20090702Porter Rebuttal.pdf

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IDAHO Pl ii::tir'UTILITIES COMM'ŠSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR A
CERTIFICATE OF PUBLIC CONVENIENCE
AND NECESSITY FOR THE LANGLEY
GULCH POWER PLANT.
CASE NO. IPC-E-09-03
I DAHO POWER COMPANY
DIRECT REBUTTAL TESTIMONY
OF
VERNON PORTER
INFORMTION SUBJECT TO THE
PROTECTIVE AGREEMENT
HAS BEEN DELETED FROM THIS DOCUMNT
1 Q.Would you please state your name, business
2 address, and present occupation?
3 A.My name is Vernon Porter and my business
4 address is 1221 West Idaho Street, Boise, Idaho. I am the
5 General Manager of Power Production at Idaho Power.
6 Q.Are you the same Vernon Porter that
7 submitted direct testimony in this proceeding?
8 A.Yes I am.
9 Q.What is the purpose of your direct rebuttal
10 testimony in this proceeding?
11 A.I will provide testimony explaining why the
12 Company decided not to consider bids involving build-and-
13 transfer arrangements in the RFP at issue.I will also
14 provide additional information concerning the Commitment
15 Estimate and Staff's proposed adjustments to the Commitment
16 Estimate.
1 7 BUILD-AN-TRASFER ARGEMNTS
18 Q.On page 36 of his direct testimony, Staff
19 witness Rick Sterling opines that Idaho Power Company's
20 ("Idaho Power" or "Company") decision to accept only PPA
21 and tolling agreement proposals, but not build-and-transfer
22 proposals, may have resulted in the Company not receiving
23 other potentially competi ti ve bids. Mr. Sterling is also
24 cri tical of what he characteri zes as the Company's
PORTER, DI REB 1
Idaho Power Company
1 justification for not accepting build-and-transfer
2 proposals, namely that the Company lacked sufficient time
3 to develop detailed design specifications necessary for
4 build-and-transfer arrangements. Was the Company's
5 decision not to accept build-and-transfer proposals due
6 only to the lack of sufficient time to develop detailed
7 specifications?
8 A.No. While developing sufficiently detailed
9 specifications to accommodate a build-and-transfer option
10 in a RFP is difficult, that is not the principal reason for
11 the Company's decision not to seek build-and-transfer
12 proposals in the RFP. The primary reason for not accepting
13 build-and-transfer proposals is based on the Company's
14 belief that build-and-transfer arrangements present risks
15 to the Company and, ultimately , its customers that are
16 significantly greater than the risks associated with Power
17 Purchase Agreements (" PPAs") or tolling agreements,
18 particularly in the case of a baseload resource of the size
19 and complexity of a combined cycle gas plant.
20 As noted in my direct testimony, the Company's own
21 experience with build-and-transfer generation projects, and
22 its observations of build-and-transfer combined cycle
23 plants currently operated by other utilities, substantiates
24 the Company's belief that build-and-transfer arrangements
PORTER, DI REB 2
Idaho Power Company
1 pose unacceptable risk to the utility and its customers in
2 the case of a combined cycle baseload resource.
3 Specifically, the lesson learned from the Company's own
4 experiences and from its observations is that a utili ty
5 should not be required to operate a generating plant unless
6 the utili ty participa tes integrally in the design and
7 construction of the plant.
8 Prior to the Company's issuance of the 2008 Baseload
9 Request for Proposal ("RFP"), Company representatives
10 inspected several combined cycle plants and interviewed
1 1 their operational personnel. Among the plants visited was
12 a combined cycle plant builtin Utah pursuant to a build-
13 and-transfer arrangement. In the unanimous opinion of all
14 team members who visited this plant, the plant evidenced
15 numerous design defects that undermined the efficient and
16 economical operation and maintenance of the plant, delayed
17 the planned commercial operation of the plant, and caused
18 significant proj ect cost overruns. In the Company's
19 judgment, these design defects likely resulted from a
20 di vergence of interest between the owner and the developer.
21 While the owner desires a design that optimizes the plant's
22 efficiency and economical operation over the life of the
23 plant, the developer is incented to reduce its costs and,
24 correspondingly, maximize its profit. These incentives may
PORTER, DI REB 3
Idaho Power Company
1 result in the developer minimizing expenditures necessary
2 to achieve an optimal long-term design, or minimizing
3 quality control expenditures necessary to assure that the
4 plant is builtin accordance with applicable design and
5 construction specifications.
6 Q.Has the Company actually encountered defects
7 in a generation facility that it acquired pursuant to a
8 build-and-transfer arrangement?
9 A.Yes. In the case of Idaho Power's Bennett
10 Mountain plant, the failure of the developer to fulfill its
11 contractual obligations during construction contributed to
12 the creation of a latent defect that manifested itself
13 after commercial operation and lead to a prolonged outage
14 and direct repair expense in excess of $ 14 million.
15 Specifically, a contractor failed to install the bolts in
16 the turbine's air inlet plenum in accordance with specific
17 construction specifications. The developer failed to
18 detect the improper installation and a bolt ultimately
19 dislodged, was ingested in the turbine, and caused
20 extensi ve damage to the turbine. Although Idaho Power
21 considered the developer' s position to be commercially
22 unreasonable and legally untenable, the developer of the
23 Bennett Mountain plant disavowed any contractual obligation
24 to reimburse Idaho Power for the repair expense. The
PORTER, DI REB 4
Idaho Power Company
1 developer argued that its warranty obligations to the
2 Company had expired.
3 Q.Even in a self-build arrangement, don't the
4 utili ty' s contracts with the EPC contractor and the
5 equipment suppliers have warranties of finite duration?
