top half of Exhibit No. 107.
This section of Staff's direct testimony
17 contains confidential information subject to protective
18 agreemen t .
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20
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22
23
24
25
CASE NO. IPC-E-09-0306/19/09
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1
2 Q.This section of Staff's direct testimony
3 contains confidential information subject to protective
4 agreement.
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24 LAGLEY GULCH PROJECT DESCRIPTION
Q.Please describe the Benchmark Resource plant.
CASE NO. IPC-E-09-0306/19/09
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1 A.The proposed Langley Gulch plant would be a
2 natural gas-fired CCCT plant with a nameplate capacity of
3 approximately 330 MWs. The facility would be located on
4 the south side of Interstate 84 approximately four miles
5 south of New Plymouth. The proposed project's combustion
6 turbine is a single Siemens SGT6-5000F. The plant would
7 also include a Siemens SST-900 steam turbine. The plant
8 would be water-cooled and be equipped with state-of-the-
9 art emission control equipment.
10 Operation
11 Q.Please describe the expected operation of the
12 proposed Langley Gulch plant.
13 A.If approved, the Langley Gulch plant will be
14 operated as a base load facility to serve Idaho Power's
15 load. However, when it is not needed to meet the
16 Company's own load, it would be economically dispatched
1 7 to make surplus sales whenever it could do so prof i tably .
18 The opportunity for sales of surplus energy will depend
19 on the difference between the market price of power and
20 the Langley Gulch plant's cost of production. Because
21 Langley Gulch is a very efficient state-of-the-art
22 combined cycle plant, its dispatch cost is lower than
23 many combined cycle plants in the region; consequently,
24 it may frequently be cost effective to operate the plant
25 to make off-system sales. In the Aurora analysis of the
CASE NO. IPC-E-09-03
06/19/09
STERLING, R (Di) 53
STAFF
1 proposal, annual capacity factors ranging from 50 percent
2 in 2013 to 75 percent in 2031 have been computed. The
3 plant is currently scheduled to be online in December of
4 2012.
5 Fuel Supply and Transportation
6 Q.As a part of this Application, Idaho Power is
7 requesting that it be allowed to include the project i s
8 cost of fuel, fuel storage and fuel transportation for
9 recovery through the existing Power Cost Adjustment (PCA)
10 mechanism prior to full inclusion in base rates. Do you
11 agree that this is appropriate?
12 A.A maj or component of the operating costs of a
13 combustion turbine generating plant is the cost of
14 natural gas fuel. Staff agrees that reasonable fuel
15 expenses should be approved for PCA recovery prior to
16 full review of normal operational costs in a general
17 revenue requirement case. Operation of the plant will
18 displace other more costly power supplies to the benefit
19 of Idaho Power customers; therefore, costs should be
20 included in the PCA. This is consistent with the manner
21 in which fuel costs were handled for the Bennett Mountain
22 and Danskin plants prior to full inclusion in base rates.
23 After normalized fuel-related costs are included in base
24 rates, only extraordinary fuel costs will flow through
25 the PCA.
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 54
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1 Q.How will natural gas be delivered to the plant?
2 A.The location of the proposed Langley Gulch
3 project is approximately three-fourths of a mile from the
4 Williams Northwest Pipeline. A short interconnection
5 pipeline will be constructed as part of the proj ect.
6 Idaho Power has not yet negotiated or entered into any
7 agreements for the purchase of natural gas fuel supplies
8 for the proposed plant.
9 Q.Does Idaho Power have adequate fuel
10 transportation rights on the Williams Pipeline to
11 accommodate the proposed plant?
12 A.Idaho Power already has several gas
13 transportation and storage agreements in order to provide
14 gas to its other gas-fired plants. This section of
15 Staff's direct testimony contains confidential
16 information subject to protective agreement.
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21
22
23 Q.How does Idaho Power plan to manage the risk
24 associated with purchasing natural gas for fuel?
25 A.Idaho Power has an Energy Risk Management
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 55
STAFF
1 Policy and natural gas is listed as a permitted
2 commodity; however, the policy does not specifically
3 address acquisition of natural gas. An internal Risk
4 Management Committee regularly quantifies, assesses, and
5 manages the Company's risk in accordance with its Risk
6 Management Policy.
7 Idaho Power also has gas hedging guidelines for
8 its existing gas-fired plants (Evander Andrews/Danskin
9 and Bennett Mountain). If the new Langley Gulch plant is
10 approved, I would expect the Company to develop its fuel
11 procurement strategy for both natural gas and
12 transportation capacity as well as expanded hedging
13 guidelines and risk management strategies for all of its
14 gas-fired plants. This section of Staff's direct
15 testimony contains confidential information subject to
16 protective agreement.
17
18 Because it is a base load plant that is
19 expected to operate at a relatively high capacity factor,
20 fuel costs for the Langley Gulch plant will be
21 substantial. A well-planned and executed hedging
22 strategy and risk management plan will be crucial to
23 managing fuel price risk in the future.
24 Water Supply
25 Q.What is Idaho Power's plan for water supply?
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 56
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1 A.Water would be used by the plant primarily for
2 evaporative cooling, which is normally only required in
3 the summer months. Water would be supplied with water
4 from the Snake River. This will require a pumping
5 station and an 8 -mile pipeline. Idaho Power has already
6 paid $2.2 million to purchase a water right to secure
7 water for the plant. Construction of the pipeline has
8 been estimated to cost $8.1 million.
9 Electrical Interconnection
10 Q.What transmission work would have to be done in
11 order to interconnect the proposed plant?
12 A.The site is relatively close to existing
13 transmission facilities. As planned, the Langley Gulch
14 plant would be connected to the existing Ontario-Caldwell
15 230 kV line located 2.5 miles away. It would also be
16 looped to connect to a tap approximately three miles from
17 Caldwell via construction of a new 18 mile 138 kV line.
18 The total cost for the transmission work is estimated at
19 $22.1 million. At this point, costs are estimated based
20 on a system impact study and are considered accurate to
21 within plus or minus 20 percent. Detailed costs would be
22 developed in a Design Study.
23 Project Permits
24 Q.Please discuss the air quality permit that will
25 be required for the proposed plant.
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 57
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1 A.One of the most critical permits needed by the
2 project is an air quality permit (Permit to Construct)
3 issued by the Idaho Department of Environmental Quality
4 (DEQ). Idaho Power has reported that the Permit to
5 Construct application is in draft preparation and is
6 expected to be submitted in June 2009.
7 Idaho Power's air quality consultant has
8 modeled air quality impacts for the Langley Gulch site
9 This section of Staff's direct testimony contains
10 confidential information subject to protective agreement.
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18
19 Q.will other permits be required?
20 A.Yes, other major permits include a
21 Comprehensive Plan change from Payette County, a Right-
22 Of-Way permit from BLM for transmission and water lines,
23 a Stream Alteration permit and a Water Quality
24 Certification from the Corps of Engineers, a Groundwater
25 Injection permit from the Idaho Department of Water
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 58
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1 Resources, and miscellaneous construction permits. There
2 do not appear to be any insurmountable obstacles in
3 obtaining permits to construct and operate the plant.
