20090727Vol V Technical Hearing.pdf

ORIGINAL.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
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) CASE
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NO. IPC-E-09-03
,dao Public Utilties Commission
Office ot the Secretary
RECEIVED
JUL 27 2009
Bois. Idao
BEFORE
COMMISSIONER JIM KEMPTON (Presiding)
COMMISSIONER MARSHA SMITH
COMMISSIONER MACK REDFORD
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PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:July 15, 2009
VOLUME V - Pages 429 - 671
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CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone] * [phone]
Email csb~eritagewifi.com
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1 APPEARANCES
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For the Staff:
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5 For Idaho Power Company:
Scott Woodbury, Esq.
Deputy Attorney General
472 West Washington
Boise, Idaho 83720-0074
Barton L. Kline, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707 -007 0
RICHARDSON & 0' LEARY
by Peter J. Richardson, Esq.
Post Office Box 7218
Boise, Idaho 83702
RACINE, OLSON, NYE, BUDGE
& BAILEY
by Eric L. Olsen, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
Susan K. Acker.an, Esq.
Attorney at Law
9883 NW Nottage Drive
Portland, Oregon 97229
Mr. Ken Miller
5400 West Franklin
Boise, Idaho 83705
Ms. Betsy Bridge, Esq.
Attorney at Law
Idaho Conservation League
Post Office Box 844
Boise, Idaho 83701
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For Industrial Customers
of Idaho Power:
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10 For Idaho Irrigation
Pumpers Association:
For NIPPC:
For Snake River Alliance:
For Idaho Conservation
League:
CSB REPORTING
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APPEARANCES
1 I N D E X.2
3 WITNESS EXAMINATION BY PAGE
4 Vernon Porter Mr.Kline (Direct)432(Idaho Power)Prefiled Direct Testimony 434
5 Prefiled Rebuttal Testimony 461
Mr.Kline (Direct-Cont 'd)497
6 Mr.Richardson (Cross)502
Ms.Ackerman (Cross)507
7 Mr.Woodbury (Cross)508
Commissioner Redford 510
8 Commissioner Smith 519
Commissioner Kempton 522
9 Mr.Richardson (Cross)529
Mr.Miller (Cross)53710Mr.Woodbury (Cross)541Commissioner Redford 55911Commissioner Smith 586
Commissioner Kempton 58912
Cynthia Mitchell Mr.Richardson (Direct)59813( ICIP)Prefiled Direct Testimony 602.14
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CSB REPORTING INDEX
(208 )890-5198
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1 EXHIBITS
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Premarked
Identified 496
Identified 559
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FOR THE INDUSTRIAL CUSTOMERS OF IDAHO POWER:
CSB REPORTING
Wilder, Idaho 83676
Premarked
Premarked
Premarked
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3 NUMBER DESCRI PTION
4 FOR I DAHO POWER COMPANY:
5 11. Confidential exhibit sponsored by
Vernon Porter
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26. Confidential exhibit sponsored by
Vernon Porter
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9 FOR THE STAFF:
10 116. Confidential exhibit provided at
Commissioner Redford i s request
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206. CV of Cynthia K. Mitchell
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207. 2010 & 2013 Forecast
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208. Average Energy Load & Resource
Balance
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EXHIBITS
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1 BOISE, IDAHO, WEDNESDAY, JULY 15, 2009, 9: 00 A. M.
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4 COMMISSIONER KEMPTON: So we are at the
5 Idaho PUC Commission Hearing Room. It's July 15th, 2009,
6 and second day of hearings on the Langley Gulch technical
7 hearings, Case No. IPC-E-09-03. All procedures that were
8 in effect yesterday are in effect today. Are there any
9 motions or petitions to come before the Commission before
10 we go to the first witness? Mr. Woodbury.
11 MR. WOODBURY: Just as a carryover from
12 yesterday evening which was the public testimony, the
13 Commission at that time identified an Exhibit 901 which
has been distributed to parties. That is a public
15 witness exhibit and submitted by Mike Heckler or he was
16 the witness and he's not a party to the case, but the
17 Company, it's my understanding from a discussion last
18 night, would have the opportunity to address any
19 inaccuracies that they might see in the document at the
20 conclusion of the hearing or some other time, so I just
21 wanted to just make note of that, I guess, for the
22 record.
23 COMMISSIONER KEMPTON: Thank you, and it
24 was the intent of the Chair last night because of the.25 technical nature of the testimony and because we did give
CSB REPORTING
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429 COLLOQUY
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1 it a specific Exhibit No. 901 that Idaho Power be given
2 the opportunity to have a position on how they would like
3 to have that particular piece of testimony handled in the
4 process of the main technical hearing today. Mr. Kline,
5 do you have any comments?
6 MR. KLINE: Yes, we reviewed Mr. Heckler's
7 material last night. Some of it, as you recall, is
8 directed toward the Company's demand side management and
9 energy conservation efforts. Mr. Pengilly who's one of
10 the witnesses that will be presented today, that is his
11 area of expertise and so we will have some questions for
12 Mr. Pengilly and he will address those questions as a
13 part of his testimony and then it's likely that we'll ask
14 Mr. Gale perhaps to address some of the other issues
15 raised by Mr. Heckler. I mean, I think generally 85
16 percent of it is stuff that has already been presented to
17 you in this case and we'll address those others.
18 COMMISSIONER KEMPTON: And has that
19 testimony given by Mr. Heckler been distributed to the
20 parties?
21 MR. KLINE: I believe that it has.
22 MR. WOODBURY: Yes.
23 COMMISSIONER KEMPTON: Is there any party
24 that does not have the testimony from last night from
25 Mr. Heckler? Very well, Mr. Kline.
CSB REPORTING
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430 COLLOQUY
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1 MR. WOODBURY: And there are extra copies
2 on the distribution table.
3 COMMI S S IONER KEMPTON: Al 1 right,
4 Mr. Kline.
5 MR. KLINE: Just one more preliminary
6 thing. Yesterday Commissioner Redford requested that we
7 supply some information regarding the RFP that was
8 conducted. That is in the process of being assembled.
9 It's a little bigger than I recalled it being, but it
10 should be available at the break this morning.
11 COMMISSIONER REDFORD: Thank you.
12 MR. KLINE: You bet. All right, we
13 concluded with Mr. Bokenkamp yesterday and so Idaho
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Power's next witness is Vern Porter.
CSB REPORTING
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431 COLLOQUY
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1 VERNON PORTER,
2 produced as a witness at the instance of the Idaho Power
3 Company, having been first duly sworn, was examined and
4 testified as follows:
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6 DIRECT EXAMINATION
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8 BY MR. KLINE:
9 Q Would you please state your name and spell
10 your last name for the reporter?
11 A My name is Vernon Porter and my last name
12 is spelled P-o-r-t-e-r.
13 Q Mr. Porter, by whom are you employed and
14 in what capacity?
A I'm employed by Idaho Power and I i m the
16 general manager of power production.
17 Q Are you the same Vernon Porter who
18 prefiled direct and rebuttal testimony in this case?
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A Yes.
Q And as a part of your prefiled testimony,
21 did you also prefile Exhibit No. 11?
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A Yes, I did.
Q Are there any additions or corrections
24 that you need to make to either your prefiled testimony
25 or your Exhibit 11?
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432 PORTER (Di)
Idaho Power Company
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1 A No.
So if I were to ask you the same questions
3 that were set out in your prefiled testimony today, would
2 Q
4 your answers be the same?
5 A Yes.
MR. KLINE: With that, Mr. Chairman, I
7 would move that the prefiled testimony of Mr. Porter be
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8 spread on the record as if read in its entirety and that
9 Exhibit 11 be marked.
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11 so ordered.
COMMISSIONER KEMPTON: Without objection,
12 (The following prefiled direct and
13 rebuttal testimony of Mr. Vernon Porter is spread upon
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433 PORTER (Di)
Idaho Power Company
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1 Q.Would you please state your name, employment
2 status, and educational background?
3 A.My name is Vernon Porter. I have been employed
4 by Idaho Power Company (" Idaho Power" or "Company") for
5 19 years. I currently hold, and at all times relevant to
6 this Application have held, the position of General
7 Manager of Power Production. I work at the Company's
8 Corporate Headquarters, located at 1221 West Idaho Street
9 in Boise. I attended Brigham Young Uni versi ty from which
10 I obtained a Bachelor of Science degree in 1985 in
11 Electrical Engineering and a Master of Science degree in
12 1986.
13 Q.What are your responsibilities as General
14 Manager of Power Production?
15 A.I manage the operation, maintenance, and
16 construction of Idaho Power's generation facilities. I
17 also manage Idaho Power's interest in certain jointly
18 owned coal-fired plants and a coal mine.
19 Q.Would you please provide a summary of your
20 testimony in this proceeding?
21 A.I offer testimony regarding: the development
22 of the proposed combined cycle combustion turbine
23 ("CCCT") baseload resource that is the subj ect of this
24 proceeding ("Langley Gulch Power Plant" or "Plant");
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434 PORTER, DI 1
Idaho Power Company
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1 the contracts for acquisition of the equipment and the
2 engineering, procurement, and construction ("EPC")
3 services relating to the Plant; the status of the
4 Company's efforts to obtain governmental permits
5 necessary to construct and operate the Plant; the Plant's
6 environmental and emission controls; the allocation of
7 price risk associated with the construction of the Plant;
8 interconnection of the Plant to Idaho Power's system;
9 plant operation, and benefits associated with the
10 Company's operation of the Plant; and economic benefits
11 to the local economy of construction and operation of the
12 plant.
13 Q.What role have you had in the development of
14 the Langley Gulch Power Plant?
15 A.I was the senior member of the Idaho Power team
16 that submitted the Company's benchmark resource proposal
17 in response to the Company's baseload resource Request
18 for Proposal ("RFP"). That team is commonly referred to
19 as the "Benchmark Resource Team" or "Team," and the
20 benchmark resource is now referred to as the Langley
21 Gulch Power Plant.
22 Q.What were the responsibilities of the Benchmark
23 Resource Team?
24 A.The Benchmark Resource Team was responsible for
25 developing a proposal for a technologically and
435 PORTER, DI 2
Idaho Power Company
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1 economically sound baseload generating resource that
2 would be capable of commercial operation by June of 2012.
3 Q.You stated that the Langley Gulch Power Plant
4 was originally scheduled to be in service in June 2012.
5 What is its currently scheduled date of commercial
6 operation?
A.December 1,2012.
Q.Why did its commercial operation date
change?
A.In order to meet a June 1,2012,commercial
operation date,Idaho Power would have to authorize the
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12 EPC contractor to proceed with engineering and other
13 project related activities before the Idaho Public
14 Utilities Commission (" IPUC") had considered and ruled
15 upon Idaho Power's Application for a Certificate of
16 Public Convenience and Necessity. Given the current
17 economic crisis and the challenges it creates in
18 financing the project, Idaho Power has negotiated with
19 the EPC contractor to delay commencement of its work
20 until September 1, 2009. This will permit the IPUC to
21 consider the Application and, if it so decides, issue a
22 Certificate that will facilitate proj ect financing.
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436 PORTER, DI 3
Idaho Power Company
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1 LAGLEY GULCH POWER PLAT DEVLOPMENT
2 Q.Will you please describe, in general, the
3 Langley Gulch Power Plant?
4 A.The proposed Langley Gulch Power Plant is a
5 CCCT power plant that utilizes a Siemens SGT6-S000F
6 combustion gas turbine matched with a Siemens steam
7 turbine (a combination referred to as a "lX1"
8 configuration) for a flexible, energy efficient,
9 low-emission, highly reliable power plant located
10 approximately four miles south of New Plymouth, Idaho, in
11 Payette County. The Benchmark Resource Team performed an
12 extensive evaluation of numerous sites across Southwest
13 Idaho. The selected site, in combination with high
14 efficiency equipment and superior design and
15 construction, will result in a state of the art facility
16 that will provide long-term, low cost, fully
17 integratable, and operationally flexible generation to
18 meet Idaho Power customer needs for an estimated 35
19 years.
20 Q.Will you please describe, in general, the
21 Benchmark Resource Team's process that led to the
22 development of the Langley Gulch Power Plant proposal?
23 A.The Benchmark Resource Team was led by Idaho
24 Power's Power Production group, with technical assistance
25 of many others within, and external to, Idaho Power. The
Team has been assisted by Idaho Power personnel from the
437 PORTER, DI 4
Idaho Power Company
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1 Company's Land Management, Legal, Environmental, and
2 Water Management Departments.
3 The Team also retained the services of an
4 independent engineering firm, Power Engineers, to act as
5 an Owner's Engineer to assist with technical matters and
6 provide independent advice on pricing and current trends
7 and developments in the combined cycle industry.
8 The Team conducted a thorough site selection
9 process that led to the Company acquiring the right to
10 purchase land for the facility.
11 The Team issued an RFP and conducted a
12 competi ti ve bidding process for key equipment
13 components - the gas and steam turbines. The Team
14 selected an equipment supplier, Siemens, after receiving
15 the competing proposals.
16 The Benchmark Resource Team also issued a
17 Request for Statement of Qualifications ("RFQ") to
18 identify potential contractors to perform EPC services.
19 After evaluating the qualifications of potential
20 contractors, interviewing representatives of the
21 contractors, and inspecting proj ects built by them, the
22 Team selected what it considers to be the best EPC
23 contractor for this proj ect.
24 The Team has begun the process of securing
25 environmental, land use, and other permits necessary to
438 PORTER, DI 5
Idaho Power Company
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1 complete construction and commence commercial operation
2 of the Plant by December 1, 2012.
3 Q.Where is the Langley Gulch Power Plant to be
4 located?
5 A.The site consists of 137 acres of undeveloped
6 range land located in rural Payette County, adj acent to
7 Interstate 84 and immediately southwest of Exit 9. This
8 interchange provides access to US Highway 30 and the City
9 of New Plymouth approximately four miles to the north.
10 To the south, the interchange leads directly into this
11 specific property. The site is bounded by Interstate 84
12 to the north, Bureau of Land Management ("BLM") land to
13 the south and west, and private range ground to the east.
14 Q.What has the Company done to secure land on
15 which the Langley Gulch Power Plant will be located?
16 A. The Company has acquired an option to purchase
17 the land. The option will expire in March 2010.
18 Q. Will you please describe how the Benchmark
19 Resource Team selected this site for the Langley Gulch
20 Power Plant?
21 A.The Benchmark Resource Team conducted a
22 detailed review of 13 potential sites in Southwest Idaho
23 in order to identify and secure a site that provides the
24 optimal combination of project performance, reliability,
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439 PORTER, DI 6
Idaho Power Company
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1 economy, minimal environmental impact, and
2 constructabili ty. The Team considered 18 factors
3 relative to each site. The proposed proj ect site will
4 permi t the construction of a highly efficient combined
5 cycle plant (low elevation, water cooled) at a location
6 away from any population center and outside the potential
7 air quality "non-attainment" area consisting of Ada and
8 Canyon counties. At the same time, the site is near
9 available transmission, gas, and transportation
10 facilities. The site will also accommodate the possible
11 future construction of additional generating resources at
12 the same location. Specifically:
13 (1) The site is at low elevation, and can
14 access water from the Snake River. These factors
15 optimize the generating efficiency of the Plant and
16 reduce overall generation costs;
17 (2) Gas supply from the Williams Northwest
18 Pipeline is located approximately three-quarters of a
19 mile from the site;
20 (3) The site is near existing transmission
21 facilities;
22 (4) The site has no nearby neighbors. The
23 nearest residence is approximately three quarters of a
24 mile from the site, across the Interstate;
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440 PORTER, DI 7
Idaho Power Company
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1 (5) The site is located adj acent to the
2 Interstate and nearby rail sidings, permitting optimal
3 access; and
4 (6) The site could accommodate possible future
5 construction of a similar capacity plant or simple cycle
6 gas generation facility at the same location.
7 Q.You indicated that the Langley Gulch Power
8 Plant will be water cooled. What has the Company done to
9 secure water for this Plant?
10 A.The Company purchased a water right from the
11 Cottonwood Irrigation District for Snake River surface
12 water rights. The Company will construct a pumping
13 station and pipeline. The pipeline will be approximately
14 eight miles in length, the maj ori ty of which will be
15 across BLM land.
16 SIEMNS EQUIPMNT
17 Q.You stated that the Langley Gulch Power Plant
18 will utilize a Siemens gas turbine and Siemens steam
19 turbine. What has the Company done to assure that this
20 equipment will be available for the Plant?