6 A.Yes, but there are fundamental differences
7 between the contractual terms in a self-build arrangement
8 and a build-and-transfer arrangement. Foremost, in a self-
9 build arrangement, the utility has a direct contractual
10 relationship with the engineering, procurement, and
11 construction ("EPC") contractor and with the maj or
12 equipment suppliers. In a build-and-transfer arrangement,
13 the utility has a direct contractual relationship with only
14 the developer, and the developer in turn has contractual
15 relationships with the equipment suppliers and EPC
16 contractor. A utility's direct contractual relationship
17 with the EPC contractor and with the equipment suppliers
18 affords the utility the opportunity to negotiate directly
19 with the contractor and equipment suppliers, and to secure
20 contractual terms with these counter-parties that optimize
21 the design of the plant for long-term operation, and permit
22 the utility to observe that the plant is constructed in
23 accordance with applicable specifications. Even during
24 construction, the utility has the ability to negotiate
PORTER, DI REB 5
Idaho Power Company
1 contractual change orders that are necessary to optimize
2 plant design. Because a utility must operate the plant
3 during the expected life of the plant, as compared to a
4 developer whose contractual obligations relating to the
5 plant continue only for a finite warranty period, the
6 utility is much more likely to offer engineering input and
7 authorize design changes and to monitor quality control
8 during construction than it could under a build-and-
9 transfer arrangement.
10 Q.What is the difference between detailed
11 specifications necessary for a RFP that invites build-and-
12 transfer proposals and the bid criteria developed in the
13 subj ect RFP?
14 A.The bid criteria necessary to evaluate bids
15 for a self-build combined cycle plant, PPA, or tolling
16 agreement are not as detailed as the specifications
17 necessary for a request for proposal that invites build-
18 and-transfer proposals. Bid criteria necessary to support
19 PPA or tolling agreement proposals can be relatively more
20 general because the bidder assumes risk associated with
21 design and construction. Detailed design criteria are,
22 however, a necessary component of a request for proposal
23 inviting bids for build-and-transfer projects of the
24 complexity of a combined cycle plant. The only means by
PORTER, DI REB 6
Idaho Power Company
1 which the utility can ensure that the plant is designed and
2 constructed in a manner that assures that the plant is
3 capable of being operated and maintained in a cost-
4 effective and reasonable manner is by including in the
5 contract with the developer very detailed engineering and
6 construction specifications. This, in turn, requires that
7 the request for proposal inviting build-and-transfer bids
8 contain these detailed specifications, or the evaluation of
9 competing bids could become extremely complicated and
10 subjective. The detailed specifications necessary to
11 evaluate build-and-transfer proposals are much more
12 specific and include the detailed identification, layout,
13 and design of plant and equipment for optimal plant
14 operation, maintenance, and operator safety.
15 Wi th regard to the Baseload RFP, the self-build team
16 was not required to prepare detailed specifications prior
17 to submitting a bid. The team did work with the EPC
18 contractor during the proposal phase to determine design
19 criteria, plant layout, etc. However, detailed design
20 specifications for the Langley Gulch plant will not be
21 completed until well after the IPUC issues a Certificate of
22 Public Convenience and Necessity, should it elect to do so.
23 Q.Can the development of a detailed design
24 specification that all bidders must follow in responding to
PORTER, DI REB 7
Idaho Power Company
1 an RFP eliminate the risks associated with a build-and-
2 transfer arrangement?
3 A.No. While having detailed design
4 specifications does reduce the design and construction
5 risks, they do not eliminate the risks. Moreover, detailed
6 design specifications in the case of a build-and-transfer
7 arrangement do not reduce the risks to the same level that
8 direct contractual relationships between the utility and
9 the EPC contractor and equipment suppliers reduce risk. In
10 a build-and-transfer relationship, by definition, the owner
11 must work through an intermediary - the developer - with
12 regard to design and construction matters. The owner has
13 no contractual authority to effectuate changes or
14 improvements in design or construction directly with the
15 parties responsible for design and construction - the
16 engineer, construction contractor, and equipment
17 manufacturer. This fact, in itself, reduces the owner's
18 authority, influence, and flexibility.
19 Moreover, the development of design specifications
20 in a competi ti ve RFP procurement that includes a build-and-
21 transfer option must occur before the RFP is distributed to
22 the potential bidders. Thus, in the case of a build-and-
23 transfer arrangement, the owner must develop specifications
24 with a high level of detail to reduce design and
PORTER, DI REB 8
Idaho Power Company
1 construction risk before the RFP is distributed to
2 potential bidders. As a result, the development has to be
3 done generically, and without any input from the engineer,
4 construction contractor, or equipment manufacturer that
5 will design and construct the proj ect and supply maj or
6 equipment.In the case of a self-build proj ect, the
7 utility has worked extensively with the engineer,
8 construction contractor, and equipment manufacturer even
9 before the self-build bid was submitted. If the self-build
10 option is selected, the interaction between the owner and
11 these parties continues as an iterative process through
12 completion of the proj ect.