4 Project Risks
5 Q.What are some of the risks associated with the
6 Langley Gulch proj ect?
7 A.One risk is simply the risk associated with
8 using natural gas for fuel. As evidenced by the past
9 year, gas prices can be extremely volatile. The proj ect
10 would increase the amount of gas-fired generation in
11 Idaho Power's fleet to over 700 MW. Nevertheless,
12 whether Idaho Power chose the Benchmark Resource proposal
13 or one of the tolling agreements submitted in the RFP, it
14 would face the same risk.
15 However, by choosing the Benchmark Resource
16 proposal, Idaho Power will face some risks that it would
17 have avoided with a tolling agreement. First, by being
18 the owner and operator of the plant, Idaho Power will be
19 responsible for any ongoing capital investment that may
20 be required to keep the plant operational, and for any
21 O&M costs that exceed project estimates. Second, there
22 are potential construction-related risks, perhaps due to
23 delays or liquidated damages, that Idaho Power could be
24 responsible for by constructing the plant itself. Third,
25 by being the proj ect owner, the Company may be liable for
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 59
STAFF
1 equipment failures or decreases in heat rate that occur
2 after equipment warranties expire. Finally, there is the
3 risk that Idaho Power will not be able to obtain
4 financing construction of the plant. This issue is
5 discussed in more detail in the testimony of Idaho Power
6 witness Smith and Staff witness Carlock.
7 Project Benefits
8 Q.Besides the advantages of the Benchmark
9 Resource proposal that were considered in the scoring and
10 ranking of proposals, are there any additional benefits
11 to the Langley Gulch proj ect?
12 A.All of the tolling proposals considered in the
13 RFP were for only 20 year terms, and only the 20-year
14 costs and benefits of the Benchmark Resource proposal
15 were considered in the ranking and scoring of proposals.
16 However, the Langley Gulch proj ect is expected to have a
17 useful life of 35 years. Consequently, there are an
18 additional 15 years of residual value to the plant that
19 was not accounted for in the evaluations. This section
20 of Staff's direct testimony contains confidential
21 information subject to protective agreement.
22 COMMITMNT ESTIMATE
23 Q.Idaho Power has proposed a Commitment Estimate
24 of $427 million. Please discuss the items that make up
25 the $427 million.
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 60
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1 A.Exhibit No. 108 shows a breakdown of costs
2 included in the Commitment Estimate. Idaho Power has
3 already signed contracts with Siemens for the gas and
4 steam turbine equipment following competitive bids by
5 capable turbine manufacturers. This section of Staff's
6 direct testimony contains confidential information
7 subject to protective agreement.
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17 All of the items from lines 22 through 32 are
18 estimated costs, which with few exceptions have yet to be
19 incurred. Transmission costs associated with building a
20 new transmission line and interconnecting the plant are
21 shown on line 51 ($22.1 million). The estimated costs of
22 financing the plant (AFUDC) are shown on line 55 ($49.3
23 million). I will discuss the remaining items (lines 36-
24 38 and lines 42-47) in more detail below.
25 Q.Please discuss the items on lines 36-38 of the
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 61
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1 Commitment Estimate shown in Exhibit No. 108.
2 A.As I discussed earlier in my testimony, Idaho
3 Power decided to delay the proposed online date of the
4 proj ect from June 2012 to December 2012. In turn, the
5 scheduled start of engineering and construction was also
6 delayed. As a condition of agreeing to delay the start
7 of construction, the EPC contractor required Idaho Power
8 to accept responsibility for any increases in labor in
9 the interim (up to 2% of the original labor component)
10 This section of Staff's direct testimony contains
11 confidential information subject to protective agreement.
12
13
14
15
16 Q.Please discuss the items on lines 41-47 of the
17 Commitment Estimate shown in Exhibit No. 108.
18 A.The costs shown on line 42 is the estimated
19 cost to construct a gas line tap to the Williams
20 Northwest pipeline and to install a gas meter. Idaho
21 Power informed all bidders that it would assume these
22 costs and that bidders did not need to include them in
23 their bids. Line 43 represents the costs incurred by
24 Idaho Power's Benchmark Resource team in preparing its
25 proposal. Line 44 is an estimate of the cost of fuel
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 62
STAFF
1 that will be required during start-testing and
2 commissioning of the plant. Line 45 is an estimate of
3 the cost of transmission upgrades that have been
4 recommended to improve the transmission system but that
5 are not required to integrate the Langley Gulch plant.
6 Line 46 is a 20 percent contingency for transmission
7 costs. The transmission estimate included in the
8 Benchmark Resource bid was deemed to be accurate to
9 within plus or minus 20 percent, so the 20 percent
10 contingency was not included in the original bid. The
11 "sub-synchronous resonance" (SSR) Study/Implementation
12 cost of $1 million included on line 47 refers to analysis
13 Idaho Power believes it will need to do to determine
14 whether the Langley Gulch facility will cause potentially
15 harmful interactions with other parts of the Company's
16 transmission system.
17 Q.Please discuss the "Soft Cap" proposed by Idaho
18 Power.
19 A.The Company has proposed that the Commitment
20 Estimate be treated as a "Soft Cap." Idaho Power
21 proposes that all costs up to the $427 million Commitment
22 Estimate be pre-approved under Idaho Code § 61-541 and
23 that any costs above this amount be brought before the
24 Commission for specific approval.
25 Q.DO you believe the Commission should allow in
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 63
STAFF
1 the Commitment Estimate all of the costs requested by
2 Idaho Power?
3 A.No, I do not.
4 Q.What guidelines do you believe the Commission
5 should follow in determining an appropriate Commitment
6 Estimate amount?
7 A.I believe that only those costs that are known
8 with reasonable certainty and based on a competitive
9 procurement process be approved for recovery under Idaho
10 Code § 61-541. Approximately three fourths of the cost
11 items in the Commitment Estimate are known with certainty
12 and competitively procured. Contracts have been signed
13 with Siemens Power Equipment for the gas and steam
14 turbines, and an EPC contract has also already been
15 signed for a specific amount. Other amounts included in
16 the Commitment Estimate are based on estimates and
17 contingencies, and are not known with enough certainty to
18 be included in a Commitment Estimate. While some of the
19 estimated costs will almost certainly be incurred, I do
20 not believe they should be subject to pre-approval under
21 Idaho Code § 61-541. Estimated costs and contingencies
22 should be subj ect to the usual rigorous prudence
23 standards to which other utility investments are held.
24 Q.Do you believe that a Soft Cap, regardless of
25 the amount, offers sufficient protection to ratepayers
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 64
STAFF
1 that costs will be controlled?
2 A.No, I think it is also necessary to establish
3 an absolute "not to exceed" amount, or Hard Cap, to
4 protect ratepayers in the event extreme costs must be
5 incurred to complete the plant and make it operational.
6 If unforeseen circumstances were to occur and costs were
7 to balloon out of control, Idaho Power should not be
8 allowed to present an endless parade of cost approval
9 requests to the Commission claiming that unless the
10 additional investment is made, the plant cannot come
11 online and all investment up to that point is wasted. A
12 Hard Cap will provide incentives for the Company to
13 contain costs and manage the proj ect efficiently.
14 Q.How do you propose to establish a "not to
15 exceed" or Hard Cap limit?
16 A.I propose that a Hard Cap be established that
17 is equal to the expected proj ect cost plus a reasonable
18 contingency for those portions of the proj ect cost that
19 were based on estimates.