21 A.Due to global high demand and long
22 manufacturing lead times for gas and steam turbines, in
23 2008 Idaho Power entered into reservation agreements with
24 Siemens for combustion and steam turbines to assure their
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441 PORTER, DI 8
Idaho Power Company
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1 delivery in time to permit completion of construction and
2 commercial operation of the Plant in 2012. Idaho Power
3 and Siemens have since executed final contracts relating
4 to the purchase of the equipment. Idaho Power has paid
5 Siemens a total of $8,721,701 to reserve the equipment.
6 This sum is creditable against the final purchase price
7 of the equipment. No further payments on the equipment
8 are required before September 1, 2009. If Idaho Power
9 terminates the contracts, the payments made to date will
10 be largely non-refundable. The contracts are, however,
11 potentially assignable subj ect to certain conditions.
12 Q.How did the Benchmark Resource Team come to
13 select Siemens equipment?
14 A.Siemens Energy was selected as the combustion
15 turbine and steam turbine supplier after Idaho Power
16 received bids in response to a RFP. Idaho Power received
17 bids from two of the three maj or suppliers of such
18 equipment (Siemens, General Electric, and Mitsubishi) .
19 Q.What are the key terms of the Siemens
20 contracts?
21 A.The two contracts for the purchase of the gas
22 turbine and steam turbine, respectively, have similar
23 terms. Each contract requires: the Company to pay a
24 fixed price for the equipment; Siemens to guarantee
25 delivery of
442 PORTER, DI 9
Idaho Power Company
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1 the equipment to the site by specific dates that will
2 accommodate the project schedule, or incur liquidated
3 damages; Siemens to guarantee that the equipment will
4 meet specified performance and emission standards, or
5 incur liquidated damages; and Siemens to warrant for a
6 period of time that the equipment is free from defects.
7 The contracts are also assignable by Idaho Power with the
8 consent of Siemens (which may not be unreasonably
9 wi thheld by Siemens) .
10 Q.Will you please describe the technical
11 characteristics of the Siemens' gas and steam turbines?
12 A.The proposed Langley Gulch Power Plant will
13 utilize a Siemens gas fired combustion turbine matched
14 with a Siemens steam turbine for an energy efficient, low
15 heat rate, low emission combined cycle power plant.
16 The gas turbine is classified as an SGT6-S000F
17 ("F-class") machine, capable of producing 180 MW at the
18 design condition. The design condition is 90 degrees
19 Fahrenheit, at 20 percent relative humidity. The machine
20 class is the same as Idaho Power's Bennett Mountain and
21 Danskin Unit No. 1 machines. The F-class machine has
22 demonstrated an exceptional world-wide operating and
23 reliabili ty record with nearly five million operating
24 hours and 205 machines in the fleet.
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443 PORTER, DI 10
Idaho Power Company
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1 The steam turbine is a SST-700 high pressure
2 steam turbine directly coupled with a SST-900
3 intermediate pressure turbine, capable of producing 96 MW
4 at the design condition. The SST-900 turbine is equipped
5 wi th a multi-valve inlet to accommodate the low pressure
6 steam system. These turbines have high reliability and
7 efficiency. They have a compact design and are nearly
8 completely assembled at the factory for easy integration
9 during construction.
10 The turbine equipment will be controlled by a
11 Siemens T-3000 control system. This is the same control
12 system in use at Idaho Power's other gas-fired plants.
13 EPC SERVICES
14 Q.Who will provide EPC services for the Langley
15 Gulch Power Plant?
16 A.Idaho Power has executed a memorandum of
17 understanding ("MOU") with a j oint venture consisting of
18 The Industrial Company ("TIC") and Kiewit Power Engineers
19 Co. ("Kiewit") to provide EPC services for the Langley
20 Gulch Power Plant.
21 Q.How was the EPC contractor selected by Idaho
22 Power?
23 A.Following issuance of a RFQ, the Benchmark
24 Resource Team conducted an evaluation of the most
25 qualified engineering and construction firms with
experience relating
444 PORTER, DIll
Idaho Power Company
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1 to combined cycle gas fired power plants. Eight firms
2 participated in a pre-qualification process. Various
3 firms were interviewed and representatives of the
4 Benchmark Resource Team examined reference plants
5 constructed by several of the firms. Through this
6 process it became apparent that Kiewit as an engineering
7 firm, and TIC as a construction firm, were superior to
8 other potential firms.
9 Q.What are the EPC Contractor's qualifications?
10 A.Kiewi t and TIC have a long history of
11 successfully engineering and constructing combined cycle
12 gas proj ects. They have built plants both individually
13 and as members of j oint ventures.
14 Q.Has Idaho Power entered into a contract with
15 the EPC Contractor?
16 A.While an executed MOU is currently in place
17 between Idaho Power and the EPC contractor, the parties
18 are in the process of completing a final EPC contract.
19 The Parties expect to execute the final agreement by
20 mid-March 2009. In addition, the EPC contractor has been
21 performing certain preliminary engineering services in
22 order to maintain proj ect schedule. These services have
23 been performed pursuant to separate engineering services
24 agreements.
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445 PORTER, DI 12
Idaho Power Company
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1 Q.What are the key terms of the EPC contract?
2 A.The EPC contract with TIC/Kiewit will require
3 TIC/Kiewit to perform all engineering services, equipment
4 procurement, and construction for the power plant (other
5 than the Siemens supplied gas and steam turbines) .
6 TIC/Kiewi t must guarantee completion of construction by
7 December 1, 2012, or pay liquidated damages. TIC/Kiewit
8 must also guarantee that the overall Plant will meet
9 specified performance standards, or pay liquidated
10 damages. TIC/Kiewit will warrant that they will perform
11 the services in accordance with the reasonable industry
12 standards of care, or remedy defective work.
13 As discussed in greater detail in my testimony
14 below, TIC/Kiewit have assumed primary price risk in
15 relation to labor and materials relative to the EPC
16 contract.
17 Q.What are the major construction schedule dates?
18 A.Subject to IPUC approval, engineering will
19 begin on September 1, 2009, and construction will begin
20 on August 1, 2010. The gas turbine is scheduled to be
21 delivered on February 1, 2011, while the steam turbine is
22 scheduled to be delivered on July 29, 2011. The Plant
23 will be available for commercial operation by December 1,
24 2012.
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446 PORTER, DI 13
Idaho Power Company
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1 PERMITS REQUIRED
2 Q.What governmental permits are required for the
3 Langley Gulch Power Plant and what has the Company done
4 to assure that those permits will be secured in time to
5 maintain the construction schedule?
6 A.This is a summary of the required permits and
7 actions taken by the Company to obtain those permits:
8 (1) Tier 1 - Title V Air Permit to Construct.
9 Preliminary air-shed modeling has been completed by a
10 consul tant retained by the Company, Tetra Tech, for 13
11 preliminary sites, including the proposed site. Based on
12 the results of the model, the Company anticipates
13 obtaining an air permit without complication. The Team
14 has coordinated with the Idaho Department of
15 Environmental Quality ("IDEQ") regarding the
16 Meteorological Monitoring Plan and location of a
17 meteorological tower to collect data required for the
18 permit. The tower was installed in November 2008 and is
19 currently collecting data.
20 (2) NEPA (Environmental). The Company has
21 entered into a contract with a consultant, EDAW, to
22 perform National Environmental Protection Act ("NEPA")
23 compliance services relating to the project. An
24 Application for Transportation and Utility Systems and
25 Facilities on
447 PORTER, DI 14
Idaho Power Company
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2 Federal Lands required by the Department of the Interior
3 has been submitted to the BLM.
4 (3) Payette County Coordination.
5 Representatives of the Company have discussed this
6 project with Payette County Planning and Zoning
7 Department personnel on several occasions. Idaho Power
8 has drafted a comprehensive plan change application and
9 is prepared to submit the application.
10 (4) Other Permits and Related Activities.
11 Other permit applications will be prepared and submitted
12 to the appropriate regulatory authorities as the project
13 proceeds. These, and related acti vi ties, include:
14 (a) Section 404 Permit - US Army Corps of
15 Engineers;
16 (b) Section 401 Water Quality - through
17 Idaho DEQ and EPA;
18 (c) Stream Alteration Permit - through
19 Idaho Department of Water Resources (IDWR);
20 (d) Injection Well Permit to Construct -
21 through IDWR;
22 (e) A National Pollutant Discharge
23 Elimination System Permit for Large Construction
24 Activities - through EPA;
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448 PORTER, DI 15
Idaho Power Company
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1 (f) Other building and installation
2 permi ts will be obtained by the building contractor;
3 (g) A geotechnical engineering report and
4 supporting addenda were prepared for the site by a
5 consultant retained by the Company, Materials Testing and
6 Inspection;
7 (h) A water distribution study has been
8 completed for the construction of the pump station and
9 associated water line to the plant. The trench will
10 predominately be open-cut with a couple of borings to
11 cross canals and State/Federal roadways; and
12 (i) A Cultural Resource Survey has also
13 been completed for the site.
14 PLAT ENVIRONMTAL AN EMISSION CONTROLS
15 Q.What environmental and emission controls are
16 incorporated into the Langley Gulch Power Plant's design?
A.The Plant is designed to accommodate current
18 and reasonably anticipated environmental restrictions,
19 and to enhance community acceptance of the project.
20 Specifically:
21 (1) A preliminary air modeling study was
22 completed that determined that the Langley Gulch location
23 was sui table for obtaining an air permit to construct.
24 The site is located outside the potential Ada and Canyon
25 County
449 PORTER, DI 16
Idaho Power Company
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1 "non-attainment II area. The Plant will have selective
2 catalytic reduction for nitrogen oxide ("NOx") control,
3 low NOx burners, and a catalyst for carbon monoxide
4 ("CO") reduction. The emission controls will qualify for
5 Best Available Control Technology. NOx emissions will be
6 2 parts per million ("ppm") and CO emissions will be 1
7 ppm;
8 (2) The plant is designed for zero surface
9 wastewater discharge to reduce environmental effects.
10 The plant is designed to utilize a cooling water
11 injection well system; and
12 (3) The equipment will include sound
13 attenuation in the design. Plant noise will be less than
14 the adj acent interstate freeway bordering the site.
15 PRICE AN OUTPUT RISK
16 Q.What has the Company done to limit its price
17 risk associated with the Langley Gulch Power Plant?
18 A.In general, the Company has attempted to manage
19 price risk by securing, to the extent possible,
20 contractual terms with the equipment and EPC contractors
21 that result in those contractors assuming price risk. To
22 this end, the contracts with Siemens for the purchase of
23 the gas and steam turbines are fixed price contracts
24 pursuant to which Siemens assumes all price risk for
25 labor
450 PORTER, DI 17
Idaho Power Company
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1 and material costs associated with the design,
2 manufacture, and deli very of the equipment.
3 The EPC contractor initially proposed two
4 pricing options: (1) a fixed price option pursuant to
5 which the contractor assumed all price risk for labor and
6 material costs associated with the construction of the
7 Plant (other than relating to the gas and steam turbine)
8 and (2) a "target" price option pursuant to which price
9 risk associated with engineered equipment would be shared
10 by the contractor and Idaho Power. Under the target
11 price option: (1) the EPC contractor's base bid is
12 reduced by approximately $5.3 million as compared to the
13 fixed price option; (2) a target price for engineered
14 equipment is established.(Engineered equipment does not
15 include commodities such as steel, rebar, concrete, and
16 other materials used to construct those portions of the
17 Plant not consisting of engineered equipment. The EPC
18 contractor assumes price risk associated with these
19 commodi ties. ); and (3) the contractor and Idaho Power
20 share equally the risks and rewards of actual engineered
21 equipment costs in a range approximately $8 million above
22 and below the target price. Price risk and reward
23 outside this aggregate approximately $16 million range is
24 assumed exclusively by Idaho Power.
25
451 PORTER, DI 18
Idaho Power Company
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1 Q.Mr. Gale describes the Company's commitment
2 estimate in his testimony. Have you read his testimony?
3 A.Yes.
4 Q.Based on your knowledge of the cost of the
5 Langley Gulch proj ect, what price risk does the Company
6 retain relative to the commitment estimate?
7 A.The Company's proposed commitment estimate
8 includes contingencies for those components of the
9 overall price of the proj ect where the Company continues
10 to assume price risk. Those primary components are:
11 (1) EPC Contract. As a condition of delaying
12 six months the commencement of construction and
13 procurement of materials and supplies (other than the
14 turbines), the EPC contractor requires Idaho Power to
15 accept price risk associated with two items: (1) Idaho
16 Power must accept the target price option relating to
17 engineered equipment; and (2) Idaho Power must assume
18 labor price escalation risk during the period of time
19 that the IPUC is considering the present petition, not to
20 exceed two percent of the total labor component of the
21 EPC contract.
22 (2) Other Components. The proposed commitment
23 estimate also assumes proj ect related expenses, and
24 contingencies, other than those related to the EPC and
25 Siemens contracts, including:(a) transmission costs,
452 PORTER, DI 19
Idaho Power Company
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20
1 and contingencies relating thereto; (b) the estimated
2 cost of constructing the gas line tap, and contingencies
3 relating thereto; (c) estimated costs associated with the
4 gas line, water line, and discharge water injection
5 wells, and contingencies relating thereto; (d) net
6 start-up fuel costs; and (e) RFP team expenses.
7 In the aggregate, that portion of the
8 commi tment estimate that is comprised of contingencies is
9 approximately 2.8 percent.
10 Q.Did the Benchmark Resource Team's proposal
11 include reasonably anticipated maintenance and operation
12 expenses and future capital expenditures associated with
13 the Plant?
14 A.Yes. The proposal included costs for maj or
15 maintenance items such as hot gas path work, spare parts,
16 labor, and other reasonably anticipated maintenance and
17 operation expense. In addition, the proposal included
18 $500,000 per year for capital and maintenance
19 improvements.
Q.What has the Company done to assure the Plant i s
21 generation output will be met?
22 A.The equipment contracts with Siemens contain
23 terms requiring that the gas and steam turbines meet
24 specific output performance standards, and if these
25 standards are not met, then Siemens must pay Idaho Power
453 PORTER, DI 20
Idaho Power Company
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1 specified liquidated damages. Similarly, the EPC
2 contract contains terms requiring that the overall Plant
3 meet specific output performance standards, and if these
4 standards are not met, the EPC contractor must pay Idaho
5 Power liquidated damages.
6 TRASMISSION AN INTERCONNECTION
7 Q.How will the Langley Gulch Power Plant be
8 interconnected to the Company's transmission facilities?
9 A.A System Impact Study has been prepared by the
10 Company's Transmission Department. In addition, an
11 Application for Network Transmission Service for the
12 project has been submitted and is queued on OASIS as
13 Request No. 72568424.
14 The selected site provides for robust
15 integration into Idaho Power's transmission grid. The
16 transmission integration plan loops the existing
17 Ontario-Caldwell 230kV line (located 2.5 miles from the
18 Plant) into the Plant, and calls for construction of a
19 new 18 mile, 138kV line from the Plant to Wagner Tap, on
20 the existing Caldwell-Willis 138kV line. Wagner Tap is
21 approximately three miles from Caldwell Substation. This
22 18 mile line will be built using 230kV construction, but
23 will be operated at 138kV, so that when future load
24 growth drives the need for additional
25
454 PORTER, DI 21
Idaho Power Company
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1 capaci ty, this line can be inexpensively converted to
2 a230kV line.
3 In addition, locating generation on the west
4 side of the Treasure Valley improves reliability in the
5 Ontario-Caldwell area. The new Plant helps alleviate
6 problems (low voltage and heavily loaded lines)
7 associated with the loss of the Brownlee-Ontario 230kV
8 line.
9 Q.What is the cost of the interconnection?
10 A.Based on the System Impact Study, the estimated
11 cost of the transmission interconnection is $22, lOS, 000.
12 That figure does not include: (1) certain upgrades
13 recommended in the study to improve the transmission
14 system but not specifically required to integrate the
15 Langley Gulch Power Plant (bringing the total estimated
16 cost to $25,424,250, exclusive of contingencies) or (2) a
17 20 percent contingency added in recognition that final
18 transmission cost estimates have not been completed.
19 Final estimates will be completed during the Facility
20 Study, which is expected to be completed in September
21 2009.
22 During the Facility Study, a sub-synchronous
23 resonance ("SSR") analysis will be performed to determine
24 whether a potentially harmful torsional interaction
25 exists between the combined cycle units and the Ontario
455 PORTER, DI 22
Idaho Power Company
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10
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. 14
15
16
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25.