13 Q.Staff witness Sterling characterizes the
14 Company's conclusion that it did not have time to develop a
15 detailed design that would have allowed the Company to
16 accept build-and-transfer proposals as "a weak excuse"
17 because a proj ect of this size and type was anticipated for
18 many years and required a long-lead time. He also
19 concludes that "much of the time Idaho Power may have
20 'saved' during the RFP stage by not preparing a detailed
21 project design will be made up later when detail design
22 work must be done before construction begins." What is
23 your response to Mr. Sterling's criticisms?
PORTER, DI REB 9
Idaho Power Company
1 A.Idaho Power did anticipate a proj ect of
2 Langley Gulch's size, just not this type. When the
3 decision was made in September 2007 to switch from a coal
4 to a natural gas plant due to difficulties with financing
5 and carbon risk, Idaho Power had to seriously retool its
6 planning in a short time frame to issue the RFP timely.
7 Taking the 6 months needed to create detailed
8 specifications for the RFP would have delayed the proj ect
9 past 2012, which the Company was not prepared to do.
10 Moreover, it does not appear that Mr. Sterling fully
11 appreciates the differences in complexity between the type
12 of detailed specification that the utility must create if
13 an RFP is going to accept build-and-transfer proposals and
14 the much less complex design work that is needed to submit
15 a proposal in an RFP.
16 Q.Is it reasonable to accept build-and-
17 transfer proposals in the absence of detailed design and
18 construction specifications developed prior to issuance of
19 the RFP?
20 A.No. For the reasons specified above, the
21 design and construction risks associated with build-and-
22 transfer proposals require that the proposals be submitted
23 in accordance with detailed specifications. Moreover, in
24 the absence of detailed specifications, the process of
PORTER, DI REB 10
Idaho Power Company
1 selecting a successful proposal becomes much more
2 subj ecti ve and difficult. Without detailed specifications,
3 various proposals would likely contain different design
4 cri teria, equipment quality, level of redundancy
5 incorporated in the basic design, adaptability of the
6 design and equipment layout to accommodate future
7 expansions, compatibility of control systems with Idaho
8 Power's existing systems, design features incorporated for
9 ease of operations, design features incorporated for ease
10 of maintenance, shop and warehouse space and features, and
11 specific design features to address extreme temperature
12 operation. These differences complicate an evaluation
13 process not only by increasing the number of potential
14 options but also by necessitating subj ecti vi ty in
15 evaluating the merit of various options.
16 Idaho Power believes that by limiting the RFP to PPA
17 proposals, tolling agreement proposals, and a self-build
18 benchmark proposal, the complications associated with, and
19 the subjectivity of, the evaluation process are reduced.
20 In this approach, each bidder is responsible for operating
21 and maintaining their proposed proj ect for the duration of
22 the agreement. Subsequently, each bidder will incorporate
23 their estimate of the costs for operating and maintaining
PORTER, DI REB 11
Idaho Power Company
1 their proj ect and these costs are ultimately reflected in
2 the price they bid.
3 The RFP Team's consultant, R. W. Beck, concurred
4 that "the evaluation process could become extremely
5 complicated and somewhat subj ecti ve" if build-and-transfer
6 options were permitted without including a detailed design
7 specification in the RFP.(See Exhibit No. 11,
8 correspondence from R. W. Beck dated April 14, 2009.)
9 Q.Did time permit the development of detailed
10 design and construction specifications in the RFP process?
11 A.No . Given (i) the decision to accelerate
12 the in-service date to 2012, (ii) the information obtained
13 regarding critical equipment manufacturing lead times, and
14 (iii) the previously mentioned differences in proj ect
15 design, the Company did not have enough time to prepare
16 detailed design and construction specifications and release
17 the RFP in time to meet the 2012 on-line date.
18 In early September 2007, the Company was still
19 exploring the possibility of satisfying its 2013 baseload
20 generation resource need by developing a coal-fired
21 generation facility. In mid-September 2007, the decision
22 to no longer pursue coal-fired generation and shift to gas-
23 fired resources was finalized. The Company then looked at
24 gas generation resource al ternati ves, visited various
PORTER, DI REB 12
Idaho Power Company
1 combined cycle proj ects, started investigating potential
2 si tes, met with potential EPC contractors, and considered
3 developing a competitively bid self-build resource not
4 unlike the process the Company followed when it was
5 considering an expansion of the Bridger proj ect. The
6 Company ultimately concluded that for a gas-fired resource,
7 issuance of a request for proposals would allow the Company
8 to access multiple experienced gas-fired resource
9 developers. In March 2008, the Company assembled an RFP
10 Team to issue an RFP requesting that independent power
11 producers submit bids for the 2012 baseload resource and
12 that the Company submit a Benchmark Resource proposal.
13 That RFP was issued April 1, 2008, requiring that
14 bids be submitted no later than October 17, 2008. The RFP
15 called for the selected resource to be capable of
16 commercial operation with a high degree of operating
17 availabili ty by June 1, 2012. Although the Benchmark
18 Resource team had performed some preliminary work relative
19 to the development of a benchmark resource before the
20 Company elected to issue the RFP - identifying potential
21 sites suitable for location of the resource, submission of
22 requests for transmission studies, review of existing
23 generation facilities, and preparation of a draft equipment
24 RFP - the preparation of a bid by the Benchmark Resource
PORTER, DI REB 13
Idaho Power Company
1 team did not begin until after the RFP was issued on April
2 1, 2009.Indeed, the preparation of a bid could not begin
3 until the RFP bid criteria were known. The preparation of
4 the Benchmark Resource team's bid was not completed until
5 just prior to the bid submission deadline of October 17,
6 2008.