20 Q.Please discuss how you propose to determine an
21 appropriate Commitment Estimate amount. Please
22 specifically identify any amounts you propose not to
23 include in the Commitment Estimate and explain why you
24 propose to exclude them.
25 A.My recommended Commitment Estimate amount is
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 65
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1 shown on Exhibit No. 109. On the right side of the
2 exhibit, I have shown three primary columns. In the
3 leftmost column, I have simply reproduced the Commitment
4 Estimate proposed by Idaho Power. The middle column
5 labeled "Soft Cap" shows my recommendations for a
6 commitment estimate. The right hand column labeled "Hard
7 Cap" is my "not to exceed" recommendation.
8 Wi thin each primary column for the Soft Cap and
9 the Hard Cap, I show a percentage amount that I recommend
10 should be allowed. For example, I recommend that 100
11 percent of the gas turbine, steam turbine and EPC
12 contract amounts be included in the Soft Cap and Hard Cap
13 because there is a signed contract and these amounts are
14 known with certainty. Similarly, any other amounts that
15 are known with certainty I recommend be included at 100
16 percent. This would include site procurement on line 18,
17 NEPA permitting on line 20, Air Permitting on line 21,
18 Transmission/Network study costs on line 27. Capitalized
19 property tax is included on line 30 as it is a certain
20 expenditure but the actual amounts will vary based on
21 property valuations and levy rates. I have included
22 water right costs on line 19 at the exact contract amount
23 I was able to verify, which is slightly less than the
24 amount Idaho Power included in its Commitment Estimate
25 amount.
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 66
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1 In the Soft Cap column, I have included many
2 items at only 50 percent of the amount estimated by Idaho
3 Power. I am assuming that the accuracy of the estimates
4 for these items is plus or minus 50 percent. For
5 example, the engineer's report used as a basis for the
6 water line construction shown on line 22 states the
7 following:
8 This section of Staff's direct testimony contains
9 confidential information subject to protective agreement.
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1 Q.It appears that some of the costs included in
2 the Company's Commitment Estimate amount are due to
3 delaying the project's planned online date from June 2009
4 to December 2009. Please explain these costs.
5 A.Idaho Power has added amounts it labeled
6 "Commitment Estimate Contingencies" to its Commitment
7 Estimate. These are the amounts shown on lines 36-38 of
8 Exhibit No. 109 that I described previously.
9 Q.Do you believe that any of these costs should
10 be recoverable?
11 A.First, we cannot be certain that any of these
12 costs will actually be incurred. However, if they are,
13 because these costs were solely due to Idaho Power
14 delaying the proj ect' s online date by six months, I do
15 not believe they should entirely be the responsibility of
16 ratepayers. All bidders were expected to be able to meet
17 a June 1, 2009 online date, and as far as I know, all of
18 them were willing and able to meet that date. Concerns
19 about financing was the reason given by Idaho Power for
20 the delay, yet this appears to only have been an issue
21 wi th the Company's Benchmark Resource proposal. As a
22 result, I do not believe these costs should be included
23 in either the Soft Cap or the Hard Cap.
24 Q.Do you believe that "RFP Team Expenses" (line
25 43) should be included in the Commitment Estimate?
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 68
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A. The team that prepared the Company's Benchmark
Resource proposal undoubtedly has incurred costs and will
likely continue to incur additional costs, although I
cannot conf irm the amounts. In any case, this is a cost
that should not be included in either the Soft Cap or the
Hard Cap. Other bidders would have had to include these
costs in their bid amount, so it would be unfair for
Idaho Power to exclude them from the Benchmark Resource
bid during the evaluation process, but add the costs to
its Commitment Estimate after it determined that the
Benchmark Resource was the winning bid.
Q. What is your recommendation regarding start-up
test fuel shown on line 44 of Exhibit No. 109?
A. I recommend that none of the costs of start-up
test fuel be included in either the Soft Cap or the Hard
Cap. Idaho Power's reason for including them is that it
believes that because it would have been required to
supply fuel for ongoing operations under any of the
tolling agreements, it would logically have to also
supply any fuel needed for start-up testing. I do not
believe this would necessarily be the case, however.
Because no final tolling agreements were ever
negotiated, we can only speculate about what the terms
might have been. However, the draft tolling agreement
included with the RFP and provided to all prospective
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 69
STAFF
1 bidders clearly indicates that bidders, not Idaho Power,
2 would be responsible for the cost of start-up testing
3 fuel. Section 6.5.3.5 of the draft tolling agreement
4 states as follows: "Seller shall reimburse Idaho Power
5 for supplying and delivering the Fuel required during
6 Start-Up Testing to reach the minimum load of the
7 Facility. "
8 This section of Staff's direct testimony
9 contains confidential information subject to protective
10 agreemen t .
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1
2 Q.What is your recommendation regarding
3 transmission upgrades shown on line 45 of Exhibit No.
4 109?
5 A.I recommend that none of the costs of
6 transmission upgrades be included in either the Soft Cap
7 or the Hard Cap. I am not suggesting that upgrades are
8 unnecessary or unwise, or that their cost should be
9 unrecoverable. Instead, because these upgrades are not
10 required as part of the Langley Gulch project, I am
11 recommending that Idaho Power be required to demonstrate
12 the prudence of the investments in a future general rate
13 case just like it would other new investments in
14 transmission.
15 Q.What is your recommendation regarding the 20
16 percent transmission contingency shown on line 46 of
17 Exhibit No. 109?
18 A.The transmission study conducted by the
19 Company's transmission group included a cost estimate
20 believed accurate to within plus or minus 20 percent.
21 The estimate transmission cost was used in preparing the
22 Benchmark Resource proposal and was also used in
23 comparing and scoring bids; however, Idaho Power
24 recognizes that actual costs could exceed or be less than
25 the estimate.
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1 I agree that the transmission contingency might
2 be incurred, but I do not agree that the contingency
3 should be allowed as part of the pre-approved Commitment
4 Estimate. Consequently, I recommend that the
5 transmission contingency not be included in the Soft Cap,
6 bu t inc i uded in the Hard Cap.
7 Q.What is your recommendation regarding the SSR
8 ("sub-synchronous resonance") study shown on line 47 of
9 Exhibit No. 109?
10 A.I recommend that 50 percent of the estimated
11 cost be included in the Soft Cap and 150 percent be
12 included in the Hard Cap. The Company seems to be quite
13 uncertain about what the study may show, and the scope of
14 possible remedies if SSR problems are identified in the
15 study.
16 Q.What is your recommendation regarding the
17 transmission costs shown on line 51 of Exhibit No. 109?
18 A.I recommend that 80 percent of the estimated
19 costs be included in the Soft Cap and 120 percent be
20 included in the Hard Cap. Idaho Power has stated that
21 the transmission cost estimate has an accuracy of plus or
22 minus 20 percent; therefore, actual costs could be as low
23 as 80 percent of the estimate included in the Benchmark
24 Resource bid or as high as 120 percent of the estimate.
25 All other proj ects considered in the bid analysis
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1 included transmission cost estimates with the same degree
2 of accuracy; consequently, I would have proposed the same
3 treatment of transmission contingencies had one of them
4 been the winning bidder.