1 C231 series capacitor bank. If SSR interactions exist,
2 they may
3
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9
I
456 PORTER, DI 22a
Idaho Power Company
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17
1 be mitigated by modifying the capacitor bank, using SSR
2 relays, or adapting operating procedures at the Plant.
3 If these options do not work, then a filter scheme can be
4 used to mitigate SSR interactions, costing an estimated
5 $4-$8 million. Initial indications are that a filter
6 scheme will not be required, but that some other lower
7 cost mitigation measure may be required. The commitment
8 estimate also includes an expense ($1 million) associated
9 with this component, and substation communication costs.
10 Q.Is the interconnection dependent upon the
11 Company's completion of the proposed Hemmingway to
12 Boardman or Sand Hollow facilities?
13 A.No. The Plant will be interconnected with the
14 existing Ontario-Caldwell 230kV line and the
15 Caldwell-Willis 138kV line.
16 PLAT OPERATION AN BENEFITS
Q.Will Idaho Power have personnel capable of
18 operating a baseload resource of this type?
19 A.Yes. Idaho Power will be able to operate and
20 maintain this combined cycle power plant. Idaho Power
21 has been operating natural gas combustion turbines since
22 Evander Andrews Unit Nos. 2 and 3 were constructed in
23 2001. The Company added Bennett Mountain in 2005, and
24 Evander Andrews Unit No.1 in 2008. Idaho Power's
25
457 PORTER, DI 23
Idaho Power Company
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1 operations and maintenance staff is familiar with gas
2 operations and has developed extensive expertise with
3 Siemens F-Class gas turbines. In addition, the combined
4 cycle power plant will be controlled by the Siemen IS
5 T-3000 system, which is the control system currently used
6 to operate the Company's existing gas turbines.
7 The combined cycle plant staff will consist of
8 18 personnel, including 10 operators to provide 24 by 7
9 coverage, two maintenance mechanics, two technicians, an
10 engineer, a chemist, a clerk/materials coordinator, and
11 an operations and maintenance supervisor. These
12 indi viduals will be hired at various stages in the
13 construction process so that they will be familiar, as
14 needed, with the design and construction of the Plant and
15 will receive training prior to commercial operation.
16 The existing combustion turbine staff and the
17 new combined cycle staff will be combined to form a gas
18 group, reporting to one manager. This will facilitate
19 the sharing of knowledge and expertise among the plants
20 as well as allow the Company to shift manpower as needed
21 for maintenance.
22 Prior to commencing with Plant operations,
23 personnel will receive operating and maintenance training
24 as part of the contracts with Siemens and Kiewit/TIC.
25
458 PORTER, DI 24
Idaho Power Company
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1 Operating and maintenance procedures will be
2 developed and implemented with Siemens and Kiewit/TIC
3 prior to commercial operation of the Plant.
4 Q.What advantages does the Company's operation of
5 a base load resource of this type provide relative to the
6 operabili ty of the Company's generation and transmission
7 systems?
8 A.This power plant is a baseload facility with
9 inherent operational flexibility. It can be dispatched
10 to optimize the Plant's output and capabilities with
11 Idaho Power's existing generation fleet. The Plant can
12 change generation quickly to maintain system balance as
13 load varies or as intermittent resources such as wind and
14 solar vary their output. In light of the limited
15 capacity of the Company's existing hydro generation
16 resources to integrate intermittent generation resources
17 such as wind and solar generation, the flexibility this
18 Plant would provide is necessary to permit integration of
19 future intermittent generation resources.
20 In addition, the Plant will also provide
21 additional operating reserves necessary to reliably
22 operate Idaho Power's transmission and generation system.
23
24
25
459 PORTER, DI 25
Idaho Power Company
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1 ECONOMIC BENEFITS TO LOCA ECONOMY
2 Q.How will the Langley Gulch Power Plant impact
3 the local economy?
4 A.Construction of the Plant will offer a stimulus
5 to the Treasure Valley economy. The construction will
6 require a labor force of up to 120 workers for as long as
7 two years. These will include qualified local
8 electricians, pipefi tters, steelworkers, excavators,
9 carpenters, concrete workers, and laborers. In addition,
10 the construction will require the purchase of commodities
11 such as concrete, rebar, and steel, and the rental of
12 equipment.
13 As noted above, when construction of the Plant
14 is complete, the Company is expected to employ 18 people
15 to operate the Plant.
16 Finally, the Plant will be placed in the tax
17 base and the Company will pay property taxes during the
18 life of the Plant.
19 Q.Does this conclude your testimony?
A.Yes, it does.
460 PORTER, DI 26
Idaho Power Company
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18
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
5 the General Manager of Power Production at Idaho Power.
6 Q.Are you the same Vernon Porter that submitted
7 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
13 build-and-transfer arrangements in the RFP at issue. I
14 will also provide additional information concerning the
15 Commi tment Estimate and Staff's proposed adj ustments to
16 the Commitment Estimate.
17 BUILD-AN-TRASFER ARGEMNTS
Q.On page 36 of his direct testimony, Staff
19 witness Rick Sterling opines that Idaho Power Company's
20 ("Idaho Power II or "Company") decision to accept only PPA
21 and tolling agreement proposals, but not
22 build-and-transfer proposals, may have resulted in the
23 Company not receiving other potentially competi ti ve bids.
24 Mr. Sterling is also critical of what he characterizes as
25 the Company's.
461 PORTER, DI REB 1
Idaho Power Company
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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
11 for the Company's decision not to seek build-and-transfer
12 proposals in the RFP. The primary reason for not
13 accepting build-and-transfer proposals is based on the
14 Company's belief that build-and-transfer arrangements
15 present risks to the Company and, ultimately, its
16 customers that are significantly greater than the risks
17 associated with Power Purchase Agreements ("PPAs") or
18 tolling agreements, particularly in the case of a
19 baseload resource of the size and complexity of a
20 combined cycle gas plant.
21 As noted in my direct testimony, the Company's
22 own experience with build-and-transfer generation
23 projects, and its observations of build-and-transfer
24 combined cycle plants currently operated by other
25 utilities, substantiates the Company's belief that
build-and-transfer arrangements
462 PORTER, DI REB 2
Idaho Power Company
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1 pose unacceptable risk to the utility and its customers
2 in 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
6 unless the utili ty participates integrally in the design
7 and construction of the plant.
8 Prior to the Company's issuance of the 200S
9 Baseload Request for Proposal ("RFP"), Company
10 representatives inspected several combined cycle plants
11 and interviewed their operational personnel. Among the
12 plants visited was a combined cycle plant builtin Utah
13 pursuant to a build-and-transfer arrangement. In the
14 unanimous opinion of all team members who visited this
15 plant, the plant evidenced numerous design defects that
16 undermined the efficient and economical operation and
17 maintenance of the plant, delayed the planned commercial
lS operation of the plant, and caused significant project
19 cost overruns. In the Company's judgment, these design
20 defects likely resulted from a divergence of interest
21 between the owner and the developer. While the owner
22 desires a design that optimizes the plant's efficiency
23 and economical operation over the life of the plant, the
24 developer is incented to reduce its costs and,
25 correspondingly, maximize its profit. These incentives
463 PORTER, DI REB 3
Idaho Power Company
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1 may result in the developer minimizing expenditures
2 necessary to achieve an optimal long-term design, or
3 minimizing quality control expenditures necessary to
4 assure that the plant is builtin accordance with
5 applicable design and construction specifications.
6 Q.Has the Company actually encountered defects in
7 a generation facility that it acquired pursuant to a
8 build-and-transfer arrangement?
9 A.Yes. In the case of Idaho Power i s Bennett
10 Mountain plant, the failure of the developer to fulfill
11 its contractual obligations during construction
12 contributed to the creation of a latent defect that
13 manifested itself after commercial operation and lead to
14 a prolonged outage and direct repair expense in excess of
15 $14 million. Specifically, a contractor failed to install
16 the bolts in the turbine's air inlet plenum in accordance
17 wi th specific construction specifications. The developer
18 failed to detect the improper installation and a bolt
19 ultimately dislodged, was ingested in the turbine, and
20 caused extensive damage to the turbine. Although Idaho
21 Power considered the developer's position to be
22 commercially unreasonable and legally untenable, the
23 developer of the Bennett Mountain plant disavowed any
24 contractual obligation to reimburse Idaho Power for the
25 repair expense. The
464 PORTER, DI REB 4
Idaho Power Company
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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 utility'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
9 self-build arrangement, the utility has a direct
10 contractual relationship with the engineering,
11 procurement, and construction ("EPC") contractor and with
12 the maj or equipment suppliers. In a build-and-transfer
13 arrangement, the utility has a direct contractual
14 relationship with only the developer, and the developer
15 in turn has contractual relationships with the equipment
16 suppliers and EPC contractor. A utility's direct
17 contractual relationship with the EPC contractor and with
18 the equipment suppliers affords the utility the
19 opportunity to negotiate directly with the contractor and
20 equipment suppliers, and to secure contractual terms with
21 these counter-parties that optimize the design of the
22 plant for long-term operation, and permit the utility to
23 observe that the plant is constructed in accordance with
24 applicable specifications. Even during construction, the
25 utility has the ability to negotiate
465 PORTER, DI REB 5
Idaho Power Company
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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 utili ty is much more likely to offer engineering input
7 and authorize design changes and to monitor quality
8 control during construction than it could under a
9 build-and-transfer arrangement.
10 Q.What is the difference between detailed
11 specifications necessary for a RFP that invites
12 build-and-transfer proposals and the bid criteria
13 developed in the subject RFP?
14 A.The bid criteria necessary to evaluate bids for
15 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
18 build-and-transfer proposals. Bid criteria necessary to
19 support PPA or tolling agreement proposals can be
20 relatively more general because the bidder assumes risk
21 associated with design and construction. Detailed design
22 cri tería are, however, a necessary component of a request
23 for proposal inviting bids for build-and-transfer
24 projects of the complexity of a combined cycle plant.
25 The only means by
466 PORTER, DI REB 6
Idaho Power Company
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1 which the utility can ensure that the plant is designed
2 and constructed in a manner that assures that the plant
3 is capable of being operated and maintained in a
4 cost-effective and reasonable manner is by including in
5 the contract with the developer very detailed engineering
6 and construction specifications. This, in turn, requires
7 that the request for proposal inviting build-and-transfer
8 bids contain these detailed specifications, or the
9 evaluation of competing bids could become extremely
10 complicated and subjective. The detailed specifications
11 necessary to evaluate build-and-transfer proposals are
12 much more specific and include the detailed
13 identification, layout, and design of plant and equipment
14 for optimal plant operation, maintenance, and operator
15 safety.
16 With regard to the Baseload RFP, the self-build
17 team was not required to prepare detailed specifications
18 prior to submitting a bid. The team did work with the
19 EPC contractor during the proposal phase to determine
20 design criteria, plant layout, etc. However, detailed
21 design specifications for the Langley Gulch plant will
22 not be completed until well after the IPUC issues a
23 Certificate of Public Convenience and Necessity, should
24 it elect to do so.
25 Q.Can the development of a detailed design
467 PORTER, DI REB 7
Idaho Power Company
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. 14
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25.
1 specification that all bidders must follow in responding
2 to
3
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7
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468 PORTER, DI REB 7 a
Idaho Power Company
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1 an RFP eliminate the risks associated with a
2 build-and-trans fer 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,
6 detailed design specifications in the case of a
7 build-and-transfer arrangement do not reduce the risks to
8 the same level that direct contractual relationships
9 between the utility and the EPC contractor and equipment
10 suppliers reduce risk. In a build-and-transfer
11 relationship, by definition, the owner must work through
12 an intermediary - the developer - with regard to design
13 and construction matters. The owner has no contractual
14 authori ty to effectuate changes or improvements in design
15 or construction directly with the parties responsible for
16 design and construction - the engineer, construction
17 contractor, and equipment manufacturer. This fact, in
18 itself, reduces the owner's authority, influence, and
19 flexibility.
20 Moreover, the development of design
21 specifications in a competitive RFP procurement that
22 includes a build-and-transfer option must occur before
23 the RFP is distributed to the potential bidders. Thus,
24 in the case of a build-and-transfer arrangement, the
25 owner must develop specifications with a high level of
detail to reduce design and
469 PORTER, DI REB 8
Idaho Power Company
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1 construction risk before the RFP is distributed to
2 potential bidders. As a result, the development has to
3 be done generically, and without any input from the
4 engineer, construction contractor, or equipment
5 manufacturer that will design and construct the proj ect
6 and supply maj or equipment. In the case of a self-build
7 proj ect, the utility has worked extensively with the
8 engineer, construction contractor, and equipment
9 manufacturer even before the self-build bid was
10 submitted. If the self-build option is selected, the
11 interaction between the owner and these parties continues
12 as an i terati ve process through completion of the
13 project.
14 Q.Staff witness Sterling characterizes the
15 Company's conclusion that it did not have time to develop
16 a detailed design that would have allowed the Company to
17 accept build-and-transfer proposals as "a weak excuse II
18 because a project of this size and type was anticipated
19 for many years and required a long-lead time. He also
20 concludes that "much of the time Idaho Power may have
21 'saved' during the RFP stage by not preparing a detailed
22 proj ect design will be made up later when detail design
23 work must be done before construction begins." What is
24 your response to Mr. Sterling's criticisms?
25
470 PORTER, DI REB 9
Idaho Power Company
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1 A.Idaho Power did anticipate a proj ect of Langley
2 Gulch's size, just not this type. When the decision was
3 made in September 2007 to switch from a coal to a natural
4 gas plant due to difficulties with financing and carbon
5 risk, Idaho Power had to seriously retool its planning in
6 a short time frame to issue the RFP timely. Taking the 6
7 months needed to create detailed specifications for the
8 RFP would have delayed the project past 2012, which the
9 Company was not prepared to do. Moreover, it does not
10 appear that Mr. Sterling fully appreciates the
11 differences in complexity between the type of detailed
12 specification that the utility must create if an RFP is
13 going to accept build-and-transfer proposals and the much
14 less complex design work that is needed to submit a
15 proposal in an RFP.
16 Q.Is it reasonable to accept build-and-transfer
17 proposals in the absence of detailed design and
18 construction specifications developed prior to issuance
19 of the RFP?
20 A.No. For the reasons specified above, the
21 design and construction risks associated with
22 build-and-transfer proposals require that the proposals
23 be submitted in accordance with detailed specifications.
24 Moreover, in the absence of detailed specifications, the
25 process of
471 PORTER, DI REB 10
Idaho Power Company
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1 selecting a successful proposal becomes much more
2 subj ecti ve and difficult. Wi thout detailed
3 specifications, various proposals would likely contain
4 different design criteria, equipment quality, level of
5 redundancy incorporated in the basic design, adaptability
6 of the design and equipment layout to accommodate future
7 expansions , compatibility of control systems with Idaho
8 Power's existing systems, design features incorporated
9 for ease of operations, design features incorporated for
10 ease of maintenance, shop and warehouse space and
11 features, and specific design features to address extreme
12 temperature operation. These differences complicate an
13 evaluation process not only by increasing the number of
14 potential options but also by necessitating subj ecti vi ty
15 in evaluating the merit of various options.
16 Idaho Power believes that by limiting the RFP
17 to PPA proposals, tolling agreement proposals, and a
18 self-build benchmark proposal, the complications
19 associated with, and the subj ecti vi ty of, the evaluation
20 process are reduced. In this approach, each bidder is
21 responsible for operating and maintaining their proposed
22 proj ect for the duration of the agreement. Subsequently,
23 each bidder will incorporate their estimate of the costs
24 for operating and maintaining
25
472 PORTER, DI REB 11
Idaho Power Company
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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,
4 concurred that "the evaluation process could become
5 extremely complicated and somewhat subj ecti ve" if
6 build-and-transfer options were permitted without
7 including a detailed design specification in the RFP.
8 (See Exhibit No. 11, correspondence from R. W. Beck dated
9 April 14, 2009.)
10 Q.Did time permit the development of detailed
11 design and construction specifications in the RFP
12 process?
13 A.No . Given (i) the decision to accelerate the
14 in-service date to 2012, (ii) the information obtained
15 regarding critical equipment manufacturing lead times,
16 and (iii) the previously mentioned differences in project
17 design, the Company did not have enough time to prepare
18 detailed design and construction specifications and
19 release the RFP in time to meet the 2012 on-line date.