7 Q.How much time would have been necessary to
8 prepare detailed design specifications for a build-and-
9 transfer arrangement?
10 A.The Company estimates that it would have
11 taken somewhere between four and six months to prepare
12 detailed design and construction specifications. The four
13 to six month estimate includes time for the Company to
14 select the design engineer, for the design engineer to
15 produce the initial draft specifications, for Idaho Power
16 to review and comment on draft specifications, and for the
17 design engineer to finalize the specifications prior to
18 releasing it for use in the RFP.
19 Q.Even if build-and-transfer projects had been
20 permitted in response to the RFP, do you believe a build-
21 and-transfer option would have provided the Company with a
22 more economical resource option.
23 A.No. Aside from the inherent risks
24 associated with build-and-transfer options noted above,
PORTER, DI REB 14
Idaho Power Company
1 build-and-transfer options involve a significant expense
2 not inherent in the cost of a self-build resource or even
3 in a PPA or tolling arrangement - the developer's fee. In
4 a build-and-transfer arrangement, the proj ect owner must
5 assume not only the costs of design, construction, and
6 equipment but also must pay the developer a substantial fee
7 for its work associated with the proj ect. This additional
8 cost element makes it unlikely that a build-and-transfer
9 proj ect would be economically competi ti ve with other
10 resource options.
11 INCENTIVE FOR JUy 1, 2012, IN-SERVICE DATE
12 Q.Several witnesses for the Intervenors have
13 suggested that the Company's decision to delay commencement
14 of construction by six months, and correspondingly extend
15 the Langley Gulch in-service date to December 1, 2012,
16 evidenced the Company's recognition that the plant was not
17 needed to serve expected load in the summer of 2012. Do
18 you agree?
19 A.No. As discussed in the testimony of Mr.
20 Bokenkamp, the Company's current system loads, and its
21 proj ected future system loads, consistently have evidenced
22 the need for the Langley Gulch Plant to be available to
23 meet load in the summer of 2012.
PORTER, DI REB 15
Idaho Power Company
1 Q.In testimony you offered in opposition to
2 the Intervenors' Petition to Stay you referenced the
3 Company's discussions with the EPC contractor to target a
4 July 1, 2012, in-service date for the Langley Gulch Plant.
5 What is the status of those discussions?
6 A.In order to satisfy expected load with
7 greater certainty and lower cost in the summer of 2012,
8 Idaho Power has reached an agreement in principal with the
9 EPC contractor to target an in-service date of July 1,
10 2012. Specifically, the Company and the EPC Contractor
11 have agreed that if the plant is substantially constructed
12 and in-service by July 1, 2012, the Company will pay the
13 contractor $750,000 as an early completion incentive. For
14 each day prior to July 1, 2012, that the plant is in-
15 service, the Company will pay an additional incentive of
16 $10,000 up to $150,000 (i.e., up to fifteen days prior to
17 July 1, 2012). In addition, the Company has agreed to pay
18 up to $100,000 to the contractor to assist in securing
19 timely delivery of a critical path piece of equipment, the
20 steam turbine.
21 Q.Does Idaho Power expect to seek rate
22 recovery of these early incentive payments?
23 A.Yes. If the plant is in-service to meet
24 summer peak loads, the Company's customers should benefit
PORTER, DI REB 16
Idaho Power Company
1 from the increased reliability the plant provides and the
2 avoidance of more expensive market purchases necessary to
3 meet expected load. In addition, accelerating the on-line
4 date will result in an estimated savings of $4.7 million in
5 reduced AFUDC.
6 Q.Does the EPC contractor expect to meet a
7 July 1, 2009, in-service date?
8 A.We are advised by the EPC contractor that if
9 the preiiminary permitting and equipment delivery benchmark
10 dates are met, we should expect that the plant will be in
11 service by July 1, 2012.
12 COST OF PROJECT DELAY
13 Q.Mr. Sterling has testified that the
14 Company's decision to slide the proj ect schedule six
15 months, and the resultant delay to December 1, 2012, of the
16 in-service date, resulted in a $6.8 million increase in the
17 cost of the proj ect.(Sterling Direct, pp. 17-18.) Mr.
18 Sterling then suggests that the Company's shareowners,
19 rather than its customers, should bear this cost, and Mr.
20 Sterling recommends that the amount be excluded from any
21 commi tment estimate approved by the Commission.(Id., p.
22 68. )Do you agree with Mr. Sterling's conclusions?
23 A.No. I respectfully disagree with Mr.
24 Sterling for two reasons. First, Mr. Sterling is incorrect
PORTER, DI REB 1 7
Idaho Power Company
1 in his conclusion that the delay increased the project
2 costs by $ 6.8 million. Second, the decision to delay the
3 proj ect was not made to benefit or protect shareholders.
4 It was made as a result of the maj or dislocations in the
5 financial markets. As a result of these changed financial
6 conditions, the Company concluded it would be in the
7 customers' interest to delay the on-line date to see if the
8 Company could obtain ratemaking assurances that would allow
9 the Company to finance the proj ect using traditional
10 utility financing techniques. If it can finance in this
11 manner, the Company will save customers a substantial
12 amount of money as compared to the costs it would incur
13 under the other bids. In my mind, this is definitely a
14 customer benefit and should not be used to penalize
15 shareholders.