5 Q.What is your recommendation regarding AFUDC
6 costs shown on line 55 of Exhibit No. 109?
7 A.Details óf Staff's recommendations are
8 addressed in the testimony of Staff witness Harms.
9 However, in summary, AFUDC will be accrued based on the
10 actual amounts, timing, and borrowing rate for funds
11 needed to construct the plant. Thus, the exact amount of
12 AFUDC incurred can be computed and audited after the
13 plant is completed. Therefore, Staff recommends that the
14 actual amount of AFUDC incurred be recoverable, but that
15 it be cónsidered an addition to both the Soft Cap and the
16 Hard Cap amounts.
17 Q.What are some of the factors you believe the
18 Commission should consider when deciding whether to
19 approve costs above the Commitment Estimate if the
20 Commission decides that those costs should be subj ect to
21 prudence review and Commission approval?
22 A.Some of the factors which I believe the
23 Commission should consider are the following:
24 . the reasonableness of cost;
25 . the necessity of the expenditure;
CASE NO. IPC-E-09-03
06/19/09
STERLING, R (Di) 73
STAFF
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. the consistency with proj ect plans;
. the method of selection of contractors,
materials, equipment, and vendors;
. whether the cost is based on competitive
procurement of equipment, materials or
services,
· the nature of expense;
. whether the work is completed on time;
. whether any costs are penalties or liquidated
damages, and
. whether costs are consistent with pre-
construction estimates.
I do not believe that any additional costs
caused by Idaho Power's delay or negligence should be
recoverable.
Q.Are there any additional costs that Idaho Power
18 may incur because of its decision to delay the project's
19 online date by six months?
20 A.This section of Staff's direct testimony
21 contains confidential informtion subject to protective
22 agreemen t .
23
24
25
CASE NO. IPC-E-09-03
06/19/09 STERLING, R (Di) 74
STAFF
1
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6 On May 28, 2009, Idaho Power notified the
7 Commission of changes to the Company's contract with Hoku
8 Materials, Inc. One of the changes to the contract was a
9 40 MW required reduction in Hoku' s summertime load in
10 2012. I cannot be certain whether Hoku voluntarily
11 agreed to reduce its load during this period or whether
12 Idaho Power required the reduction as a condition of Hoku
13 delaying the start of its contract in the summer of 2009.
14 Nevertheless, Idaho Power presumably would have been able
15 to serve the load if Langley Gulch were available when
16 originally scheduled. Now, with the delayed online date,
17 Idaho Power will lose the revenue it would have otherwise
18 received from Hoku. Depending on the cost Idaho Power
19 would have incurred to serve Hoku during these months,
20 Idaho Power could either make money or lose it due to
21 Hoku' s reduced load.
22 Q.Earlier you discussed the Commitment Estimate
23 and all of the cost elements that compose it. Were all
24 of the cost elements that are included in Idaho Power's
25 proposed Commitment Estimate included in the Benchmark
CASE NO. IPC-E-09-03
06/19/09
STERLING, R (Di) 75
STAFF
1 Resource proposal that was scored by the Evaluation Team?
2 A.No, not all of the costs were included.
3 Q.Please describe how the Commitment Estimate is
4 different than the Benchmark Resource proposal cost.
5 A.The Commitment Estimate includes several costs
6 and contingencies that were added after the Benchmark
7 Resource proposal was selected. Generally, those costs
8 that were added are the items listed on lines 36-38 and
9 lines 41-47 of Exhibit No. 108.
10 Q.Do you believe it was appropriate to add costs
11 to the Commitment Estimate that were not included in the
12 Benchmark Resource bid after the Benchmark Resource
13 proposal was chosen as the winning bid?
14 A.In some cases it was appropriate because it was
15 clear that some costs that were Idaho Power's
16 responsibility would be added to every bid if chosen.
17 However, in other cases, while I believe the costs are
18 likely to be incurred, I think they should have been
19 included in the Benchmark Resource proposal cost that was
20 actually considered in scoring the proposals.
21 Q.Did Idaho Power reevaluate the costs of the top
22 proposals and revise bid price scores based on the costs
23 included in the Commitment Estimate?
24 A.Yes, in response to a production request, Idaho
25 Power did compute revised price scores based on the
CASE NO. IPC-E-09-0306/19/09
STERLING, R (Di) 76
STAFF
1 Commitment Estimate amount. The results of that re-
2 scoring are shown on Exhibit No. 113. This section of
3 Staff's direct testimony contains confidential
4 information subject to protective agreement.
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CASE NO. IPC-E-09-0306/19/09
STERLING, R (Di) 77
STAFF
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13 Idaho Code § 61-541
Q.Idaho Power has requested approval of the
15 proposed Langley Gulch project under Idaho Code § 61-541.
16 Please discuss the requirements of this new legislation.
17 A.For reference purposes, I have included a copy
18 of Idaho Code § 61-541 as Exhibit No. 115. Idaho Code
19 § 61-541 provides that utilities may file an application
20 with the Commission for an order specifying in advance
21 the ratemaking treatments that shall apply when the costs
22 of the proposed facility are included in the utility's
23 revenue requirements. Among the ratemaking treatments
24 the Commission may apply are to specify the maximum
25 amount of costs that will be included in rates at the
CASE NO. IPC-E-09-0306/19/09
STERLING, R (Di) 78
STAFF
1 time without the utility having the burden of moving
2 forward with additional evidence of the prudence and
3 reasonableness of such costs . Effectively, this means
4 that the Commission may pre-approve some portion of the
5 proj ect 's expected costs.
6 Q.How would approval under Idaho Code § 61-541
7 differ from approval that has been given to prior new
8 generation projects?
9 A.Idaho Code § 61-541 provides that all amounts
10 approved under the legislation not be subj ect to further
11 prudence review. This is really no different than the
12 process recently used in approving Idaho Power's Evander
13 Andrews/Danskin and Bennett Mountain plants because a
14 CPCN for those plants was granted, along with a
15 commitment estimate, prior to project construction. Any
16 costs in excess of the commitment estimates approved in
17 those cases were required to be submitted to the
18 Commission for later approval.
19 Q.Do you believe Idaho Power has met the
20 requirements of Idaho Code § 61-541 with its filing in
21 this case?
22 A.Idaho Code § 61-541 requires the Commission in
23 reviewing the application to determine whether:
24 (i) The public utility has in effect a
25 commission-accepted integrated resource plan;
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 79
STAFF
1 (ii) The services and operations resulting
2 from the facility are in the public interest and will not
3 be detrimental to the provision of adequate and reliable
4 electric service;
5 (iii) The public utility has demonstrated that
6 it has considered other sources for long-term electric
7 supply or transmission;
8 (iv) The addition of the facility is
9 reasonable when compared to energy efficiency, demand-
10 side management and other feasible alternative sources of
11 supply or transmission; and
12 (v) The public utility participates in a
13 regional transmission planning process.
14 Assuming the Commission makes a ruling in this
15 case addressing whether the proposed proj ect is in the
16 public interest, I believe all of these requirements will
17 have been satisfied. Idaho Power does have an
18 acknowledged integrated resource plan on file with the
19 Commission. In the IRP, the utility considers other
20 sources of supply, including transmission, energy
21 efficiency and demand~side management. Idaho Power also
22 participates in multiple regional transmission planning
23 processes.