20 In early September 2007, the Company was still
21 exploring the possibility of satisfying its 2013 baseload
22 generation resource need by developing a coal-fired
23 generation facility. In mid-September 2007, the decision
24 to no longer pursue coal-fired generation and shift to
25 gas-fired resources was finalized. The Company then
473 PORTER, DI REB 12
Idaho Power Company
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24.25
1 looked at gas generation resource alternatives , visited
2 various
3
4 /
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6 /
7
8 /
9
474 PORTER, DI REB 12a
Idaho Power Company
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1 combined cycle projects, 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
7 resource, issuance of a request for proposals would allow
8 the Company to access multiple experienced gas-fired
9 resource developers. In March 2008, the Company
10 assembled an RFP Team to issue an RFP requesting that
11 independent power producers submit bids for the 2012
12 baseload resource and that the Company submit a Benchmark
13 Resource proposal.
14 That RFP was issued April 1, 2008, requiring
15 that bids be submitted no later than October 17, 2008.
16 The RFP called for the selected resource to be capable of
17 commercial operation with a high degree of operating
18 availability by June 1, 2012. Although the Benchmark
19 Resource team had performed some preliminary work
20 relative to the development of a benchmark resource
21 before the Company elected to issue the RFP - identifying
22 potential si tes suitable for location of the resource,
23 submission of requests for transmission studies, review
24 of existing generation facilities, and preparation of a
25 draft equipment RFP - the preparation of a bid by the
Benchmark Resource
475 PORTER, DI REB 13
Idaho Power Company
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1 team did not begin until after the RFP was issued on
2 April 1, 2009. Indeed, the preparation of a bid could
3 not begin until the RFP bid criteria were known. The
4 preparation of the Benchmark Resource team i s bid was not
5 completed until just prior to the bid submission deadline
6 of October 17, 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 taken
11 somewhere between four and six months to prepare detailed
12 design and construction specifications. The four to six
13 month estimate includes time for the Company to select
14 the design engineer, for the design engineer to produce
15 the initial draft specifications, for Idaho Power to
16 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 proj ects had been
20 permitted in response to the RFP, do you believe a
21 build-and-transfer option would have provided the Company
22 wi th a more economical resource option.
23 A.No. Aside from the inherent risks associated
24 with build-and-transfer options noted above,
25
476 PORTER, DI REB 14
Idaho Power Company
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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.
4 In a build-and-transfer arrangement, the proj ect owner
5 must assume not only the costs of design, construction,
6 and equipment but also must pay the developer a
7 substantial fee for its work associated with the proj ect.
8 This additional cost element makes it unlikely that a
9 build-and-transfer proj ect would be economically
10 competi ti ve with other 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
14 commencement of construction by six months, and
15 correspondingly extend the Langley Gulch in-service date
16 to December 1, 2012, evidenced the Company's recognition
17 that the plant was not needed to serve expected load in
18 the summer of 2012. Do you agree?
19 A.No. As discussed in the testimony of Mr.
20 Bokenkamp, the Company's current system loads, and its
21 projected future system loads, consistently have
22 evidenced the need for the Langley Gulch Plant to be
23 available to meet load in the summer of 2012.
.24
25 /
477 PORTER, DI REB 15
Idaho Power Company
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1 Q.In testimony you offered in opposition to the
2 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
5 Plant. What is the status of those discussions?
6 A. In order to satisfy expected load with greater
7 certainty and lower cost in the summer of 2012, Idaho
8 Power has reached an agreement in principal with the EPC
9 contractor to target an in-service date of July 1, 2012.
10 Specifically, the Company and the EPC Contractor have
11 agreed that if the plant is substantially constructed and
12 in-service by July 1, 2012, the Company will pay the
13 contractor $750,000 as an early completion incentive.
14 For each day prior to July 1, 2012, that the plant is
15 in-service, the Company will pay an additional incentive
16 of $10,000 up to $150,000 (i.e., up to fifteen days prior
17 to July 1, 2012). In addition, the Company has agreed to
18 pay up to $100,000 to the contractor to assist in
19 securing timely delivery of a critical path piece of
20 equipment, the steam turbine.
21 Q.Does Idaho Power expect to seek rate recovery
22 of these early incentive payments?
23 A.Yes. If the plant is in-service to meet summer
24 peak loads, the Company's customers should benefit
25
478 PORTER, DI REB 16
Idaho Power Company
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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
4 on-line date will result in an estimated savings of $4.7
5 million in reduced AFUDC.
6 Q.Does the EPC contractor expect to meet a July
7 1, 2009, in-service date?
8 A.We are advised by the EPC contractor that if
9 the preliminary permitting and equipment delivery
10 benchmark dates are met, we should expect that the plant
11 will be in service by July 1, 2012.
12 COST OF PROJECT DELAY
13 Q.Mr. Sterling has testified that the Company's
14 decision to slide the proj ect schedule six months, and
15 the resultant delay to December 1, 2012, of the
16 in-service date , resulted in a $ 6.8 million increase in
17 the cost of the proj ect.(Sterling Direct, pp. 17-18.)
18 Mr. Sterling then suggests that the Company's
19 shareowners, rather than its customers, should bear this
20 cost, and Mr. Sterling recommends that the amount be
21 excluded from any commitment estimate approved by the
22 Commission.(Id., p. 68.) Do you agree with Mr.
23 Sterling's conclusions?
24 A.No. I respectfully disagree with Mr. Sterling
25 for two reasons. First, Mr. Sterling is incorrect
479 PORTER, DI REB 17
Idaho Power Company
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16
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
6 financial conditions, the Company concluded it would be
7 in the customers' interest to delay the on-line date to
8 see if the Company could obtain ratemaking assurances
9 that would allow the Company to finance the proj ect using
10 tradi tional utility financing techniques. If it can
11 finance in this manner, the Company will save customers a
12 substantial amount of money as compared to the costs it
13 would incur under the other bids. In my mind, this is
14 defini tely a customer benefit and should not be used to
15 penalize shareholders.
Q.What are the actual costs associated with the
17 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
480 PORTER, DI REB 18
Idaho Power Company
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1
2
Price Escalation of the Gas line,
Water line, andInjection Wells $~ I I I I I I I I I
3 Total:$ 6,800,686
4 However, only the $~~ I I I I I of the $ 6.8 million
5 associated with potential labor escalation is directly
6 tied to the six-month delay of engineering and equipment
7 procurement.
8 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
9 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
10 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
11 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 II I I I I I I I I I I II I I I I I I I I
12 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
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 I I I I I I I I I I I I I I I I I I
14 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
15 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
16 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
17 111111111111111111111111111111111111
18 The contingencies related to material price
19 escalation and price escalation of the gas line, water
20 line, and inj ection wells could theoretically be impacted
21 by the six-month delay; however, they are more
22 realistically tied to the escalation risk between project
23 bidding and the construction period ending in 2012. A
24 commitment estimate associated with these items would
25 have
481 PORTER, DI REB 19
Idaho Power Company
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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 responsible
4 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
9 a 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
17 proj ect without ratemaking assurances from the
18 Commission . It was a prudent decision to secure
19 agreement of the EPC contractor to maintain the viability
20 of the project while the Commission considered whether to
21 issue a certificate. Shareowners should not be penalized
22 for a prudent decision that will benefit the customers.
23 The Commitment Estimate contingencies are for
24 those components of the overall price of the project
25 where the
482 PORTER, DI REB 20
Idaho Power Company
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1 Company continues to assume price risk . Given high
2 volatili ty in the commodities markets, it is appropriate
3 that a reasonable contingency be included in the
4 Commi tment Estimate.
5 HA CAP/SOFT CAP
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 i S recommendations regarding caps, do you agree
14 wi th his methodology in applying those caps?
15 A.No. There are a number of errors or inequities
16 in the manner in which Mr. Sterling recommends
17 application of the caps. Specifically:
18 1.Labor Escalation Costs. For the reasons
19 specified above (see, "Cost of Proj ect Delay"), labor
20 escalation costs of $/////////// should be included
21 wi thin the Soft Cap on line 36.
22 2.Air Permitting. Staff recommends that air
23 permitting costs be included, in full, wi thin the Soft
24 Cap column (p. 66, ll. 14-18). However, Staff's
25 testimony
483 PORTER, DI REB 21
Idaho Power Company
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1 shows no allotment under the Soft Cap. Exhibit No. 109,
2 l. 21.) This is an apparent mathematical error and air
3 permi tting 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
7 the Commitment Estimate. These components include (1)
8 price escalation on materials, estimated at $///////////
9 and (2) gas pipeline, water pipeline, and the inj ection
10 well design and construction, estimated at $/////////.
11 The total commitment contingency added was $/////////.
12 These contingencies were added for price escalation risk
13 of materials over the duration of the proj ect (from the
14 2008 bid to 2012 completion). These materials include
15 all components of the project, including the material
16 risk component of the EPC Contract in which Idaho Power
17 retains 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
23 Estimate, Staff Exhibit No. 118, should be included in
24 Mr. Sterling i s Soft Cap as a fully recoverable cost.
25
484 PORTER, DI REB 22
Idaho Power Company
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1 4.RFP Team Expenses. Staff recommends that
2 the RFP Team Expenses shown on Line 43, Staff Exhibit No.
3 109, be excluded from recovery from the Soft Cap and Hard
4 Cap columns. Staff contends that these costs would have
5 had to be included in all proposals as part of the
6 evaluation process and should not be allowed to be added
7 to the Commitment Estimate after the winning the bid.
8 However, I believe Staff comes to that conclusion based
9 on the mistaken impression that these are costs incurred
10 by the Benchmark Resource team. They are not. These are
11 the 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 s.Start-Up Fuel Costs. Under normal utility
15 accounting practice, start-up fuel, net of the market
16 value of the energy generated by the start-up fuel, is
17 capi tali zed 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
21 B, advised the Company that its bid did not include
22 start-up fuel costs and it would expect the Company to
23 provide the fuel at its expense. In any event, start-up
24 fuel expense is a necessary cost of putting the plant in
25 service and,
485 PORTER, DI REB 23
Idaho Power Company
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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
5 contained in the Commitment Estimate should be included
6 in either his Soft Cap or Hard Cap. He makes this
7 recommendation because these upgrades are not required as
8 part of the Langley Gulch proj ect and, in his view, Idaho
9 Power should be required to demonstrate the prudence of
10 an investment in these upgrades in a future general rate
11 case.
12 The transmission upgrades Mr. Sterling is
13 referring to total $/////////, including AFUDC (Exhibit
14 No. 109, l. 45), consisting of two components:(1) the
15 incremental cost of $///////// to loop the
16 Ontario-Caldwell 230 kV line in and out of the Langley
17 Gulch plant in lieu of building just a tap connection and
18 (2) the incremental cost of $///////// to build the new
19 18 mile Langley Gulch-Wagner Jct. 138 kV line using 230
20 kV construction standards. The transmission cost listed
21 in the Commitment Estimate column is $//////////.
22 (Exhibi t No. 109, l. 51.) This is the estimated cost to
23 interconnect the Langley Gulch Power Plant to Idaho
24 Power's existing transmission system by tapping the
25 nearby Ontario-Caldwell 230 kV line (2.5 mile tap) and
building a new 18 mile Langley Gulch-Wagner Jct.
486 PORTER, DI REB 24
Idaho Power Company
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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
5 interconnection of a new resource should be designed so
6 that there should be no loss of load or Idaho Power
7 network resource generation following an N-1 outage.
8 Meeting this standard is required from all parties
9 seeking interconnection. It is not discretionary.
10 Although this $//// million transmission
11 integration option meets the criteria established by the
12 RFP, Idaho Power's Transmission Department recommends
13 that the Ontario-Caldwell 230 kV line be looped into the
14 plant 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
17 a 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
23 addi tional cost for this upgrade is $////////////. The
24 loop also provides the additional benefit of providing a
25 reasonable
487 PORTER, DI REB 25
Idaho Power Company
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1 connection to the grid in case the new Langley Gulch-
2 Wagner Jct. line is delayed. Since the 230 kV loop
3 upgrade directly benefits plant reliability, I believe
4 its costs should be included in the Soft Cap for the
5 Langley Gulch proj ect.
6 The second upgrade entails building the new 18
7 mile Langley Gulch-Wagner Jct. 138 kV line using 230 kV
8 construction standards. Load growth will eventually
9 drive the need for the upgrade to 230 kV. Constructing
10 this line at 230 kV standards now will be less expensive
11 than re-permitting and rebuilding the line at a future
12 date.I believe the $1.8 million upgrade costs should
13 be recovered as part of the Langley Gulch proj ect and
14 included in Mr. Sterling's Soft Cap.
15 7.Remaining Items. Mr. Sterling recommended
16 that many of the components from Idaho Power's Commitment
17 Estimate be reduced in his Soft Cap proposal. His
18 proposed reductions (ranging from 5 percent to SO
19 percent) include the following items:
20 1.Water Right
21 2.Water Line Construction
22 3.Water Pump Station Property and
Pipeline Easement Property
23
4. Gas Line Construction
24
25 /
488 PORTER, DI REB 26
Idaho Power Company
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1 s.Landscaping and Aesthetics
2 6.Vehicles & Equipment
3 7 .Start-Up Expenses
4 8.IPC Supplied Equipment
5 9.Idaho Power Engineering Oversight and
Support
6
10. Gas Line Tap and Meter
7
11. SSR Study/Implementation
8
12. Transmission Cost
9
10 Idaho Power developed the cost estimates for
11 these components of the Proj ect based on (1) estimates
12 from other Idaho Power departments, (2) estimates from
13 outside firms with expertise in their respective areas,
14 (3) actual costs of equipment and material purchase, (4)
15 reasonable labor costs, and (5) established contract
16 costs.These are reasonable engineering estimates that
17 reflect our best estimate as to what it will cost to
18 construct these aspects of the proj ect.
19 The reductions suggested by Mr. Sterling are
20 unrealistic. Idaho Power cannot build the proj ect for
21 the amounts suggested by Mr. Sterling. Mr. Sterling
22 should have used 100 percent of the amounts provided in
23 the Commitment Estimate in his Soft Cap.
24
25 /
489 PORTER, DI REB 27
Idaho Power Company
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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. Gi ven 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 AGREEMENTS
10 Q.Why did the Company enter into reservation
11 agreements with the turbine supplier for the gas and
12 steam turbines, even before the self-build option had
13 been 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
16 its customers. Although the Company was unaware whether
17 its self-build option would ultimately be selected or
18 built, entering into reservation agreements for the
19 critical path turbines was necessary in order to ensure
20 that, when the bidding process was completed, the Company
21 had at least one generation option capable of meeting
22 load in 2012. In mid-September 2007, demand for gas
23 equipment was high, leading to long lead times. This
24 fact was confirmed by our Owner's
25
490 PORTER, DI REB 28
Idaho Power Company
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1 Engineer (Power Engineers), potential OEM suppliers, and
2 EPC contractors.
3 It became clear that in order for a plant to be
4 in service for the summer of 2012, the Company would need
5 to enter into reservation agreements for the gas and
6 steam turbines. On September 19, 2008, a month prior to
7 the RFP bid submittal date, Idaho Power entered into
8 reservation agreements with Siemens for gas and steam
9 turbine equipment.
10 Q.Is the long lead time for turbines - from the
11 date of order until the date of delivery - confirmed by
12 any other sources of information?
13 A.Interestingly, Intervenors NIPPC' sand ICIP 's
14 wi tness, Dr. Reading, offers evidence confirming this
15 fact. In his testimony, Dr. Reading references a letter
16 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 proj ect schedule.
19 (Exhibits Nos. 703 and 205.) In that letter, the
20 prospecti ve bidder 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 I I
II I I I I II 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 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 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 I23 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 I I I I I I I I I I I I I I I I I I I I24 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
25
491 PORTER, DI REB 29
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1
2
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 II 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 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 II 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 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 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 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 III II I I I I I I I I I I I I I I I III I I I I I I I
3
4
5
6
7
8
9 ASSIGNABILITY OF TURBINE AGREEMNTS
10 Q.During the RFP process, why did Idaho Power not
11 offer to assign its turbine equipment to whatever bidder
12 was ultimately selected?
13 A.I am aware that during the pre-bid process the
14 Company informed prospective bidders that it did not have
15 the authority to assign equipment to any third party.
16 This statement was true. Until shortly before bids were
17 due, the Company had not completed its selection of a
18 manufacturer for the turbines, and had not entered into a
19 reservation agreement with any supplier. Those
20 reservation agreements were effective September 19, 2008.
21 Q.Did the reservation agreements provide IPC with
22 unfettered discretion to assign them to any third party?