16 Q.What are the actual costs associated with
17 the delay?
18 A.The Commitment Estimate, Staff Exhibit 108,
19 identifies certain contingencies that total $ 6.8 million
20 (Ll. 36-38). Specifically:
21
22
23
24
25
Labor Escalation
(2% of the labor component)$/ / / / / / / / / /
Material Escalation $/ / / / / / / / / /
PORTER, DI REB 18
Idaho Power Company
1
2
3
4
5
Price Escalation of the Gas line,
Water line, and
Inj ection Wells $/ / / / / / / / / /
Total:$ 6,800,686
6 However, only the $////////////// of the $6.8 million
7 associated with potential labor escalation is directly tied
8 to the six-month delay of engineering and equipment
9 procurement.
10 / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / // / / / // /
11 / / / / / / / / / // / // / // / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / /
12 / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / //
13 / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / /
14 / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / /
15 / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / /
16 / / / / // / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / /
17 / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / /
18 / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / /
19 ///////////////////
20 The contingencies related to material price
21 escalation and price escalation of the gas line, water
22 line, and inj ection wells could theoretically be impacted
23 by the six-month delay; however, they are more
24 realistically tied to the escalation risk between project
25 bidding and the construction period ending in 2012. A
26 commitment estimate associated with these items would have
PORTER, DI REB 19
Idaho Power Company
1 included the same contingency even if the on-line date of
2 the proj ect had not been delayed.
3 Q.Is it fair to ask customers to be
4 responsible for costs associated with the delay?
5 A.Yes, customers rather than shareowners will
6 obtain a substantial benefit if the Company can obtain
7 ratemaking assurances and thereby finance the proj ect and
8 preserve the lower cost of the Langley Gulch proj ect. As a
9 result, it is fair to ask customers to bear the risk
10 associated with the potential labor cost increases during
11 the six month delay period. To do otherwise would
12 discourage the Company from considering cost-effective
13 options that would benefit customers but expose it to
14 disallowance. The decision to delay the start of
15 engineering and equipment procurement was made because of
16 the potential inability to obtain financing for the proj ect
17 without ratemaking assurances from the Commission. It was
18 a prudent decision to secure agreement of the EPC
19 contractor to maintain the viability of the proj ect while
20 the Commission considered whether to issue a certificate.
21 Shareowners should not be penalized for a prudent decision
22 that will benefit the customers.
23 The Commitment Estimate contingencies are for those
24 components of the overall price of the project where the
PORTER, DI REB 20
Idaho Power Company
1 Company continues to assume price risk. Given high
2 volatility in the commodities markets, it is appropriate
3 that a reasonable contingency be included in the Commitment
4 Estimate.
5 HA CAP/SOFT CA
6 Q.Mr. Sterling recommends adoption of certain
7 "caps," specifically a "soft cap" and a "hard cap,"
8 relating to certain items in the proposed Commitment
9 Estimate. Do you agree with this approach?
10 A.No. For the reasons specified in Mr. . Gale's
11 rebuttal testimony, I do not.
12 Q.Even if the Commission were to adopt Mr.
13 Sterling's recommendations regarding caps, do you agree
14 with his methodology in applying those caps?
15 A.No. There are a number of errors or
16 inequi ties in the manner in which Mr. Sterling recommends
17 application of the caps. Specifically:
18 1.Labor Escalation Costs. For the
19 reasons speci fied above (see, "Cost of Proj ect Delay"),
20 labor escalation costs of $// / / / / / / / / / / should be included
21 wi thin the Soft Cap on line 36.
22 2.Air Permitting. Staff recommends that
23 air permitting costs be included, in full, within the Soft
24 Cap column (p. 66, 11. 14-18). However, Staff's testimony
PORTER, DI REB 21
Idaho Power Company
1 shows no allotment under the Soft Cap. Exhibit No. 109, 1.
2 21. ) This is an apparent mathematical error and air
3 permitting costs should be fully recoverable.
4 3.Contingencies for IPC's Retained Price
5 Risk. The Company retains price escalation risk through
6 the entire construction period on certain components in the
7 Commi tment Estimate. These components include (1) price
8 escalation on materials, estimated at $// / / / / / / / / and (2)
9 gas pipeline, water pipeline, and the inj ection well design
10 and construction, estimated at $// / / / / / / / . The total
11 commitment contingency added was $ / / / / / / / / /. These
12 contingencies were added for price escalation risk of
13 materials over the duration of the proj ect (from the 2008
14 bid to 2012 completion). These materials include all
15 components of the project, including the material risk
16 component of the EPC Contract in which Idaho Power retains
17 price risk - construction power to the site,
18 communications, vehicles, Idaho Power supplied equipment,
19 etc. The commodities markets have been and are currently
20 very volatile and allowing Idaho Power a contingency is
21 reasonable as a cost of doing business. As a result, the
22 costs shown on lines 37 and 38 of the Commitment Estimate,
23 Staff Exhibit No. 118, should be included in Mr.
24 Sterling's Soft Cap as a fully recoverable cost.
PORTER, DI REB 22
Idaho Power Company
1 4.RFP Team Expenses. Staff recommends
2 that the RFP Team Expenses shown on Line 43, Staff Exhibit
3 No. 109, be excluded from recovery from the Soft Cap and
4 Hard Cap columns. Staff contends that these costs would
5 have had to be included in all proposals as part of the
6 evaluation process and should not be allowed to be added to
7 the Commitment Estimate after the winning the bid.