24 Q.If the Commission wishes to approve the
25 Company's request to construct Langley Gulch, must it do
CASE NO. IPC-E-09-03
06/19/09 STERLING, R(Di) 80
STAFF
1 so under Idaho Code § 61-541?
2 A.No, although Idaho Power has requested approval
3 under Idaho Code § 61-541, the Commission may accept,
4 deny of modify the proposed ratemaking treatment proposed
5 by the utility. In addition, the Commission may
6 determine the maximum amount of cost to be pre-approved
7 for inclusion in rates without the utility having the
8 burden of moving forward with additional evidence of the
9 prudence and reasonableness of such costs. The
10 Commission can require that amounts above the maximum be
11 subj ect to the usual requirements of demonstration of
12 prudence and reasonableness after the actual expenditures
13 have been made and the utility seeks to recover them in
14 rates.
15 Q.Do you believe preapproval of the Langley Gulch
16 project is warranted in this case?
17 A.Because it is likely that preapproval is
18 necessary in order for Idaho Power to obtain financing, I
19 believe that those portions of the estimated proj ect cost
20 that are known with a high degree of certainty be
21 preapproved under Idaho Code § 61-541. However, as I
22 explained earlier, I believe that some portions of the
23 proj ect' s estimated costs are not known with high enough
24 certainty to merit preapproval. Regardless, issuance of
25 CPCNs in the recent past have effectively provided
CASE NO. IPC-E- 09 - 0306/19/09
STERLING, R (Di) 81
STAFF
1 preapproval anyway.
2 TOTAL EXPECTED POWER COST
3 Q.What is the total expected power cost for the
4 proposed Langley Gulch plant?
5 A.This section of Staff's direct testimony
6 contains confidential information subject to protective
7 agreement.
8
9
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11
12 It is also extremely important to recognize
13 that the power cost computed for analysis purposes is
14 highly dependent on the cost of gas that is assumed in
15 the analysis. Idaho Power's analysis assumed a starting
16 gas price of $9.39 per MMBtu in 2012, increasing to
17 $15.55 per MMBtu in 2036. These estimates seem high
18 based on recent gas prices and forecasts, but prices
19 could turn out to be much different than assumed in the
20 analysis or that are forecasted today. It should also be
21 pointed out that the actual cost will ultimately also
22 depend on the actual capacity factor. The actual
23 capacity factor will vary from year to year and will be
24 driven by loads, weather, and gas and electric market
25 conditions. Higher capacity factors would lower the cost
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 82
STAFF
1 estimate while lower capacity factors would increase it.
2 The cost estimate I have included here is only intended
3 to be a rough indication of the total cost of energy
4 produced by the plant.
5 Q.Are avoided cost rates for PURPA contracts a
6 fair comparison to expected costs of the Langley Gulch
7 plant?
8 A.I do not believe avoided cost rates used for
9 PURPA QF contracts are a fair comparison to the cost
10 Idaho Power will pay for power produced by the Langley
11 Gulch plant. Although avoided cost rates are computed
12 based on a surrogate combined cycle combustion turbine
13 (SAR) very similar to Langley Gulch, assumptions aQout
14 how the SAR and the Langley Gulch plant would be operated
15 are much different. Avoided cost rate computations
16 assume that the SAR plant is not economically dispatched
17 and is instead operated at nearly its maximum achievable
18 capacity factor. This is consistent with PURPA QFs that
19 are not dispatchable and operate at as high a capacity
20 factor as they can. The Langley Gulch plant clearly will
21 be dispatchable, and will be operated only when it is
22 cost effective to meet load or make surplus sales.
23 Unlike the assumptions for the SAR or PURPA QFs, it will
24 not be operated when it is not needed or when it is not
25 profitable. Langley Gulch will almost certainly have a
CASE NO. IPC-E-09-03
06/19/09
STERLING, R (Di) 83
STAFF
1 capacity factor less than the capacity factor assumed for
2 the SAR. Consequently, there will be fewer hours over
3 which to spread fixed costs, resulting in a higher cost
4 per kWh than the PURPA avoided cost rate.
5 Q.How does the capital cost of the Langley Gulch
6 project compare to other CCCT alternatives?
7 A.Based on the $427 million Commitment Estimate
8 proposed by Idaho Power and Langley Gulch's 330 MW
9 nameplate capacity, the capital cost is $1,294 per kW.
10 By comparison, the current surrogate CCCT cost (which is
11 based on current costs as reported by the Northwest Power
12 and Conservation Council) used to establish the Idaho
13 published avoided cost rate is $l,313/kW. Idaho Power's
14 2009 IRP proposes to use approximately $1,350 per kW for
15 its assumption of new CCCT costs. PacifiCorp' s just
16 filed 2008 IRP shows new cost ranging from $1,180 to
17 $l,491/kW for comparable plants, and Avista' s nearly
18 completed 2009 IRP shows new CCCT capital costs of
19 approximately $1,050/kW. All cost listed here include an
20 assumed amount for AFUDC. A 2008 RFP issued by
21 PacifiCorp returned CCCT capital costs in the range of
22 $1,000 to $1, 300/kW.
23 Comparisons could also be made to recent
24 transactions by Avista and PacifiCorp. In Avista' s
25 current general rate case, Avista is seeking approval of
CASE NO. IPC-E-09-0306/19/09
STERLING, R (Di) 84
STAFF
1 a tolling agreement for the Lancaster CCCT plant in
2 Northern Idaho. Avista and its consultant separately
3 performed net present value and DCF analysis to compare
4 the Lancaster tolling agreement to other theoretical
5 tolling agreements based on capital construction costs of
6 existing regional CCCT resources. The analysis also
7 compared the agreement to expected costs to construct a
8 new CCCT in the region. The analyses show that the
9 tolling agreement is essentially equivalent to a Company
10 owned greenfield plant with a capital cost of about
11 $530/kW. Further analysis shows that the value of the
12 tolling agreement is equivalent to paying up to $677 /kW.
13 Another recent example of a comparable CCCT transaction
14 was the purchase by PacifiCorp of the existing 500 MW
15 Chehalis CCCT at a cost of approximately $610/kW. It
16 should be pointed out, however, that both the Lancaster
17 plant and the Chehalis plants were built several years
18 ago, so their costs may not be directly comparable to a
19 new plant built today like Langley Gulch.
20 FUL COSTS
21 Q.Idaho Power is requesting that the Proj ect ' s
22 prudently incurred costs for fuel, fuel storage, and fuel
23 transportation for recovery through the Company's
24 existing Power Cost Adjustment ("PCA") mechanism. Do you
25 agree that this would be appropriate?
CASE NO. IPC-E-09-0306/19/09
STERLING, R (Di) 85
STAFF
1 A.Yes, I do believe it would be appropriate to
2 include these costs in the PCA until the Company's next
3 general rate case when these costs can be normalized and
4 included in base rates. Once these costs are included in
5 base rates, only deviations from the normalized amounts
6 of these costs would be included in the PCA, subj ect to
7 the currently-approved 95-5 sharing percentages.
8 STAFF CONCLUSIONS
9 Q.Are you convinced that Idaho Power has
10 demonstrated a genuine need for the Langley Gulch plant?