23 A.No. The Company's representatives negotiated
24 vigorously with the equipment supplier to permit
25
492 PORTER, DI REB 30
Idaho Power Company
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1 the Company the greatest flexibility to assign the
2 reservation agreements. It was in the Company's
3 interests to have such flexibility. In the end, the
4 supplier would not agree to permit the Company to assign
5 the agreements to an unrelated third party without
6 securing the consent of the supplier, which the supplier
7 could not unreasonably withhold. Given this consent
8 provision, the Company was not legally entitled to assure
9 prospective bidders that they could assume contractual
10 rights to the turbines.
11 CACELLATION FEES
12 Q.Mr. Sterling discusses in his direct testimony
13 the cancellation fees to be incurred by Idaho Power if
14 this proj ect is delayed. He states that the cancellation
15 fees are approximately $8. 7 million for the gas and steam
16 turbines, combined. Does Mr. Sterling capture all of
17 potential expense to the Company if this proj ect is
18 delayed?
19 A.No. Depending on the length of the delay,
20 cancellation charges may be substantially more than $8. 7
21 million. The approximately $8.7 million represents
22 payments already made by the Company to Siemens for the
23 gas and steam turbine reservation fees and the initial
24 contract payment for the steam turbine. The details of
25 the cancellation charges are outlined in the Gas Turbine
493 PORTER, DI REB 31
Idaho Power Company
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1 and Steam Turbine Agreements Idaho Power provided in the
2 Staff's Production Request No. 77. They were also
3 outlined in the Company's June 8, 2009, 8-K filing with
4 the Securities and Exchange Commission.
5 If Idaho Power cancels the purchase agreements
6 on September 1, the Company would be required to pay a
7 cancellation fee of 35 percent of the total purchase
8 price of the gas turbine, less any payments already made
9 by Idaho Power under the Gas Turbine Agreement. The Gas
10 Turbine Agreement also contains a schedule of
11 cancellation fees IPC must pay if it terminates the Gas
12 Turbine Agreement at any time during the contract term,
13 absent assignment of the Gas Turbine Agreement by IPC
14 wi th the written consent of Siemens Energy. The
15 cancellation fees are based on a percentage of the total
16 gas turbine purchase price and increase monthly from 20
17 percent on July 1, 2009, to 100 percent on or after
18 September 1, 2010.
19 The steam turbine purchase agreement with
20 Siemens Energy ("Steam Turbine Agreement II ) also contains
21 a cancellation fee schedule. Idaho Power has the right
22 to terminate the Steam Turbine Agreement at any time upon
23 paying a cancellation fee to Siemens Energy based on a
24 percentage of the total purchase price of the steam
25 turbine, absent assignment of the Steam Turbine Agreement
494 PORTER, DI REB 32
Idaho Power Company
.1 by Idaho Power with the written consent of Siemens
2 Energy. The Steam Turbine Agreement cancellation fee
3 percentage increases monthly from 10 percent on February
4 15, 2009, to 100 percent on or after May 15, 2011. The
5 cancellation fee is 15 percent on September 1, 2009.
6 On September 1, the cancellation fees for the gas and
7 steam turbines, based on current contract amounts, are as
8 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
13
. 14
18
20
21
22
23
24
25.
12 Does this conclude your testimony?Q.
A.Yes, it does.
15
16
17
19
495 PORTER, DI REB 33
Idaho Power Company
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15
1 (The following proceedings were had in
2 open hea~ing.)
3 MR. KLINE: We also have one other exhibit
4 that we'd like to distribute at this point to Mr. Porter
5 so that he can address it.
6 (Ms. Nordstrom approached the witness.)
7 COMMISSIONER KEMPTON: And you'd like to
8 have that exhibit --
9 MS. NORDSTROM: Exhibi t 26.
10 (Idaho Power Company Exhibit No. 26 was
11 marked for identification.)
12 COMMISSIONER KEMPTON: Mr. Kline, am I to
13 take it that this is a confidential sheet?
14 MR. KLINE: That is correct.
COMMISSIONER KEMPTON: And do you wish to
16 discuss this in the environment of a confidential hearing
17 item?
18 MR. KLINE: I'm afraid we're going to have
19 to. The material in here is information that has been
20 provided by the manufacturers, equipment manufacturers,
21 and they are very jealously guarding their pricing.
22 COMMISSIONER KEMPTON: Okay, as explained
23 yesterday when we get to this point in the hearing where
24 this information is discussed, if not right now, I'll
25 have to excuse people who have not signed a
CSB REPORTING
[phone]
496 PORTER (Di)
Idaho Power Company
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1 confidentiali ty agreement with Idaho Power. Mr. Kline.
2 MR. KLINE: Oh, some of the parties
3 have.
4 COMMISSIONER KEMPTON: And then you're
5 also directed to strike from your memories anything you
6 may have seen on that sheet.
7 (Pause in proceedings.)
8 **********BEGINNING OF CONFIDENTIAL INFORMTION**********
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Idaho Power Company
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1 *************END OF CONFIDENTIAL INFORMTION************
2 the witness may step down, then.
3 THE WITNESS: Thank you.
4 MR. WOODBURY: This is only on his --
5 MR. KLINE: We need to bring the rest of
6 the troops back.
7 COMMISSIONER KEMPTON: Okay, and that's
8 what I was thinking in terms of his -- so he doesn't get
9 to step down. Go ahead and call everybody back in.
10 (Pause in proceedings.)
11 COMMISSIONER KEMPTON: Okay, so we have
12 finished the confidentiality review on this and we are
13 back in cross-examination and Mr. Richardson, you would
14 be first up.
15 MR. RI CHARDSON : Than k you, Mr. Cha i rman .
16
17 CROSS-EXAMINATION
18
19 BY MR. RICHARDSON:
Q Mr. Porter, would you refer to page 3 of
21 your direct testimony? And beginning on line 16, you
22 state that given the current economic crisis and the
23 challenges it creates in financing the project, Idaho
24 Power has negotiated with the EPC contractor to delay
25 commencement of its work until September 1, 2009, and my
CSB REPORTING
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529 PORTER (X)
Idaho Power Company
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1 question is, what was the original commencement date for
2 the EPC contractor to commence work?
3 A March 1st, 2009.
4 Q And what work did you envision that the
5 EPC contractor would be embarking upon on March 1st?
6 A The procurement of engineered equipment.
7 This would be the HRSG, the heat recovery steam
8 generator, the cooling tower, the condenser and the
9 generator step-up transformer.
Q And so that agreement was obviously
11 negotiated sometime prior to March 1st?
12
13
14
A Yes.
Q What time frame, approximately?
A We had -- let me correct myself and I'll
15 explain. The negotiations with our EPC contractor would
16 have been, let's just say, late spring/early summer of
17 2008 and we began, of course, negotiating with them on a
18 contract. We signed a memorandum of understanding prior
19 to the bid submittal in October of 2008, and then we
20 began working on the final contract. That final contract
21 took some time to finish up, so -- excuse me. We had a
22 memorandum of understanding and were negotiating the
23 final contract language. It was essentially complete,
24 just had to finish up a few last details, but the plan
25 was to have that contract finished up and begin on March
CSB REPORTING
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530 PORTER (X)
Idaho Power Company
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1 1st with the engineering and work that would be required
2 for the procurement of that equipment.
3 Q So you had anticipated that the EPC would
4 begin its work on the proj ect on March 1st and you
5 started -- you did an MOU with the EPC in October and
6 when was the EPC agreement finalized?
7 A The EPC, the memorandum was, memorandum of
8 understanding was, completed before we submitted the bid
9 and then the actual final details were actually
10 finalized -- let's see if I have my notes here someplace.
11 It was actually finalized in the spring, the spring of
12 2009, so it was roughly April.
13 Q But if the EPC contractor was supposed to
14 start work on March 1st, you had the finalized agreement
15 after the scheduled start date?
16 A We would have -- remember at that time we
17 were already looking at the delay of the project and so
18 if we would have started on March 1st, that EPC contract
19 would have been completed before March 1st, but there was
20 no rush to finalize the very last little details of it at
21 that point.
22 Q Okay. On your rebuttal testimony on page
23 4, this is in relationship to your discussion about why a
24 build and transfer process is not desirable from the
25 Company's -- build and transfer arrangement is not
CSB REPORTING
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531 PORTER (X)
Idaho Power Company
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1 desirable from the Company' s perspective and I was
2 wondering, first of all, as a background, you currently
3 have three gas-fired combustion turbines on-line;
4 correct?
5 A No, we have four.
6 Q You have four, and were those plants build
7 and transfer arrangements?
8 A The Danskin 2 and 3 was not, or Evander
9 Andrews, and the Bennett Mountain and Danskin No.1,
10 Danskin or Evander Andrews No.1, were build and
11 transfer. These were simple cycle peaker units and did
12 not have the same complexity, nor size, or size, as a
13 combined cycle plant would, so the Company did not feel
14 like it needed to have, at that time didn't feel like it
15 needed to have, the detailed specifications for a plant
16 like that.
17 Q But your point here isn't that the
18 specific construction specifications isn't really what --
19 is at the heart of your objection to build and transfer,
20 your point here, correct me if I'm wrong, is that you
21 can't control the quality and here you reference this
22 $14 million repair bill?
23 A Yes.
24 Q What were the circumstances surrounding
25 that?
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532 PORTER (X)
Idaho Power Company
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1 A The context of my -- my concern about
2 build and transfers is, as my testimony describes, has
3 several different aspects to it, but, first of all, is
4 that for a plant the size and complexity of a combustion
5 turbine proj ect, you must have detailed specifications
6 for that. There i s also other risks with respect to
7 interest and direct relationship with the contractor, but
8 with respect to Bennett Mountain, that i s clearly a
9 si tuation where the divergence of interests surfaced
10 itself, where you have a developer who i s focused on short
11 term, getting the project on-line, getting it built and
12 getting it through the warranty period, not focusing
13 enough attention on quality assurance, on making sure
14 that that plant is designed, the nuts and bolts of it are
15 designed, so that it i s going to be good for long-term
16 maintenance and reliability, and so this is where it
1 7 showed up.
18 The developer in this case didn't have the
19 quality assurance program necessary to build that
20 turbine. It turns out that the bolts on the air intake
21 of that turbine were not torqued properly and not tack
22 welded as they should have been as called out and so
23 eventually a bolt loosened up, went through the turbine
24 and caused $14 million worth of damage and, of course,
25 when we went back to the developer for assistance, we had
CSB REPORTING
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533 PORTER (X)
Idaho Power Company
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1 just exceeded the warranty period and he refused to help
2 us, so that divergence of interest is something that's a
3 risk that's associated with build and transfers. It's
4 something we're very concerned about.
5 I'm also not saying that there i s not a
6 place for a build and transfer. In my opinion, I think
7 the place for where a build and transfer makes sense is
8 when you have a site and you have the equipment and you
9 have specifications, that reduces the risk associated
10 with build and transfers.
11 Q At line 22 on page 4 of your rebuttal, you
12 state that it's Idaho Power's position that the
13 developer iS, the developer's, position is legally
14 untenable. What do you base that on?
15 A That contractor had a -- the developer had
16 a responsibility to deliver us a reliable plant when they
17 were finished with it. The plant did not, was not
18 reliable. It had a latent defect in it that was a time
19 bomb waiting to explode because of a lack of quality
20 assurance.
21 Q And the question goes to your legal
22 conclusion that the developer's position is untenable,
23 what do you base that on?
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25
A It's based on the fact that they did not
li ve up to their terms, the terms of the agreement, the
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534 PORTER (X)
Idaho Power Company
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1 build and transfer agreement, by delivering us a proj ect
2 that had a latent defect in it.
3 Q And the developer's response to that is
4 that the warranty period had expired?
5 A Yes.
6 Q And so is it your view that the warranty
7 period has not expired?
8 A No, I agree the warranty period had
9 expired; however, they did not live up to the terms and
10 condi tions of the agreement where they would deliver us a
11 reliable plant.
12 Q So it's Idaho Power's position that that
13 developer is still responsible for those costs?
14 MR. KLINE: Mr. Chairman, I think the
15 question has been asked and answered.
16 MR. RICHARDSON: Mr. Chairman, that
17 question hasn't been asked yet.
18 COMMISSIONER KEMPTON: Mr. Richardson,
19 would you simply focus on a single question and then move
20 on because we're going around and around the legal issue
21 that you're driving at.
22 MR. RICHARDSON: Thank you, Mr. Chairman.
23 Q BY MR. RICHARDSON: I'll just get to the
24 point. Is that $14 million currently being paid for by
25 the ratepayers?
CSB REPORTING
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535 PORTER (X)
Idaho Power Company
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Mr. Chairman, I'd ask that you instruct
counsel for Idaho Power to stop instructing his
3 witness.
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5 Mr. Richardson.
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8 again?
9 Q
COMMISSIONER KEMPTON: Noted,
MR. RICHARDSON: Thank you, Mr. Chairman.
THE WITNESS: So what is the question
BY MR. RICHARDSON: The question is are
10 the ratepayers covering that $14 million?
11 A That was paid from insurance. We, of
12 course, covered our deductible, insurance covered the
13 ma j 0 r i t Y 0 fit.
14 Q So the answer is no?
18
19 That's all I have.
22 you.
15 A No, the answer is to a certain extent,
16 yes. I mean, we paid our deductible and I don't have the
17 details, but I'll stop at that.
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MR. RICHARDSON: Thank you, Mr. Chairman.
COMMISSIONER KEMPTON: Ms. Ackerman.
MS. ACKERMAN:None, Your Honor. Thank
COMMISSIONER KEMPTON: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Purdy.
CSB REPORTING
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536 PORTER (X)
Idaho Power Company
.1 MR. PURDY: I have none. Thank you.
2 COMMISSIONER KEMPTON: Mr. Miller.
3 MR. MILLER: Thank you, Chairman.
4
5 CROSS-EXAMINATION
6
7 BY MR. MILLER:
8 And hello. Please forgive me if I'mQ
9 asking questions that are redundant. We've been out of
10 the room for awhile. I just have a few questions. On
11 page 33 where we're talking about the cancellation
12.13
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A Page 33 of which --
Q I'm sorry, of your rebuttal, direct
rebuttal, I'm sorry, Mr. Porter, of your testimony where
15 you've identified the total cost of $23. 7 million.
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A Yes.
Q I guess my question is what the ratemaking
18 treatment of that amount might be and I also am wondering
19 whether given the remarks on page 28, and I think it's
20 line 21 through 23 where we're talking about the amount
21 of gas plants available in the market, I just wonder --
22 well, first of all, the ratemaking treatment, I guess
23 that would be my first question.
24 I would defer that to Ric Gale, Mr. Gale,A
25 wi th respect to ratemaking issues.
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537 PORTER (X)
Idaho Power Company
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1 Q Following up on that, then, has the
2 Company contacted given the market or the availability of
3 turbines on the market, has the Company contacted Siemens
4 to determine whether the cancellation fee might be
5 negotiable?
6 A We have not contacted them other than
7 through the negotiation of the original contract. We
8 have not gone back and contacted them about that.
9 Q One last question, then, I guess referring
10 to your direct rebuttal on page 12, line 9, I think it
11 is, where we're talking about whether the time -- did
12 time permit the development of a detailed design and
13 construction specifications in the RFP process, and your
14 answer, I think, was no and I guess my question would be
15 had there been more time, would the outcome perhaps have
16 been different?
17 A Perhaps, as what was going on at the time,
18 of course, we were busy developing a coal resource and
19 when the decision was made to pursue natural gas, we
20 still had, I still had my project manager Ryan Adelman
21 down in Salt Lake working on the Bridger project and so
22 we brought him back and formed the team and began doing
23 the due diligence on what it would take to build gas
24 resources, getting to know what the market was like, what
25 equipment was available. Those types of things would be
CSB REPORTING
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538 PORTER (X)
Idaho Power Company
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1 a basis for however the Company would proceed with
2 acquiring that resource, so there was no time.
3 We estimate between four and six months to
4 develop those design specifications and my inclination,
5 it would be more toward the six months' time frame to do
6 it. It would be a complex specification because it could
7 have been a two-on-one, a 600 megawatt resource or a 300
8 megawatt resource, water cooled, air cooled, so I think
9 it would be a great deal of working in putting that
10 specification together for it, so by the time that
11 specification is done, the market was such and you went
12 ahead and proceeded with an RFP, there was not time to
13 order the equipment and have it on-line in time for 2012
14 summer, just didn't have the time.