8 However, I believe Staff comes to that conclusion based on
9 the mistaken impression that these are costs incurred by
10 the Benchmark Resource team. They are not. These are the
11 expenses incurred by the RFP evaluation team, and
12 consequently, these costs should be recoverable as an
13 expense directly related to conduct of an RFP.
14 5.Start-Up Fuel Costs. Under normal
15 utility accounting practice, start-up fuel, net of the
16 market value of the energy generated by the start-up fuel,
17 is capitalized and included in the rate base for the plant.
18 In this case, Staff recommends that start-up test fuel
19 costs be excluded from the Soft Cap and Hard Cap. Mr.
20 Sterling acknowledges that the second lowest bid, bidder B,
21 advised the Company that its bid did not include start-up
22 fuel costs and it would expect the Company to provide the
23 fuel at its expense. In any event, start-up fuel expense
24 is a necessary cost of putting the plant in service and,
PORTER, DI REB 23
Idaho Power Company
1 consistent with normal utility accounting practice, is a
2 legi timate item for inclusion in the Commitment Estimate.
3 6.Transmission Upgrades. Mr. Sterling
4 recommends that none of the transmission upgrades contained
5 in the Commitment Estimate should be included in either his
6 Soft Cap or Hard Cap. He makes this recommendation because
7 these upgrades are not required as part of the Langley
8 Gulch proj ect and, in his view, Idaho Power should be
9 required to demonstrate the prudence of an investment in
10 these upgrades in a future general rate case.
11 The transmission upgrades Mr. Sterling is referring
12 to total $11111111111, including AFUDC (Exhibit No. 109, 1.
13 45), consisting of two components:(1) the incremental
14 cost of $~~ I I I I I I to loop the Ontario-Caldwell 230 kV line
15 in and out of the Langley Gulch plant in lieu of building
16 just a tap connection and (2) the incremental cost of
17 $~~ I I I I I I I I I I to build the new 18 mile Langley Gulch-Wagner
18 Jct. 138 kV line using 230 kV construction standards. The
19 transmission cost listed in the Commitment Estimate column
20 is $111111111111. (Exhibit No. 109, 1. 51.) This is the
21 estimated cost to interconnect the Langley Gulch Power
22 Plant to Idaho Power's existing transmission system by
23 tapping the nearby Ontario-Caldwell 230 kV line (2.5 mile
24 tap) and building a new 18 mile Langley Gulch-Wagner Jct.
PORTER, DI REB 24
Idaho Power Company
1 line at 138 kV. These two lines provide the minimal
2 interconnections needed to meet the Idaho Power Network
3 Resource Study Criteria required by the RFP, whose
4 underlying principle that the transmission interconnection
5 of a new resource should be designed so that there should
6 be no loss of load or Idaho Power network resource
7 generation following an N-1 outage. Meeting this standard
8 is required from all parties seeking interconnection. It
9 is not discretionary.
10 Al though this $// / / million transmission integration
11 option meets the criteria established by the RFP, Idaho
12 Power's Transmission Department recommends that the
13 Ontario-Caldwell 230 kV line be looped into the plant
14 rather than just tapping it. This improves the
15 transmission overload situation following the loss of two
16 Brownlee East 230 kV lines and avoids the need to install a
17 Remedial Action Scheme to open the 230 kV tap following
18 this outage. The loop also eliminates the loss of the
19 entire Langley Gulch plant for the contingency where both
20 the Ontario-Caldwell 230 kV and the Langley Gulch-Wagner
21 Jct. -Caldwell 138 kV lines are lost (they are on the same
22 poles for 2 miles coming out of Caldwell). The additional
23 cost for this upgrade is $// / / / / / / / /. The loop also
24 provides the additional benefit of providing a reasonable
PORTER, DI REB 25
Idaho Power Company
1 connection to the grid in case the new Langley Gulch-
2 Wagner Jct. line is delayed. Since the 230 kV loop upgrade
3 directly benefits plant reliability, I believe its costs
4 should be included in the Soft Cap for the Langley Gulch
5 project.
6 The second upgrade entails building the new 18 mile
7 Langley Gulch-Wagner Jct. 138 kV line using 230 kV
8 construction standards. Load growth will eventually drive
9 the need for the upgrade to 230 kV. Constructing this line
10 at 230 kV standards now will be less expensive than re-
11 permi tting and rebuilding the line at a future date.I
12 believe the $ 1.8 million upgrade costs should be recovered
13 as part of the Langley Gulch proj ect and included in Mr.