11 A.Yes, I am convinced that a new base load power
12 plant is needed by Idaho Power beginning in 2012 and is
13 in the public interest. The proj ect is consistent with
15
the Company's acknowledged IRPs.Under the right set of
weather,load and hydro conditions,it could turn out
that the plant may not actually be needed as soon as
planned,but I believe it would be unacceptably risky to
14
16
17
18 delay the plant. I do not believe Idaho Power could have
19 pursued enough other alternatives that collectively could
20 eliminate or be an acceptable substitute for the Langley
21 Gulch plant.
22 Q.Do you believe that the request for proposals,
23 the criteria used by Idaho Power to evaluate bids, and
24 analysis of the bids was fair to all proposals?
25 A.I believe that the RFP was fair and that the
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 86
STAFF
1 evaluation criteria were reasonable for those proposals
2 that were submi t ted. However, I think Idaho Power should
3 have allowed build and transfer bids to be submitted.
4 Q.Do you recommend that the Commission issue to
5 Idaho Power a Certificate of Public Convenience and
6 Necessi ty to construct the Langley Gulch plant?
7 A.Yes, with reservations. I recommend that the
8 Commission approve a Commitment Estimate of $347.0
9 million plus actual AFUDC under Idaho Code § 61-541, and
10 that any costs incurred above this commitment estimate be
11 subject to review and approval by the Commission, with a
12 "Not to Exceed limit" of $376.6 million plus actual
13 AFUDC. If the Commission approves a Certificate of
14 Convenience and Necessity for the proj ect, I recommend
15 that Idaho Power be ordered to provide the Commission
16 wi th periodic progress reports during the construction
17 phase. The progress reports should cover proj ect costs,
18 construction progress, permitting milestones, legal
19 issues, problems encountered, or any other issues that
20 should be brought to the attention of the Commission.
21 Q. Do you have any additional comments?
22 A. Yes, I would like to comment on the timing in
23 this case. The need for a base load power plant has been
24 a primary element in the Company's IRPs for many years.
25 Even though the type of resource has changed since the
CASE NO. IPC-E-09-03
06/19/09
STERLING, R (Di) 87
STAFF
1 need for new base load resource was first identified and
2 it's exact timing has been a little uncertain, Idaho
3 Power has had ample time to prepare for the addition of a
4 new base load resource. Nevertheless, the Company in
5 this case has stated that it did not have time to prepare
6 detailed plans and specifications that would have been
7 needed in order to accept build and transfer proposals.
8 The Company has already signed agreements to purchase
9 maj or equipment and has signed an EPC contract for work
10 to commence in September, immediately following a
11 Commission order in this case. Work must begin in
12 September, according to the Company, in order to meet an
13 online date of December 2012.
14 By filing its application when it did and by
15 requiring such a tight schedule for initiation and
16 proj ect completion, Idaho Power has handcuffed the
17 Commission in its decision making. Idaho Power's urgency
18 has foreclosed the Commission from some decisions it
19 might otherwise wish to make. There are few or no
20 realistic alternatives that can be considered at this
21 point that will not lead to higher costs. Unless the
22 Commission approves the Company's requests in this case,
23 any other decisions would likely cause additional costly
24 delays. Staff does not believe that either ratepayers or
25 the Commission should be held hostage because of the
CASE NO. IPC-E-09-0306/19/09 STERLING, R (Di) 88
STAFF
1 Company's inability to plan and acquire resources in a
2 less time constrained manner.
3 Q.Does this conclude your direct testimony in
4 this proceeding?
5
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Yes, it does.A.
CASE NO. IPC-E-09-0306/19/09
STERLING, R (Di) 89
STAFF
Idaho Power Company .iuræ ¿uuö!
Table 10.Updated Near-Term Action Plan through 2010
Activity
2008
1. January - Issue RFP for 50-100 MW of geothermal
energy.
2. March - 170 MW Danskin expansion on-line.
3. March - Prepare and submit the 2007 Demand-
Side Management Annual Report.
4. April - Solicit expressions of interest from industrial
customers for CHP development.
5. April-Issue 2012 Baseload Resource RFP.
6. June - Submit 2008 IRP Update to the Idaho and
Oregon Commissions.
7. July - Begin the 2009 IRP process with the IRP
Advisory CounciL.
8. September - Announce successful bidder(s) in
the geothermal RFP process.
9. October - Bids due for the 2012 Baseload
Resource RFP.
2009
1. Conclude the 2012 Baseload Resource RFP process.
2. Continue DSM implementation plans with guidance
from the EEAG.
3. Continue working with. industrial customers on CHP
development opportunities.
4. Complete the 2009 IRP and submit to the Idaho and
Oregon Commissions in June 2009.
5. Make final commitments on 225 MW Hemingway-
Boardman Transmission Project.
6. Make final commitments on 500 kV Gateway West
Transmission Project.
7. Activities associated with the 2012 Baseload Resource
RFP depending on the outcome of the RFP process.
2010
1. Continue DSM implementation plans with guidance
from the EEAG.
2. Issue RFP for wind generation depending on current
level of PURPA wind development.
Table 11. 2006 IRP Preferred Portolio and Updated Portolio
2006 IRP Preferred Portolio Updated Portolio
Year Resource MW Year Resource MW
2008 Wind (2005 RFP)100 2008 Wind (2005 RFP)1 100
2009 Geothermal (2006 RFP)50 2009 Geothermal (2006 RFP)2 50
2010 CHP 50 2010 CHP (2008 Solicitation)3 50
2011 Geothermal (2008 RFP)4 50
2012 Wind 150 2012 Winds 150
2012 Transmission McNary-Boise 225 ~W::':~:=~~~dh''''~2013 Wyoming PuiverizedCoai7 250
2017 Regional IGCC Coal 250 2017 Regional IGCC Coal 250
2019 Transmission Lolc-IPC 60 2019 Transmission Lolc-fPC 60
2020 CHP 100 2020 CHP 100
2021 Geothermal 50 2021 Geothermal 50
2022 Geothermal 50 2022 Geothermal 50
2023 INL Nuclear 250 2023 INL Nuclear 250
Total Nameplate 1,585 Total Nameplate 1,635
Horizon Wind Energy Contract (100.65 MW) - Elkhom Valley Wind Project (on-line December 2007).
U.S. Geothermal Contract (45.5 MW) - Raft River #1 (13 MW on-line October 2007), Raft River #3 (6.5 MW) and Neal Hot Springs #1
(1.3 MW) and #2(13 MW) are under development.
In April 2008, Idaho Power began soliciting industral customers within its service area for expressions of interest in the development of
combined heat and power projects at existing industrial facilties. Depending on the level of interest, a fonnal RFP may be issued in late2008. '
An RFP for 56 to 100MW of geothennal energy was released in January 2008 to offset deficits resulting from PURPA contract
tenninations.
Actual quantity will depend on level of PURPA wind development.
Project was renamed once actual termination points were identified.