15 Q I do have one last question, if I could,
16 and I appreciate that answer. The incentive payment of
17 about a million dollars or so to complete the proj ect in
18 June as opposed or July as opposed to December, the six
19 months' difference, it's the Company's position that that
20 should be included in rates?
21 A That is correct.
22 Q Could you briefly explain, and I know
23 you've discussed it in your direct rebuttal, but the
24 rationale for that?
25 A In my opinion, there's great benefits to
CSB REPORTING
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539 PORTER (X)
Idaho Power Company
1 the customer for doing that. First of all, even though.2 we had to delay the resource, the need never went away.
3 The summer of 2012 was the target and so by bringing it
4 back, we were able to get that unit back on-line and
5 ready for service for summer 2012. We're able to save
6 AFUDC. Our calculations were by moving it forward we
7 could save about $4.7 million of AFUDC. We're
8 expecting -- well, it's very possible that we may have
9 600 megawatts of wind on by the summer of 2012 and so the
10 ability to help us to integrate the wind, lots of
11 benefits for bringing it back.
12 Also, once again, another summer of not
13 having to rely on non-firm transmission which is a bear..14 I've spent many years in operations and I can tell you
15 that it is not prudent to operate this system relying on
16 non-firm transmission. It's the first thing to get cut
17 and it's not just for problems on our system. If there's
18 problems on other systems due to the rules and
19 regulations in the WECC, our transmission can get cut for
20 other people's problems and that happens and it's a
21 nightmare trying to operate it and keep the lights on
22 relying on non-firm transmission. I just don't think
23 that's prudent to continue to do it to the extent we are,
24 so there's a lot of benefits in bringing it back to the
.25 summer of 2012 for the customers.
CSB REPORTING
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540 PORTER (X)
Idaho Power Company
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MR. MILLER: I thank you, Mr. Porter, and
I apologize for going over old ground if it has already
3 been covered.
4 COMMISSIONER KEMPTON: No reason to
5 apologize. We kicked you out, you have your chance.
6 Ms. Bridge.
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8 Mr. Chairman.
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14 BY MR. WOODBURY:
MS. BRIDGE: I have no questions,
COMMISSIONER KEMPTON: Mr. Woodbury.
MR. WOODBURY: Thank you, Mr. Chairman.
CROSS-EXAMINATION
Good morning, Mr. Porter.
Good morning.
Looking at your direct testimony, you
18 indicate you're the general manager of power productLon
15 Q
19 and you've been employed with Idaho Power for 19 years.
16 A
20 How long have you held your current position?
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22
17 Q
Approximately three years.
Okay, and then you've held that title only
23 so long -- I think the only resources that the Company
A
Q
24 has acquired, hard resources, I guess, would be simple
25 cycle combustion turbines?
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541 PORTER (X)
Idaho Power Company
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1 A That is correct.
Q And did you work in this division prior to
holding this title?
A No,I have not.
Q Okay,with respect to the --well,in your
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6 posi tion, you're responsible for bringing on supply
7 resources?
8 A Yes.
9 Q And that falls out of sort your task, the
10 integrated resource plan, do you have any participation
11 in that process in determining preferred portfolio
12 resources?
13 A Any interaction on that would simply be to
14 support what Mr. Bokenkamp' s team would be doing. We
15 actually -- my senior manager over engineering and
16 construction who has been with power supply for a long
17 time in the construction business, his expertise of over
18 20 years in building and constructing plants, he is on
19 the IRP team to help provide input from a power
20 production perspective. We're the group that operates
21 and maintains and builds plant and so modifies and makes
22 sure we're in compliance with FERC standards. We have
23 generation dispatch, all those kinds of things, so we do
24 participate, I guess answering your question, is that we
25 do have a member of our team, Scott Larondo, our senior
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Idaho Power Company
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1 manager of engineering and construction, helping out with
2 the IRP.
3 Q Okay, yes, operation and maintenance and
4 construction is what you do?
5 A Yeah.
6 Q And as part of that, one of your tasks to
7 secure a resource, it's your responsibility to, I guess,
8 secure contractors for your EPC contracts, energy,
9 procurement and construction?
10 A Yes.
11 Q Okay, with respect to Bennett Mountain,
12 there was some discussion regarding the problem that the
13 Company had with that resource, but that was a resource
14 that was brought on-line in 2005. Were you involved in
15 the RFP for that?
16 A No, I was not.
17 Q Do you know if any of those single cycle
18 resources that you have, the combustion turbines, the
19 Company and the RFP' s provided specifications as part of
20 the RFP process?
21 A It is my understanding that the
22 specifications were not detailed design specifications,
23 but there were some specifications. That's the best of
24 my knowledge.
25 Q And as a result of, I guess, your field
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Idaho Power Company
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1 trip to Utah and looking at a combined cycle combustion
2 turbine there -- well, with respect to the single cycle
3 and turnkey or build and transfer operations, you think
4 that that is only a viable option if the Company does
5 provide the detailed design specs up-front?
6 A Must have the design, the detailed design,
7 specs. There are other risks, too, but that's critical.
8 You've got to have it.
9 Q I mean, but this can't be something that
10 the Company has just discovered, I mean, because there
11 are quite a few utilities that acquire resources as build
12 and transfer and is it general utility practice in the
13 RFP as part of that process to provide the detailed
14 design specs?
15 A You know, I don't know if there's a
16 general utility practice out there. I think every
1 7 utility's circumstances are different and, for instance,
18 like I mentioned before, maybe utilities would already
19 have a site or have their equipment they desire or other
20 things that might mitigate the risks of build and
21 transfers, but I don't know specifically what each
22 utili ty, how they prefer to do business, but what I do
23 know is that based on what I've seen and lessons learned
24 from Bennett Mountain and certainly the Utah plant was
25 that for a unit like a combined cycle plant, the owner
CSB REPORTING
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544 PORTER (X)
Idaho Power Company
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1 and operator of that plant better be involved very much
2 so in the design and construction of that plant.
3 At Utah, I did not go down to the Utah
4 plant, but when our engineers came back, they said that
5 was the worst designed plant they had ever seen in their
6 lives and that gets your attention pretty quick. We i re
7 talking pipes in walkways. We're talking unable to
8 access gauges and meters. The maintenance folks there at
9 the plant said that they weren't even sure they could
10 even pull the boiler feed pump if they had to maintain
11 it. There was just no attention to designing that plant
12 for maintenance and there were other things involved with
13 that plant, but anyway, it just convinced me and our team
14 that if we're going to have a plant like this, we need to
15 have involvement.
16 Q A more hands-on approach?
17 A Yes.
18 Q In those type of operations or I guess a
19 build and transfer, can the Company have a representative
20 on site to act as an agent in the construction process?
21 A Yes, we can, but contractually speaking,
22 one of the concerns we have is not having a direct
23 contractual ability to influence the long-term
24 maintenance of that plant and construction of it, excuse
25 me, the ability to influence -- let me say this right,
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Idaho Power Company
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1 the maintenance and operation of the plant as it's
2 designed and constructed; whereas, if it IS because our
3 contractual relationship is with the developer. It's not
4 wi th the EPC contractor or the equipment person. The
5 developer has the relationship, the contractual
6 relationship, with the EPC contractor and the equipment
7 person, so there's a barrier between the two, if that
8 makes sense.
9 Q It's my understanding that your EPC
10 contract, it's a joint venture, as you describe it, with
11 you've got a construction firm and an engineering firm
12 and that contract was executed, I guess, in April of '09.
13 Did you go out and seek these firms independently or did
14 they offer their services jointly and you knew that or it
15 was available in that manner?
16 A They offered their services jointly. When
17 we did our RFQ for that they came jointly.
18 Q And I i m guessing with respect to your
19 experience in project oversight that Idaho Power doesn't,
20 has never built a combined cycle combustion turbine;
21 correct?
22 A That is correct. We do have -- here's an
23 interesting point is that, of course, we do have a lot of
24 experience with gas, but as we went around visiting.25 plants, the interesting thing that we learned in talking
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546 PORTER (X)
Idaho Power Company
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1 to the operators was the difficult thing to maintain and
2 operate with this plant is the gas side of things. You
3 know, if you've got the gas side of things down, they
4 said that the steam turbine is robust technology and so,
5 therefore, is not as complex to maintain as the gas side
6 is and we have an excellent staff, very experienced in
7 gas operations and we do have some steam experience as
8 well in the Company. As you know, we're j oint partners
9 wi th other utili ties, coal plants that have steam cycles
10 and so steam is not foreign to us.
11 Q But it's my understanding in your
12 describing the single cycle plants that those are
13 relatively simple plants compared to what you're bringing
14 on-line with Langley and the difficulty appears as an
15 order of magnitude that you'll have with this --
16 A Yes.
17 Q -- and it's just not more parts and a
18 longer time to put together.
19 A It is an order of magnitude because now
20 you've got two cycles. You i ve got a gas cycle and a
21 steam cycle and all the systems associated with that.
22 Q But the problem that you had in Bennett
23 with a piece of equipment not being installed, that was
24 an oversight, but that oversight could occur even with a
25 Company proj ect, couldn't it?
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547 PORTER (X)
Idaho Power Company
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1 A It could happen, but if we are focused, I
2 believe that our Company is more focused, has more reason
3 to be focused on long-term maintenance and operation of
4 that equipment and, therefore, would make sure that we
5 had the right quality assurance programs in place to
6 minimize the possibility of something like that.
7 Q The EPC team that you put together, how
8 many proj ects have they developed of this sort?
9 A I don't have the exact number, but a
10 substantial number of proj ects.
11 Q Okay; so you believe that they will
12 complement your lack of experience?
13 A Yes. As a matter of fact, I can tell you
14 that -- and I guess I'd argue the lack of experience. We
15 do have experience in th~ area, but as far as operating a
16 complete combined cycle, you i re correct, but we do
17 complement ourselves very well and we have had meetings
18 down in Kansas City and other places where we've gone
19 through and determined the redundancy. We've selected
20 equipment that we would allow.I mean, one of the great
21 things about doing this is now we select equipment that
22 we're already used to doing.
23 We're going to put in relays that are like
24 all the rest of our relays so we don i t have to retool..25 We don't have to learn how to do a specific relay. We
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[phone]
548 PORTER (X)
Idaho Power Company
.
.
.
1 can make sure that everything is done and tested in a way
2 that meets NERC criteria. For instance, with the relays,
3 they are going to buy the relays and with our expertise,
4 we i re going to go ahead and install them and test them
5 oursel ves because they would have to go out and hire
6 that, so by doing so, we're actually saving money. One
7 of the great things they're able to do for us is help us
8 wi th the site and the overall pricing of the bid, but we
9 were also able to reduce the price of the contract by $20
10 million of the Siemens work, because when we originally
11 bid it, we bid it as a power island and they looked at it
12 and said, you know, we can buy the exact same equipment
13 and we split it up and we can save you $20 million and
14 that's exactly what we did, so it was wonderful working
15 together with an EPC contractor, using their experience
16 with the equipment and plants and our experience of what
17 we want to have as far as the grid and interface with the
18 Idaho Power system, it's a perfect match. I think that's
19 the way you want to build projects.
20 Q There was a question that I had yesterday
21 regarding the transmission component of the Company's
22 application for recovery and whether the two lines that
23 are part of this include some Company betterment and they
24 said you're the better person to ask that.
25 A Okay, let me explain and please, if I get
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[phone]
549 PORTER (X)
Idaho Power Company
.
.
.
1 into the weeds, pull me out. I'm an engineer and it's
2 easy to go there, but let me give some background to the
3 transmission question and these two upgrades is the RFP,
4 the criteria for transmission in the request for proposal
5 for the resource said that for the loss of one unit or
6 one line or one element in the grid that you wouldn't
7 lose any load and you wouldn't have to back down any of
8 your other resources because of that outage, so
9 basically, you can suffer the loss of an element and
10 everything stays on, which is a good criteria, so the
11 base transmission amount we put in the contract, the 22
12 million and a little bit of change, included what it took
13 to meet that criteria, the bear minimum, and what that
14 was was a single tap over to the Ontario-Caldwell 230 kV
15 line and then a single line built down towards Caldwell
16 to Wagner Junction, so it was basically two taps, so
17 that's the basis for the base transmission costs.
18 Well, in the study process, the
19 transmission group strongly recommended that we do two
20 upgrades. The first one was that instead of just tapping
21 the Ontario-Caldwell line, they said, you know, it would
22 be much better if you looped it in or built an in and
23 out; in other words, instead of simply building a line
24 over and just tapping into it, you actually took the
25 Ontario line and actually looped it in and out of the
CSB REPORTING
[phone]
550 PORTER (X)
Idaho Power Company
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.
.
1 plant, so there's now two connections to that line to the
2 plant versus just one, and so what the benefits that
3 brought were that for certain outages on the Boise Bench
4 Brownlee system, it would reduce overloads and would
5 eliminate the need for what we call a remedial action
6 scheme, which in other words, if those outages happened,
7 then they would have to open up that 230 kV tap to avoid
8 overloads and so they liked that, they strongly
9 recommended it for that reason.
10 And then, also, I think everyone is very
11 well aware of the issues surrounding permitting
12 transmission these days. It's complex and it takes time
13 and there's always things that pop up and there's a
14 possibility of not being able to complete that 138 kV
15 line down to Caldwell area, 18 miles, in time for the
16 project to be on-line and so having that loop into the
17 plant from the 230 system gives you a much more, a much
18 better connection to the grid if for some reason that 138
19 was late, and then the last one was that the
20 Ontario-Caldwell line, the 230 line, and the 138 line
21 coming out of Caldwell that goes to Wagner tap are on the
22 same poles for two miles out of the Caldwell substation
23 and so if something were to happen where you lost one of
24 those poles, then you'd lose both lines and the plant
25 would turn off and so indeed, those are situations where
CSB REPORTING
[phone]
551 PORTER (X)
Idaho Power Company
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.
1 you're losing two elements, but transmission looked at it
2 and said, you know, we strongly recommend you take that
3 extra million-and-a-half dollars and loop that in, so
4 that would be to the benefit of the project and so we
5 fel t that's a prudent decision to make. It increases the
6 reliabili ty of the proj ect. Yes, it should be added to
7 the commitment estimate, but that was a decision that we
8 left up to Company, what do you want to do. The other
9 one is --
10 Q When you say I mean, it wasn't part of
11 the commitment estimate?
12 A No, it was added. It is in the commitment
13 estimate. It's called transmission upgrades. It's about
14 three -- the cost to build the loop in and out of the
15 plant from the 230, the Ontario-Caldwell 230, was about
16 one-and-a-half million dollars, and then the other one
17 was 1.8 million, approximately, and what that was is that
18 18-mile. line that is going to be built from the plant
19 down to the Caldwell area to the Wagner tap. The
20 transmission group strongly recommended for the future
21 benefit of our customers is that we build that at 230 kV
22 construction. They saw that eventually we're going to
23 need to convert that to 230 kV and it would not be
24 prudent to build that 138 now and then come back a few
25 years later and rip it out, repermi tit and rebuild it at
CSB REPORTING
[phone]
552 PORTER (X)
Idaho Power Company
.
.
.
1 230 kV. That would not be a prudent decision to make, so
2 they strongly recommended that we construct that line at
3 230 kV, operate it at 138 for now and so that cost us
4 1.8 million. With that 1.8 million and the 1.5 million
5 from the loop, that constituted the 3.3 million, roughly,
6 in transmission upgrades that were in the commitment
7 estimate.
8 Q Thanks. With respect to the short-listed
9 'bidders, the Company's decision to defer on-line
10 commercial operation for six months, that decision
11 occurred within this process that they were submitting
12 and you said that -- I think the Company said they gave
13 the short-listed bidders the option or asked them whether
14 it would affect their commitment estimate and their
15 response was that it wouldn't; is that correct?
16 A I believe that's correct. Mr. Bokenkamp
17 would be the proper witness to testify on that, but I do
18 believe that's correct.
19 Q Okay. If it had been awarded to a PPA or
20 a TA, what leeway would the Company have given them with
21 respect to a $1 million incentive payment for bringing it
22 back on-line in June, would the Company have paid that?
23 A It's possible. It would depend on the
24 benefits.I mean, I look at that decision to delay the
25 in-service date, it was done not, as I testified, to
CSB REPORTING
[phone]
553 PORTER (X)
Idaho Power Company
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.
.
1 benefi t the shareowner but to benefit the customer.
2 There was significant savings involved in two areas. One
3 is the difference between the Langley Gulch proposal and
4 the next bid, $ 95 million, and then also the ability to
5 secure traditional utility financing, as Ms. Smith
6 testified, provided significant benefits to the
7 customers, so when you look at the entirety of that
8 decision, it was a good decision, a prudent one that
9 benefits customers.