14 Sterling's Soft Cap.
15 7.Remaining Items. Mr. Sterling
16 recommended that many of the components from Idaho Power's
17 Commitment Estimate be reduced in his Soft Cap proposal.
18 His proposed reductions (ranging from 5 percent to 50
19 percent) include the following items:
20 1.Water Right
21 2.Water Line Construction
22
23
3.Water Pump Station Property and
Pipeline Easement Property
24 4.Gas Line Construction
PORTER, DI REB 26
Idaho Power Company
1 S. Landscaping and Aesthetics
2 6. Vehicles & Equipment
3 7. Start-Up Expenses
4 8. IPC Supplied Equipment
5
6
9. Idaho Power Engineering Oversight
and Support
7 10. Gas Line Tap and Meter
8 11. SSR Study/Implementation
9 12. Transmission Cost
10 Idaho Power developed the cost estimates for these
11 components of the Proj ect based on (1) estimates from other
12 Idaho Power departments, (2) estimates from outside firms
13 with expertise in their respective areas, (3) actual costs
14 of equipment and material purchase, (4) reasonable labor
15 costs, and (5) established contract costs.These are
16 reasonable engineering estimates that reflect our best
17 estimate as to what it will cost to construct these aspects
18 of the proj ect.
19 The reductions suggested by Mr. Sterling are
20 unrealistic. Idaho Power cannot build the proj ect for the
21 amounts suggested by Mr. Sterling. Mr. Sterling should
22 have used 100 percent of the amounts provided in the
23 Commitment Estimate in his Soft Cap.
PORTER, DI REB 27
Idaho Power Company
1 8.Transmission Contingency. Mr. Sterling
2 removed all transmission contingency from his recommended
3 Soft Cap. I do not believe this is reasonable. The
4 estimated transmission cost from the System Impact Study
5 has an accuracy of plus or minus 20 percent . Given the
6 fact that these are System Impact Study estimates, I
7 believe it is prudent to include a 20 percent contingency
8 in the Commitment Estimate.
9 TURINE RESERVATION AGREEMNTS
10 Q.Why did the Company enter into reservation
11 agreements with the turbine supplier for the gas and steam
12 turbines, even before the self-build option had been
13 selected as the successful bidder?
14 A.As noted by Mr. Bokenkamp in his rebuttal
15 testimony, the Company has a legal obligation to serve its
16 customers. Although the Company was unaware whether its
17 self-build option would ultimately be selected or built,
18 entering into reservation agreements for the critical path
19 turbines was necessary in order to ensure that, when the
20 bidding process was completed, the Company had at least one
21 generation option capable of meeting load in 2012. In mid-
22 September 2007, demand for gas equipment was high, leading
23 to long lead times. This fact was confirmed by our Owner's
PORTER, DI REB 28
Idaho Power Company
1 Engineer (Power Engineers), potential OEM suppliers, and
2 EPC contractors.
3 It became clear that in order for a plant to be in
4 service for the summer of 2012, the Company would need to
5 enter into reservation agreements for the gas and steam
6 turbines. On September 19, 2008, a month prior to the RFP
7 bid submittal date, Idaho Power entered into reservation
8 agreements with Siemens for gas and steam turbine
9 equipment.
10 Q.Is the long lead time for turbines - from
11 the date of order until the date of delivery - confirmed by
12 any other sources of information?
13 A.Interestingly, Intervenors NIPPC's and
14 ICIP's witness, Dr. Reading, offers evidence confirming
15 thïs fact. In his testimony, Dr. Reading references a
16 letter sent from a potential bidder to Idaho Power that
17 confirmed the need to immediately reserve gas and steam
18 turbines in order to meet the project schedule. (Exhibits
19 Nos. 703 and 205.) In that letter, the prospective bidder
20 states:
21 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I22 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I23 I I I I I I I I I I I I I I I I I I I I I II I I I I I I I I I I I I I I I I
24 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I25 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I
26 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I
27 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I
PORTER, DI REB 29
Idaho Power Company
1
2
3
4
5
6
7
8
9
10
11
12
13
I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I III
I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I II I I I
I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I II I I I I I
I I I II I I I I I I I I I I I II I I I I I I I I I I I I I I III I I I I
I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I III I I I I I
I I I I I I I I I I I I I I I I I I I I I I I I III I I I I I II I I I I I
I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I
I I I I I I I I I I I I I I I I II I I I I I I I I I I I I I I I I I I I I I
I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I II I I
I I I I I I I I I I I I I I I I I I I I I I I I I I I I I II II I I I I I I
I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I II I I I I I I
I I I I I II I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I
I I I I I I I I I I I I I I I I I I I I I I I I II I I I I I I II I I I I I
14 ASSIGNABILITY OF TURINE AGREEMNTS
15 Q.During the RFP process, why did Idaho Power
16 not offer to assign its turbine equipment to whatever
17 bidder was ultimately selected?
18 A.I am aware that during the pre-bid process
19 the Company informed prospective bidders that it did not
20 have the authority to assign equipment to any third party.
21 This statement was true. Until shortly before bids were
22 due, the Company had not completed its selection of a
23 manufacturer for the turbines, and had not entered into a
24 reservation agreement with any supplier. Those reservation
25 agreements were effective September 19, 2008.
26 Q.Did the reservation agreements provide IPC
27 with unfettered discretion to assign them to any third
28 party?
29 A.No. The Company' s representatives
30 negotiated vigorously with the equipment supplier to permit
PORTER, DI REB 30
Idaho Power Company
1 the Company the greatest flexibility to assign the
2 reservation agreements. It was in the Company's interests
3 to have such flexibility. In the end, the supplier would
4 not agree to permit the Company to assign the agreements to
5 an unrelated third party without securing the consent of
6 the supplier, which the supplier could not unreasonably
7 withhold . Given this consent provision, the Company was
8 not legally entitled to assure prospective bidders that
9 they could assume contractual rights to the turbines.