Due to escalating construction costs and continued uncertainty surrounding future GHG laws and regulations. Idaho Power has shifted its
focus from a conventional coal-fired resource to the development of a combined-cycle, natural gas resource located closer to its loadcenter in southern Idaho. .. Exhibit No. 101
Case No. IPC-E-09-3
Page 34 2008 Integrated Resour R. Sterling, Staff0('/19109
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Case No. IPC-E-09-3
R. Sterling, Staff
06/19/09 Page 1 of 4
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Case No. IPC-E-09-3
R. Sterling, Staff
06/19/09 Page 3 of 4
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Case No. IPC-E-09-3
R. Sterling, Staff
06/19/09 Page 4 of 4
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Case No. IPC-E-09-3
R. Sterlíng, Staff
06/19/09 Page 1 of 2
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Case No. IPC-E-09-3
R. Sterling, Staff
06119/09 Page 2 ~f 2
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Case No. IPC-E-09-3
R. Sterling, Staff
06/19/09 Page l of 2
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Case No. IPC-E-09-3
R. Sterling, Staff
06/19/09 Page 2,of2
9.0 Criteria Used for Scoring Qualified Proposals
This section briefly describes the criteria Idaho Power wil use to evaluate proposals
submitted in response to the RFP. The following tables summarize these criteria. For a
more detailed description of information that should accompany each proposal, see
Attchment G, "Required Proposal Information".
Factors
Price
Non-Price
A
Total:
Table 1. Evaluation Criteria
Descnptions
Pnce - This category captures all fixed and variable costs of the capacity and energy
delivered under the proposal. This evaluation wil include the nominal and present
wort costs of delivered power.
B
Project Development: This category captures the Respondents general background,
financing capability and ability to get the project completed on time.
1. Permitting status
2. Developer expenence
3. Project financing
4. Site Control
Project Characteristics: This category captures the physical charactenstics of any generation
resource necessary to support Respondent's proposaL. The evaluation critena for this
category generally addresses physical and operational charactenstics associated with the
production and delivery of power to Idaho Power.
1. ,Point-of-Delivery3
2. Resource base of energy project
3. O&M reliabilty characteristics
4, Extension option
5. Option to purchase after initial term
6. Impact on most severe single contingency
Product Charcteristics: This category scores how well the proposed product matches Idaho
Power's operational needs. The evaluation critena for this category generally address pnce
and performance along with the benefits of flexibility and optionality.
1. Guaranteed Availabilty Factor (GAF)
2. Compensation for failure to meet GAF
3. Flexibility, dispatch and load following capability
4. Contract term
5. Seasonal de-rating
6. Operational limitations
Project Location: This category captures the siting characteristics of any generation
resource(s) necessar to support Respondent proposed projects. Specifically: with EPA's
recent announcement to change the ozone stadard and the likelihood of Ada County being
listed as a non-attainment area, the Company is concerned about potential future operating
restrictions being placed on any projects located in the Treasure Valley. Idaho Power's
evaluation wil strictly scrutinize proposals that are supplied or supported by generation
resources planed to be built in Ada or Canyon counties; It wil also consider whether
community opposition to a plant wil delay the completion of necessar facilties.
Environmental: This category captures the environmental impacts of proposals, including
C02 emissions.
1. Land use
2. Water use and discharge
3. Fish and wildlife
4. Noise output
5. Emissions
Credit Factors and Financial Strength: This category captures the creditwortiness and
strength of the Respondent's financial sustainabilty.
Subtotal Total
60%
40%
8%
8%
8%
8%
3%
5%
100%
C
D
E
F
3 Please refer to Section 11.0 Transmission Interconnection
- 16 -Exhibit No. 106
Case No. IPC-E-09-3
R. Sterling, Staff
06119/09
Case No. IPC-E-09-3
Exhibit No. 107 prepared and sponsored by
Rick Sterling is Confidential and only
available to those persons who have signed
Protective Agreements
Case No. IPC-E..09-3
Exhibit No. 108 prepared and sponsored by
Rick Sterling is Confidential and only
available to those persons who have signed
Protective Agreements
Case No. IPC-E-09-3
Exhibit No. 109 prepared and sponsored by
Rick Sterling is Confidential and only
available to those persons who have signed
Protective Agreements
Case No. IPC-E-09-3
Exhibit No. 110 prepared and sponsored by
Rick Sterling is Confidential and only
available to those persons who have signed
Protective Agreements
Case No. IPC-E-09-3
Exhibit No. 111 prepared and sponsored by
Rick Sterling is Confidential and only
available to those persons who have signed
Protective Agreements
Case No. IPC-E-09-3
Exhibit No. 112 prepared and sponsored by
Rick Sterling is Confidential and only
available to those persons who have signed
Protective Agreements
Case No. IPC-E-09-3
Exhibit No. 113 prepared and sponsored by
Rick Sterling is Confidential and only
available to those persons who have signed
Protective Agreements
Case No. IPC-E-09-3
Exhibit No. 114 prepared and sponsored by
Rick Sterling is Confidential and only
available to those persons who have signed
Protective Agreements
RECEIVED
2009 JUL lOAM II: 23
IDAHO PUB,qÇ.. "., i
UTILITIES COMMib:)!Ut'\
To: Paries of Record
Commission Secretar
From: Commission Staff
Date: July 10, 2009
RE: Case No. IPC-E-09-03
Attached please find Exhibit No. 115 to the Direct Testimony of Staff witness Rick
Sterling previously filed on June 19,2009. Exhibit No. 115 was erroneously labeled as a
confdential exhibit.
Substitute pages wil be provided at the hearing on July 14,2009.
Please contact me if you have any questions at [phone].
I
Sixtieth Legislature
LEGISLATURE OF THE STATE OF IDAHO
First Regular Session - 2009
IN THE SENATE
SENATE BILL NO. 1123
BY STATE AFFAIRS COMMITTEE1 AN ACT
2 RELATING TO PUBLIC UTILITY RATES; AMENDING CHAPTER 5, TITLE 61, IDAHO
3. CODE, BY THE ADDITION OF A NEW SECTION 61-541, IDAHO CODE, TO
4 DEFIN A TERM, TO PROVIDE THAT PUBLIC UTILITY COMMISSION BINDING
5 RATEMAKING TREATMENTS ARE APPLICABLE WHEN COSTS OF A NEW
6 ELECTRIC GENERATION FACILITY ARE INCLUDED IN RATES, TO PROVIDE
7 PROCEDURES AND TO PROVIDE FOR RULES.
8 Be It Enacted by the Legislature of the State of Idaho:
9 SECTION 1. That Chapter 5, Title 61, Idaho Code, be, and the same is hereby amended
10 by the addition thereto of a NEW SECTION, to be known and designated as Section 61-541,
11 Idaho Code, and to read as follows:
12 61-541. BINDING RATEMAKING TREATMENTS APPLICABLE WHEN COSTS
13 OF A NEW ELECTRIC GENERATION FACILITY ARE INCLUDED IN RATES. (1) As
14 used in this section, "certificate" means a certificate of convenience and necessity issued under
15 section 61-526, Idaho Code.
16 (2) A public utilty that proposes to construct, lease or purchase an electric generation
17 facilty or transmission facilty, or make major additions to an electric generation or
18 transmission facilty, may file an application with the commission for an order specifying in
19 advance the ratemaking treatments that shall apply when the costs of the proposed facility are
20 included in the public utility's revenue requirements for ratemaking purposes. For purposes
21 of this section, the requested ratemaking treatments may include nontraditional ratemaking
22 treatments or nontraditional cost recovery mechanisms.