10 Q Wi th respect to start-up fuel costs,
11 didn't the draft tolling agreement clearly state that the
12 project owner rather than the Company would pay for
13 start-up fuel?
14 A I believe the draft tolling agreement said
15 that. I have not read the draft tolling agreement, but
16 from the testimony and whatnot, I gather that is true.
17 You'd have to talk to Mr. Bokenkamp to be sure of that.
18 Q And is the Company. in this case requesting
19 to recover those costs?
20 A Yes. I would also point out in the
21 testimony that it appears that that draft tolling
22 agreement probably would not have ended up as the final
23 tolling arrangement. Apparently, one of the bidders came
24 back and said no, that will be your responsible Idaho
25 Power, I'm paraphrasing, and my belief is that's where it
CSB REPORTING
[phone]
554 PORTER (X)
Idaho Power Company
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.
20
1 would have been. That's what we've done at Danskin and
2 Bennett Mountain. It's prudent utility practice to
3 capitalize those start-up fuel costs and so my belief is
4 those would have been paid by the Company and we would
5 have -- and they are included in our commitment
6 estimate.
7 Q How you would approach build and transfer
8 and your field trip to Utah, you didn't make the trip,
9 but isn't it possible that some of the problems that were
10 experienced there were a result of, I guess, a lack of
11 utili ty oversight in the building process?
12 A Possibly.
13 MR. WOODBURY: Mr. Chairman, if I can have
14 just have a second.
15 (Pause in proceedings.)
16 MR. WOODBURY: Staff has no further
17 questions. Thank you.
18 COMMISSIONER KEMPTON: Commissioner
19 Redford.
COMMISSIONER REDFORD: Mr. Chairman, can
21 we take a break?
22 COMMISSIONER KEMPTON: I think we should.
23 Thank you for reminding me of that, so let's take a
24 ten-minute break. We'll recess for 10 minutes..25 (Recess. )
CSB REPORTING
[phone]
555 PORTER (X)
Idaho Power Company
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.
.
1 COMMISSIONER KEMPTON: Okay, if we could
2 come back to order again, please. There are a couple of
3 announcements that I need to make very quickly. As soon
4 as Mr. Porter is finished, Ms. Ackerman will be allowed
5 to place the witness on the stand, the purpose being
6 transportation arrangements that are necessary for the
7 wi tness to catch a plane. We have a Mr. Robert Cahn that
8 will be on the line and is on the line now. Mr. Cahn,
9 are you on the line?
10 MR. CAHN: Yes, I am, Mr. Chairman. Thank
11 you for accommodating me.
12 COMMISSIONER KEMPTON: Okay; so everybody
13 here at the hearing knows that you i re on. The only thing
14 I would request is make sure that you have no sound
15 devices on in the background.
16 MR. CAHN: Well, I'm going to have my mute
17 on, so thank you, sir.
18 COMMISSIONER KEMPTON: All right, and
19 Ms. Ackerman, if you would just very briefly introduce
20 him, so that everybody knows where we are.
21 MS. ACKERMAN: Mr. -- Dr. Cahn, actually,
22 is the executive director of the Northwest &
23 Intermountain Power Producers Coalition, so he is my
24 client and I would just advise people he has not signed a
25 protecti ve order, has seen none of the confidential
CSB REPORTING
[phone]
556 PORTER (X)
Idaho Power Company
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.
.
1 material, so to the extent we are dipping into that,
2 we'll need to ask him to leave, but I don't think that
3 there will be any of that for the rest of this morning
4 anyway.
5 COMMISSIONER KEMPTON: Okay, thank you,
6 Ms. Ackerman. We've had the corrected Exhibit 10 that
7 Idaho Power has handed out to everyone and it does have
8 Corrected Exhibit No. 10 in the bottom right-hand corner
9 that replaces the previous Exhibit 10. Also, Idaho Power
10 has the information that Commissioner Redford requested
11 and it's over there in the boxes on the table for Mr.
12 Redford's scrutiny at any time during the hearing that he
13 would like to do that.
14 MR. KLINE: One caveat I need to make sure
15 that we mention is that, of course, portions of that
16 material were confidential. This was bidding materials
17 that a particular bidder presented and so they want that
18 to be confidential. There's two sets over there, one
19 wi th yellow and one with without and if you haven't
20 signed the protective agreement, then don i t take the one
21 with yellow, but they're all available and, of course,
22 the parties that have signed the protective agreement
23 have had access to all of that information.
24 COMMISSIONER KEMPTON: Okay, is there
25 anything else to come before the Commission before we
CSB REPORTING
[phone]
557 PORTER (X)
Idaho Power Company
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.
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1 complete the questioning with Mr. Porter? There being
2 none --
3 COMMISSIONER REDFORD: I have one item. I
4 would like to have the documents that Mr. Kline brought
5 to us today marked as an exhibit and spread on the
6 record, so they could be Commission Exhibit 1, I guess,
7 or something.
8 COMMISSIONER KEMPTON: Exhibit 101, Scott,
9 is that where we would be on that?
10 MR. WOODBURY: This is for what?
11 COMMISSIONER KEMPTON: For the information
12 that was brought over by Idaho Power for Commissioner
13 Redford at his request. He wishes to have it marked as
14 an exhibit and I see on the list that it would be 101.
15 Well, that's a Staff list, we can't do that.
16 MR. WOODBURY: Staff could enter it into
17 their exhibits.
18 COMMISSIONER REDFORD: Well, for want of
19 another number, we could say it's Exhibit 501 or
20 something like that.
21 COMMISSIONER SMITH: Those numbers are all
22 assigned.
23
24
25
COMMISSIONER KEMPTON: They're all taken.
COMMISSIONER REDFORD: Okay, 1001.
COMMISSIONER KEMPTON: That one is not.
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558 PORTER (X)
Idaho Power Company
.
.
1 COMMISSIONER REDFORD: Okay.
2 MR. WOODBURY: The next number in Staff's
3 is 116.
4 COMMISSIONER KEMPTON: Yes, 116, is that
5 what you want to use? All right, we i II use it as Staff
6 Exhibit 116 at Commissioner Redford's request.
7 (Staff Exhibit No. 116 was marked for
8 identification. )
9 COMMISSIONER KEMPTON: Back to the
10 testimony with Mr. Porter. Commissioner Redford.
11 COMMISSIONER REDFORD: Thank you,
12 Mr. Chairman.
13
14 EXAMINATION
15
16 BY COMMISSIONER REDFORD:
17 Q Mr. Porter, we i ve run into a situation, at
18 least I have, of asking questions of the wrong witness
19 and so I would suggest that if I ask you a question that
20 should have been asked of Mr. Bokenkamp or to any other
21 wi tness that you let me know. That way we will avoid a
22 lot of time. What was the date that the RFP went out for
23 the EPC or for the work, do you recall -- not the EPC, I
24 mean for the contractors in the scheme where you were.25 selected.
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559 PORTER (X)
Idaho Power Company
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.
1 A Okay, for the Company's request for
Yes.
I believe that went out on April 1st,
5 2008, to the best of my recollection.
2 proposal?
7 the successful bidder?
And when were you notified that you were
3 Q
It was in 2009. That's a good question.
9 It was after the evaluation process was completed.
14
15
4 A
You don't have to be specific, but --
Just maybe end of February, some time like
February of 2009?
Uh-huh.
16 with the EPC contractor?
And then when did you start negotiating
17
6 Q
The actual negotiations started back when
18 we selected the EPC contractor back in early summer or
8 A
19 late spring of 2008.
20
10 Q
11 A
12 that, February.
13 Q
A
Q
A
Q
21 MOU signed?
22 A
Correct me if I'm wrong, but when was the
October, October of 2008 and I couch that
23 it could have been late September 2008 as well.
24
25
Q
the RFP?
Was it after the bidding was concluded on
CSB REPORTING
[phone]
560 PORTER (X)
Idaho Power Company
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.
1 A No, our bid was -- that MOU was signed
2 before we submitted our bid to the RFP process.
3 Q Did the MOU have some language that
4 contained a statement that you would only hire them in
5 the event you were the low bidder or the successful
6 bidder?
7 A Yes, to that extent, that clearly we would
8 have to be selected to proceed with the proj ect.
9 Q So you started negotiating the EPC
10 contract before the bids were evaluated?
11 A Yes, we would have to in order to maintain
12 the schedule.
13 Q You've mentioned Power Engineers or
14 someone has mentioned Power Engineers as assisting you in
15 something. I don't know what it was. What was the scope
16 of work for Power Engineers?
17 A Power Engineers was our owner i s engineer,
18 so they helped us with all the facets relating to the
19 preparation of a proposal to the Company's RFP, so it
20 would include everything from helping us write the
21 request for proposal for the turbines and evaluating
22 them, helping us evaluate the EPC contractors, helping us
23 with any technical information about combined cycle
24 plants. They were basically our engineers working for us
25 for whatever technical issues that might come up.
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561 PORTER (X)
Idaho Power Company
.
12
1 Q Okay. Did they prepare for you any design
2 work?
3 A They helped us prepare the specifications.
4 As a matter of fact, they took the lead in preparing the
5 specifications for the turbines.
6 Q Did you negotiate with Power Engineers?
7 A Yes, yes, we did. We set up an agreement
8 with them.
9 Q And so you as a team member bidding for
10 the work had prior knowledge which was supplied to you by
11 Power Engineers?
A We were able to draw on their experience
.13 and knowledge, yes.
14 Q How about after the RFP came out, did they
15 still do any work?
16 A After the RFP came out, you mean after we
1 7 submi t ted the RFP or our bid or --
18 Q Well, at the time that the RFP was handed
19 out to the various bidders.
20 A I would say that's when -- yes, they
21 continued to work for us there, absolutely.
22 Q Did any other bidder have an opportunity
23 to discuss anything with Power Engineers?
24.25
A They certainly could have had they wanted
to. I'm not aware of whether they did or not.
.
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562 PORTER (X)
Idaho Power Company
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.
.
1 Q Do you know whether these other bidders
2 knew that they could contact Power Engineers?
3 A Power Engineers is an engineering firm out
4 there, an engineering and construction firm, and they're
5 well known and there's many of those types of firms out
6 there and I think the only way they could have known
7 is -- I mean, they would have called up Power Engineers
8 and talked to them about it. Nothing precluded them from
9 doing so.
10 Q Did Power Engineers prepare for you a bid
11 schedule?
12 A They helped us prepare the schedule,
13 absolutely.
14 Q Which schedule?
15 A The proj ect schedule which would have
16 helped as far as -- you know, when you say "bid," I
1 7 assume we're talking turbine bids, you know, that we did.
18 They helped us do that.
19 Q They didn't help you on the other elements
20 of the other bidders' bids?
21 A Well, remember, this is just for the
22 Benchmark, I mean, just for the Langley Gulch proj ect, so
23 as far as other bids, there really were no other
24 competitive bids other than for the turbines. There was
25 other work done, other consulting work with the
CSB REPORTING
[phone]
563 PORTER (X)
Idaho Power Company
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.
1 permi tting and those types of things and Power would have
2 had a role in helping us maybe select good consultants to
3 talk to or other experts that we could draw inside
4 from.
5 Q At the pre-bid meeting did you notify the
6 other or did anyone notify the other prospective bidders
7 about Power Engineers' involvement?
8 A Not that I'm aware of. Karl Bokenkamp
9 would be the witness.
10 Q Okay, thank you. Were you in attendance
11 at the pre-bid meeting?
12 A No.
13 Q Was anybody from Benchmark at the
14 pre-bidding?
15 A No.
16 Q Why was that?
17 A Probably because -- I'd have to ask
18 Mr. Bokenkamp about that, get his perspective on it, but
19 possibly I could say that it was because maybe some
20 questions might come up that other people might not be
21 comfortable sharing if we were there. I don i t know. We
22 didn't go.
23 Q After the pre-bid meeting did you stop
24 your general employment and then go to work full time for
25 Benchmark?
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564 PORTER (X)
Idaho Power Company
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.
.
1 A I continued my full employment with all
2 the responsibilities that I had as general manager.
3 Q General manager of --
4 A Of power production which would include a
5 lot of different areas.
6 Q You also mentioned that we, and I don't
7 know who "we" is, had meetings with the Board of
8 Directors. Were you in attendance at those meetings?
9 A The meeting I attended was -- I mean, it
10 was after the selection where I was called in to the
11 Board to talk about the project. They wanted to know
12 about Langley Gulch.
13 Q Are you familiar with the term "Chinese
14 wall "?
15 A Yes, I am.
16 Q And did Idaho Power employ a Chinese wall
17 on Benchmark?
18 A Absolutely. We were very diligent is how
19 I would describe it in making sure there was no improper
20 communication between the evaluation team and the
21 Benchmark team and I can assure you that that process was
22 done with integrity and I'm unaware of any improper
23 communications in that process. We're very well aware of
24 the standard of conduct of FERC. We know how serious it
25 is and how important it is that the process be done with
CSB REPORTING
[phone]
565 PORTER (X)
Idaho Power Company
1 integri ty and properly..2 Q Did any of the other bidders build what I
3 like to call a design build?
4 A I don't know. I'm not familiar with the
Wi th regard to your EPC contract, what
7 type of a contract is it? Is ita fixed price
5 other bidders.
6 Q
Yes.
And it's got -- elements of it provide for
11 bonuses for early completion?
8 contract?
9 A
Well, that's what we are negotiating with
.13 them as we speak and we've reached an understanding and
10 Q
14 agreement of that incentive to reach early completion,
16 Q
12 A
15 but we haven't signed the change order yet.
20
17 A
So they you bid $427 million?
18 Q
Yeah.
And there was no design completed at that
No design completed at which time, when we
21 submitted our bid?
22
23
19 time, was there?
A
Q
A
Yes.
Well, there clearly had been meetings that
24 we had held with the EPC contractor to decide the scope.25 of the proj ect, the layout, all the redundancies, the
CSB REPORTING
[phone]
566 PORTER (X)
Idaho Power Company
.1 preliminary work associated with what we wanted and the
2 single lines, the interfaces, all those kinds of things
3 had been worked and we relied on the expertise and
4 experience of the EPC contractor for the bid.
5 Q There wasn't a competi ti ve bid for the EPC
6 contractor?
7 A No, no, there was not.
8 Q It was a sole source contract?
9 A There was a process. We did our request
10 for qualification process and we felt that -- anyway, so
11 what we did is we sent out requests for qualification.
12 We got seven back or so and then we ended up selecting
13 three of those as a short list and then we interviewed.14 them and anyway, we interviewed those three and selected
15 TIC/Kiewit and the reason we did that is because we
16 felt -- I mean, we could have gone out for bid, but we
17 felt like it would be more valuable in our bid to team up
18 with an EPC contractor and use the fact that we're
19 competing with all other proposers of proj ects to bring
20 in that element of competition with the EPC contractor,
21 so we felt like we had brought in the competition with
22 them and we felt there was more value in working with
23 them to try to get the proj ect right than doing the bids
24 and then having a shorter period of time. We brought.25 them in, they helped us with the siting and with the
CSB REPORTING
[phone]
567 PORTER (X)
Idaho Power Company
.
10
11
.
.
1 evaluation of the turbine equipment bids, those kinds of
2 things and it was a very good partnership.
3 Q Did Kiewit also have a dialogue with the
4 evaluation team --
5 A I'm unaware.
6 Q -- for Idaho Power?
7 Evaluation team, you're talking about Mr.A
8 Bokenkamp' steam?
9 Q Yes.
A Not that I'm aware of.
Q Did the EPC contractor develop a schedule,
12 a construction schedule?
13 A Yes.
14 Q And what kind of schedule is that? Are
15 you familiar with the term "critical path method" or what
16 kind of a schedule?
17 Yes, it definitely had -- I mean, it was aA
18 general project schedule, but it had identified the
19 critical path items in it.
20 Q Was it just a bar chart, though?
21 Yeah, your classical scheduling toolA
22 product, no doubt.
23 Well, that generally isn't a CPM schedule.Q
24 What did you call it?A
25 Q Critical path method schedule.
CSB REPORTING
[phone]
568 PORTER (X)
Idaho Power Company
.1 Maybe I'm misunderstanding what you meanA
2 by that. I assumed that when you said critical path that
3 you knew what your critical path item was, which in this
4 case was the steam turbine, and that dictated a lot of
5 the aspects of the schedule, so maybe I'm
6 misunderstanding your question.