10 CACELLATION FEES
11 Q.Mr. Sterling discusses in his direct
12 testimony the cancellation fees to be incurred by Idaho
13 Power if this project is delayed. He states that the
14 cancellation fees are approximately $8.7 million for the
15 gas and steam turbines, combined. Does Mr. Sterling
16 capture all of potential expense to the Company if this
17 project is delayed?
18 A.No. Depending on the length of the delay,
19 cancellation charges may be substantially more than $8.7
20 million. The approximately $8.7 million represents
21 payments already made by the Company to Siemens for the gas
22 and steam turbine reservation fees and the initial contract
23 payment for the steam turbine. The details of the
24 cancellation charges are outlined in the Gas Turbine and
PORTER, DI REB 31
Idaho Power Company
1 Steam Turbine Agreements Idaho Power provided in the
2 Staff's Production Request No. 77. They were also outlined
3 in the Company's June 8, 2009, 8-K filing with the
4 Securities and Exchange Commission.
5 If Idaho Power cancels the purchase agreements on
6 September 1, the Company would be required to pay a
7 cancellation fee of 35 percent of the total purchase price
8 of the gas turbine, less any payments already made by Idaho
9 Power under the Gas Turbine Agreement. The Gas Turbine
10 Agreement also contains a schedule of cancellation fees IPC
11 must pay if it terminates the Gas Turbine Agreement at any
12 time during the contract term, absent assignment of the Gas
13 Turbine Agreement by IPC with the written consent of
14 Siemens Energy. The cancellation fees are based on a
15 percentage of the total gas turbine purchase price and
16 increase monthly from 20 percent on July 1, 2009, to 100
17 percent on or after September 1, 2010.
18 The steam turbine purchase agreement with Siemens
19 Energy ("Steam Turbine Agreement") also contains a
20 cancellation fee schedule. Idaho Power has the right to
21 terminate the Steam Turbine Agreement at any time upon
22 paying a cancellation fee to Siemens Energy based on a
23 percentage of the total purchase price of the steam
24 turbine, absent assignment of the Steam Turbine Agreement
PORTER, DI REB 32
Idaho Power Company
1 by Idaho Power with the written consent of Siemens Energy.
2 The Steam Turbine Agreement cancellation fee percentage
3 increases monthly from 10 percent on February 15, 2009, to
4 100 percent on or after May 15, 2011. The cancellation fee
5 is 15 percent on September 1, 2009.
6 On September 1, the cancellation fees for the gas
7 and steam turbines, based on current contract amounts, are
8 as follows:
9 Gas turbine: $53,221,048 x 35% =$ 18,627,367
10 Steam turbine: $33,835,327 x 15%$ 5,075,299
11 Total:$ 23,702,666
12 Q.Does this conclude your testimony?
13 A.Yes, it does.
PORTER, DI REB 33
Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTiliTIES COMMISSION
CASE NO. IPC-E-09-03
IDAHO POWER COMPANY
PORTER, DI REB
TESTIMONY
EXHIBIT NO. 11
Bokenkamp, Karl
From:
Sent:
To:
Cc:
Subject:
Agnello, Elaine (Egnellocmrwec.coml
Tuesday, April 14, 209 2:12 PM
Bokenkamp, Karl
Stein, Steven
Dra language
Confidenti Attorney-eent PrvUeged and Work-Produet: The Information In This E-Mail And In Any Attachment
May Contain Information Which Is Legally Privileged. It Is Intended Only For The Atention And Use Of The
Named Recipient. If You Are Not The Intended RecIpient You Are Not Authorized To Retain, Disclose, Copy Or
DistrIbute The Mesage And/Or Any Of Its Atchments. If You Received This E-Mail In Error, Please Notify Me
And Delete This Message. Thank-You.
Good afternoon Mr. Bokenkamp:
Steve Stein asked me to send you this language.
R. vv Beck was consulted and asked if they agreed with Idaho Power's belief that n. . . the evaluation
process could become extremely complicated and somewhat subjective n if build and transfr options
were permitted without including a detailed design specification in the RFP. Preparation of detailed
design specifications for a build and transfr RFP pross option is consistent with R. vv Beck's
normal recommendations to clients for projects of this type.
Elaine Agnello
Offce Supervisor
Phone [phone] Cell 407-399-7516
Fax [phone]
1000 legion Place, Suite 1100
Orlando. Fl 32801
----_.._-_. --~..__._-_.__.-..._. --. ..._- "-_...- _.-..-....._.__.--MInd Powered: Insight wilh Impact.ivckco
Please i:nslder the envinmen before prntflg this email.
This conlcaion and any re/Sled ve coicatio are proved undr the te of R. W. B/('S cotract with Its clnt, and 81 no 1ttendd to be used or
reiie upon by any third Pary other /han advsors or cosullants to the ciient. Any im of such commnicati by any othr Uiir part is the responsibilty of suchthird part, and R. W. Beck accts no responibitt fo any damage incur by any thir par as a relt of dacis or ae/ios bad on such commutl.
Any guiance or opinion pridd hein shld only be fiM and reie UPOl by client within the limitatis and colald of any prio gudance prided by R. W.
Beck in any pnor wo pris teing 10 th subjac mailer of such comunica.
1
Exhibit No. 11
Case No. IPC-E-09-03
v. Porter, IPC
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