23 (a) In its application for an order under this section, a public utility shall describe the
24 need for the proposed facility, how the public utilty addresses the risks associated with
25 the proposed facilty, the proposed date of the lease or purchase or commencement of
26 construction, the public utility's proposal for cost recovery, and any proposed ratemaking
27 treatments to be applied to the proposed facility.
28 (b) For purposes of this section, ratemaking treatments for a proposed facilty include but29 are not limited to:
30 (i) The return on common equity investment or method of determining the return
31 on common equity investment;32 (ii) The depreciation life or schedule;
33 (ii) The maximum amount of costs that the commission wil include in rates at the
34 time determined by the commission without the public utilty having the burden
35 of moving forward with additional evidence of the prudence and reasonableness of36 such costs;
37 (iv) The method of handling any variances between cost estimates and actual38 costs; and
Exhibit No. 115
Case No. IPC-E-09-3
R. Sterling, Staff
06/19/09 Page 1 of 2
~
2
1 (V) The treatment of revenues received from wholesale purchasers of service
2 from the proposed facilty.
3 (3) The commission shall hold a public hearing on the application submitted by the
4 public utilty under this section. The commission may hold its hearing in conjunction with an
5 application for a certificate.
6 (4) Based upon the hearing record, the commission shall issue an order that addresses
7 the proposed ratemaking treatments. The commission may accept, deny or modify a proposed
8 ratemaking treatment requested by the utility. In determining the proposed ratemaking
9 treatments, the commission shall maintain a fair, just and reasonable balance of interests
10 between the requesting utilty and the utilty's ratepayers.
11 (a) In reviewing the application, the commission shall also determine whether:
12 (i) The public utiity has in effect a commission-accepted integrated resource plan;
13 (ii) The services and operations resulting from the facilty are in the public
14 interest and wil not be detrimental to the provision of adequate and reliable15 electric service;
16 (iii) The public utilty has demonstrated that it has considered other sources for
17 long-term electric supply or transmission;
18 (iv) The addition of the facilty is reasonable when compared to energy effciency,
19 demand-side management and other feasible alternative sources of supply or20 transmission; and
21 (v) The public utilty participates in a regional transmission planning process.
22 (b) The commission shall use its best efforts to issue the order setting forth the
23 applicable ratemaking treatments prior to the date of the proposed lease, acquisition or
24 commencement of construction of the facility.
25 (c) The rate making treatments specified in the order issued under this section shall be
26 binding in any subsequent commission proceedings regarding the proposed facilty that is
27 the subject of the order, except as may otherwise be established by law.
28 (5) The commission may not require a public utility to apply for an order under this
29 section.
30 (6) The commission may promulgate rules or issue procedural orders for the purpose of
31 administering this section.
Exhibit No. 115
Case No. IPC-E-09-3
R. Sterling, Staff
06/19/09 Page 2 of 2
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 10TH DAY OF mLY 2009,
SERVED THE FOREGOING NON-CONFIDENTIAL EXHIBIT NO. 115 OF RICK
STERLING'S DIRECT TESTIMONY, IN CASE NO. IPC-E-09-03, BY ELECTRONIC
MAIL AND MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L KLINE
LISA D NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: bkline(fidahopower.com
Inordstrom(fidahopower.com
PETER J RICHARDSON
RICHARDSON & O'LEARY
515 N 17TH STREET
PO BOX 7218
BOISE ID 83702
E-MAIL: peter(frichardsonandolear.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: dreadingrfmindspring.com
KEN MILLER
CLEAN ENERGY PROGRAM DIRECTOR
SNAKE RIVER ALLIANCE
PO BOX 1731
BOISE ID 83701
E-MAIL: kmiller(fsnakeriverallance.org
ANTHONYYANKEL
29814 LAK ROAD
BAY VILLAGE OH 44140
E-MAIL: tony(fyanel.net
ERIC L. OLSEN
RACINE, OLSON, NYE, BUDGE
& BAILEY, CHARTERED
PO BOX 1391
POCATELLO ID 83204-1391
E-MAIL: elorfracinelaw.net
BETSY BRIDGE
IDAHO CONSERVATION LEAGUE
710 N SIXTH ST (83702)
POBOX 844
BOISE ID 83701
E-MAIL: bbridgerfwildidaho.org
SUSAN K. ACKERMAN
9883 NW NOTTAGE DR
PORTLAND OR 97229
E-MAIL: susan.k.ackermanrfcomcast.net
BRAD M. PURDY
ATTORNEY AT LAW
2019 N. 17TH STREET
BOISE, ID 83702
E-MAIL: bmpurdyrfhotmail.com
1 CERTIFICATE OF SERVICE
ELECTRONIC COPIES ONLY
ROBERT KAHN
E-MAIL: rkahrfnippc.org
~~1SECRETA~ m
2 CERTIFICATE OF SERVICE
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 19TH DAY OF JUE 2009,
SERVED THE FOREGOING DIRECT TESTIMONY OF RICK STERLING, IN
CASE NO. IPC-E-09-3, BY ELECTRONIC MAIL AND MAILING A COPY THEREOF,
POSTAGE PREPAID, TO THE FOLLOWING:
BARTON L KLINE
LISA D NORDSTROM
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
(CONFIDENTIAL INFORMATION)
E-MAIL: bkline(iidahopower.com
Inordstrom(iidahopower .com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
(CONFIDENTIAL INFORMATION)
E-MAIL: dreading(imindspring.com
ANTHONY YANKEL
29814 LAK ROAD
BAY VILLAGE OH 44140
(NON-CONFIDENTIAL INFORMATION)
E-MAIL: tony(iyanel.net
BETSY BRIDGE
IDAHO CONSERVATION LEAGUE
710 N SIXTH ST (83702)
PO BOX 844
BOISE ID 83701
(NON-CONFIDENTIAL INFORMATION)
E-MAIL: bbridge(iwildidaho.org
PETER J RICHARDSON
RICHARDSON & O'LEARY
515 N 17TH STREET
PO BOX 7218
BOISE ID 83702
(CONFIDENTIAL INFORMATION)
E-MAIL: peter(irichardsonandolear.com
KEN MILLER
CLEAN ENERGY PROGRAM DIRECTOR
SNAKE RIVER ALLIANCE
PO BOX 1731
BOISE ID 83701
(NON-CONFIDENTIAL INFORMATION)
E-MAIL: kmiler(isnakeriverallance.org
ERIC L. OLSEN
RACINE, OLSON, NYE, BUDGE
& BAILEY, CHARTERED
PO BOX 1391
POCATELLO ID 83204-1391
(NON-CONFIDENTIAL INFORMATION)
E-MAIL: elo(iracinelaw.net
SUSAN K. ACKERMAN
9883 NW NOTTAGE DR
PORTLAND OR 97229
(CONFIDENTIAL INFORMATION)
E-MAIL: susan.k.ackerman(icomcast.net
1 CERTIFICATE OF SERVICE
BRAD M. PURDY
ATTORNEY AT LAW
2019 N. 17TH STREET
BOISE, ID 83702
(NON-CONFIDENTIAL INFORMATION)
E-MAIL: bmpurdy(ßhotmail.com
ELECTRONIC COPIES ONLY
ROBERT KAHN
(NON-CONFIDENTIAL INFORMATION)
E-MAIL: rkah(ßnippc.org
~~SECRETARY~~
2 CERTIFICATE OF SERVICE