7 Do you know how a CPM schedule works?Q
8 I assume it looks at critical path itemsA
9 and schedules them such that they will be completed on
10 time.
.
.
11 Q Are you aware that on a critical path
12 method that one critical -- a critical path method that
13 before one task is completed or, excuse me, when a task
14 is completed, the next item of the critical path comes on
15 for completion?
16 This seems logical.A
17 Like, for instance, site preparation, thatQ
18 has to be completed before you can pour footings or
19 something of that nature?
20 A Yes.
21 COMMISSIONER REDFORD: Do we have that
22 schedule?
23 MR. KLINE: I don't think you do.
24 THE WITNESS: It would have been in the
25 documentation room that we had back at the Company.
CSB REPORTING
[phone]
569 PORTER (X)
Idaho Power Company
.1 MR. KLINE: I don't believe that the
2 contracts between the various entities are included. Do
3 you want them?
4 Q BY COMMISSIONER REDFORD: Well, generally,
5 it isn't. It's generally a stand-alone document because
6 the critical path is always being adj usted. I don't
7 really need to have it, but I just wanted to know what
8 kind of scheduling system you used.
9 You know, if I had the schedule today, IA
10 think you would find that it would meet your
11 expectations, that it does incorporate the elements of
12 cri tical path scheduling because that's how you schedule.
13.
.
I mean, those are key things and so I would expect that
14 you would find that that's how it was done.
15 Did your EPC contractor help develop thatQ
16 schedule?
17 Yes.A
18 Did you request of the other bidders aQ
19 similar type of schedule?
20 You mean the EPC contractor?A
21 Q No,from the RFP.
A That would be a question for
Mr.Bokenkamp.I'm not aware.
Q What design has been completed to date?
A Design work on the turbines,of course,is
22
23
24
25
CSB REPORTING
[phone]
570 PORTER (X)
Idaho Power Company
.
10
11
12.
.
1 well underway. Some of those aspects may be complete.
2 The EPC contractor on their own at their own expense and
3 risk has been doing the design for the heat recovery
4 steam generator, condenser and those other maj or pieces
5 of equipment that I mentioned, so design is well
6 underway.
7 Would that be preliminary design?Q
8 No, this is final design.A
9 Detailed design?Q
A For those pieces of equipment, yes.
Q Just for the pieces of equipment?
A Yes.
13 Q Do you have a schedule for assembly or
14 construction, overall construction, of the plant?
15 A Yes.
16 That's done?Q
17 Yes, that would be that schedule we wereA
18 talking about earlier.
19 Okay, but the design for the overall plantQ
20 has not been completed?
21 Detailed design has not been completedA
22 yet.
23 Okay; so you stated it was a fixed priceQ
24 contract and did you develop line items for what was
25 considered in the EPC contractor's contract?
CSB REPORTING
[phone]
571 PORTER (X)
Idaho Power Company
.1 A We worked together with -- as I recall,
2 the EPC contractor brought the line items to the table
3 for review, but then we went through everyone of them
4 with them. I do want to add one more, when you mentioned
5 before and I answered is ita fixed price contract, it
6 is, but there is an element of it that does have some
7 risk to it and that is the maj or equipment piece of it.
8 We've gone to the target pricing on that as part of the
9 agreement to delay, as explained in my testimony. For
10 the major equipment, we've gone to a target pricing where
.
.
11 there's a target and there's a band width around that and
12 we share the costs, the risks and benefits around that
13 target, so I just wanted to make sure that was clear.
14 Okay, in the event that there are changeQ
15 strike that. At the conclusion of the contractorders
16 if the cost exceeds $427 million, does the contractor eat
17 that?
18 It depends on -- I guess that would dependA
19 on what the changes were and who was responsible for
20 them.
21 Well, let's just assume that pricesQ
22 escalated and the price went over $427 million. Would
23 your EPC contractor have to bear the responsibility for
24 the overage?
25 They would argue that they wouldn't beA
CSB REPORTING
[phone]
572 PORTER (X)
Idaho Power Company
1 responsible, that it would be our responsibility for.2 that.
3 Q Why do you say that?
4 A Well, as we planned out the proj ect and
5 put our commitment estimate together, we put comri tment
6 estimate contingencies in that comri tment estimate.
7 Q What if you went over your contingency?
8 A Well, that's a risk we'd have to take.
9 That's one of the risks with a project that can happen;
10 however, we feel like we fixed the risk for the most part
11 in this project. If you look at the overall cost, the
12 maj ori ty of it is fixed, so we've done our best to manage
13 that risk and with our comri tment contingencies, we.14 believe we have the right price to build that plant.
15 Q But the question I have, if you go over
16 the bid price and your contingency and there have been no
17 changes other than an escalation of prices, the EPC
18 contractor has assumed those risks?
19 A Well, for portions of the contract they
20 have, absolutely. I mean, the EPC contract is a $221
21 million contract, but there's a portion of that of the
22 maj or equipment that we plan to go out to bid for here on
23 September 1st. We would like to go out to bid for on
24 September 1st for those four items, the heat recovery.25 steam generator, the cooling tower, condenser and
CSB REPORTING
[phone]
573 PORTER (X)
Idaho Power Company
1 generator step-up unit, transformer. With that target.2 pricing, there's some risk one way or the other of where
3 the prices could turn out, but that's why we've put in
4 commi tment estimate contingencies into our
5 Q How much are the commitment estimate
6 contingencies?
7 A That $ 12 million for contingencies,
8 approximately.
9 Q So you've made a representation to the EPC
10 contractor that there's $12 million for use in the event
11 prices escalate?
12 A I'm not sure if they know that or not. I
13 don't know if they've seen the commitment estimate or.14 not. They know what their contract with us is, but we
15 will hold them accountable for that contract.
16 Q Thank you. Would you supply the turbine
17 and the other equipment as owner-supplied equipment?
18 A The turbine is categorized that way. When
19 Siemens delivers the turbine to the rail siting, the
20 ownership changes at that point and becomes our turbine
21 and then the EPC contractor, of course, takes
22 responsibili ty for it, but at that point it becomes our
23 turbine.
24 Q Does the EPC contractor install the.25 turbine?
CSB REPORTING
[phone]
574 PORTER (X)
Idaho Power Company
.1 Yes. For the other maj or equipment theA
2 EPC contractor is the owner.
3 About how long did it take from the timeQ
4 you submitted your bid under the RFP did it take Idaho
5 Power to evaluate and select you, Benchmark?
6 Let me step through this. Let's see, theA
7 bids were due October 17th.
8 Q Of 2008?
9 Of 2008, and then there was a short-listA
10 process and we came back -- we made the short list and so
11 we came back and did a presentation December sometime it
.
.
12 was.
13 Q Of 2008?
14 Of 2008, and then at that point we wereA
15 allowed to refresh our bids and then the evaluation team
16 did their work and Mr. Bokenkamp will know exactly when
17 the decision was made, but I want to say February.
18 To the best of your knowledge, do you knowQ
19 whether any other bidder on the RFP was told that with
20 regard to the turbine, et cetera, that would be
21 owner-supplied?
22 Say that one more time.A
23 Do you know whether any bidder was offeredQ
24 owner-supplied equipment?
25 If any bidder was offered owner-suppliedA
CSB REPORTING
[phone]
575 PORTER (X)
Idaho Power Company
1 equipment..2 Q Well, you stated that Idaho Power, the
3 owner supplies the turbine, et cetera, did any other
4 bidder know that, to the best of your knowledge, that
5 Idaho Power under their contract would be provided with
6 owner-supplied equipment?
7 A I'm unaware of what they were told.
8 Q You selected a site. During the pre-bid
9 meeting was it represented to the bidders that a site had
10 been selected or were they required to select a site?
11 A The RFP -- well, as I understand it
12 well, we didn't have a site then, put it that way. Our
13 site wasn't selected until, oh, maybe August of 2008 when.14 we finally made a decision on the site, so I'm not sure
15 what -- like I said before, I wasn't in the meeting, but
16 they couldn't have communicated it anyway because we
17 didn't have a site at that time.
18 Q Whose responsibility was it to select a
19 site?
20 A That was the -- the RFP required the
21 bidders to find a site.
22 Q Okay; so presumably, they had that
23 obligation?
24 A Yes..25 Q Okay, and you've signed final contracts
CSB REPORTING
[phone]
576 PORTER (X)
Idaho Power Company
1 with Siemens?.2 A Yes.
3 Q Have you been a construction manager or a
4 contracting officer for the Company on any proj ects,
5 previous proj ects?
6 A The experience I have throughout my career
7 with proj ects has been with transmission for the most
8 part and transmission construction proj ects and then when
9 I came in on my current assignment, I was involved in the
10 construction of the Danskin, had responsibility for the
11 Danskin project.
12 Q You were the proj ect owner's.13 representati ve?
14 A No, I was the general manager overseeing
15 it. I draw on -- we have experienced engineers who have
16 been involved in construction management and construction
17 for many, many years in our department and I, of course,
18 rely on their expertise for much of the management and
19 oversight of those proj ects.
20 Q So you'll have an on-site employee
21 there?
22 A For this proj ect?
23 Q Yes.
24 A Oh, yes. We'll have several people on.25 site.
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[phone]
577 PORTER (X)
Idaho Power Company
1 Q And one of them would be a contracting.2 officer?
3 A The proj ect manager would be on site.
4 Q Okay. Do you know the contracts that
5 will there be a contract between the Company and
6 Benchmark?
7 A Not that I'm aware of. The commitment
8 estimate is the cost estimate that we've submitted to
9 build it, but I don't believe there would be a formal
10 contract between my group and Idaho Power and
11 Mr. Bokenkamp's group. There's no formal contract within
12 the Company if that's the question.
13 Q But there would have been in the event.14 another entity had been selected?
15 A Yes.
16 Q Okay. You've also talked about
17 developers. In what context did you use the term
18 "developers"?
19 A Someone who develops generation
20 projects.
21 Q In your case who is the developer?
22 A The developer in this case would be a
23 third party that would develop a proposal for generation
24 projects..25 Q And so that third party would be, have
CSB REPORTING
(20B) 890-5198
578 PORTER (X)
Idaho Power Company
1 oversight on the proj ect?.2 A If it's a third party -- excuse me, if
3 it's a build and transfer, yeah. Let me answer your
4 question. The answer is yes, that party would have
5 oversight over the proj ect.
6 Q Does that developer apply in the present
7 si tuation where Benchmark has been awarded the contract
8 or you've been selected?
9 A Say that one more time.
10 Q Is that the case, is a developer to be
11 employed under the present award of contract for a
12 resource where Benchmark got the proj ect?
13 A No, a developer will not be employed..14 Q That's only for third parties, then?
15 A Yes. We'll manage the property
16 ourselves.
17 Q When you -- I presume that you did the
18 procurement for the turbine and there was a clause in
19 that that said you can't transfer the turbine without
20 consent of Siemens and that consent will not be
21 unreasonably withheld.
22 A (The witness nodded his head up and down.)
23 Q To the best of your
24 MR. KLINE: Excuse me, Vern, you have to.25 say so Connie can hear you say yes.
CSB REPORTING
[phone]
579 PORTER (X)
Idaho Power Company
1 THE WITNESS: Yes..2 Q BY COMMISSIONER REDFORD: If you know for
3 the other bidders where you state there has to be a
4 developer, in their bids was there a line item for a
5 developer's fee?
6 A I'm unaware.
7 Q What are the incentives that have been
8 buil t in for the EPC contractor? Are there any
9 incentives? You've got a bonus and you've got a payment
10 for early completion and you've got a contingency;
11 right?
12 A Right.
13 Q Any other incentives?.14 A No.
15 Q I seem to have read somewhere that there
16 were other incentives, like a million dollars or more in
17 the event that proj ect is brought on schedule.
18 A Oh, I thought you mentioned that one.
19 When you listed them, I thought you referred to that one.
20 You're referring to the incentive to accelerate the
21 schedule back so that we can have the plant on-line for
22 the summer in June of 2012, yes, there is an incentive
23 there.
24 Q Are there any penal ties or damages in the.25 event that the project doesn't come on-line on
CSB REPORTING
[phone]
580 PORTER (X)
Idaho Power Company
1 schedule?.2 A Yes, there are liquidated damages
3 pertaining to both the turbine and the EPC contract that
4 are in the contracts.
5 Q How much are those penalties?
6 A I don't have that in front of me, but they
7 would be standard liquidated damage provisions. It would
8 be both on the output of the plant as well as delivery.
9 Q Well, generally , disincentives, we all
10 know what that means, but generally there's a dollar
11 amount.
12 A Yes, there are dollar amounts attached to
13 that. For instance, on the plant capacity, for every.14 megawatt or kilowatt under what they promised, there's a
15 penal ty associated with that.
16 Q And is there also a penalty for late
1 7 completion?
18 A Yes.
19 Q Turning your attention to page 16 of your
20 rebuttal testimony, you talk about, starting on line 10,
21 specifically, the Company and the EPC contractor have
22 agreed that if the plant is substantially constructed and
23 in-service by July 1, the Company will pay contractor
24 $750,000 as an early completion incentive, and for each.25 day prior to July 1, 2012, that the plant is in-service,
CSB REPORTING
(20B) 890-5198
581 PORTER (X)
Idaho Power Company
.1 the Company will pay an additional incentive of $10,000
2 up to $150,000 and you agreed with the EPC contractor to
3 pay up to $100,000 to assist in securing timely delivery
4 of a critical path piece of equipment. Is that the total
5 amount of incentives?
6 A Yes.
7 Q How long are you given in the schedule to
8 have the detailed design completed?
9 Not having the schedule in front of me, IA
10 can't answer that question completely, but it is
.
.
11 scheduled, I know that much. It's clearly the -- some of
12 the detailed design is already underway for equipment
13 and, just guessing, I would expect that once we gave them
14 the full notice to proceed that they're going to start
15 immediately on full design, final design of the plant.
16 Q And have they given you a schedule?
17 A Yes, we have the schedule.
18 Q Okay. You don't have any idea of the
19 order of magnitude for the design part of the
20 agreement?
21 Meaning the cost or the schedule?A
22 Q The schedule.
23 Oh, you know, it's a big schedule and, asA
24 I recall, that once full notice to proceed is given,
25 commencement of final design starts, but I cannot
CSB REPORTING
[phone]
582 PORTER (X)
Idaho Power Company
.
.
.
1 remember exactly when it starts and finishes, you know,
2 at this point. I'd need to have the schedule in front of
3 me to see it, but I know it is scheduled in order to meet
4 the deadlines given them.
5 MR. KLINE: Commissioner Redford, we could
6 provide that if that's something you want.
7 COMMISSIONER REDFORD: Yes, it is.
8 Q BY COMMISSIONER REDFORD: But the detailed
9 design does not or construction and assembly does not
10 start until the engineering of the design is completed;
11 is that right?
12 A For the most part. There could be some
13 items that could be finished up. You know, it's
14 sequential. Of course, there is site preparation that
15 has to go on and then getting all your construction,
16 power to the site and communication and all those things
17 that are involved in preparing the site, then the gas
18 turbine arrives in Feburary of 2011. The steam turbine
19 arrives in July of 2011, so, of course, it has to be all
20 sequenced so that you have final design done for whatever
21 is being installed, so clearly, final design is done
22 before any component that requires it is completed, it
23 has to be.
24 Q Are you familiar with the term "fast track
25 proj ect"?
CSB REPORTING
[phone]
583 PORTER (X)
Idaho Power Company
.
.
.
1
2
A
Q
Yes.
And is your understanding the same as mine
3 that it's a contract where the work is progressing before
4 the design is complete?
5
6
7
8
9
A
Q
A
Q
A
Yeah, I'm aware of that.
Is this a fast track contract?
No, it is not.
Okay.
Maybe I haven't been clear in my answer to
10 you, but the final design will be done as required under
11 a normal sequence in the proj ect .
15
12
13
14
16 bid.
17
Q
A
Q
A
Q
Is there a preliminary design?
Yes.
Has that been completed?
Yes, that was done when we submitted our
So the only thing that's left right now to
18 be completed is the detailed design --
19
20
21
22
A
Q
A
Q
Yes.
-- or the construction design?
Yes.
Okay. Wi th regard to the EPC contractor
23 and the schedule slippage right now, are they holding
24 firm on their bid price?
25 A The only thing that changed with the bid
CSB REPORTING
[phone]
584 PORTER (X)
Idaho Power Company
.
.
.
1 price was the -- well, two things. One was going to the
2 target price and then the second one was that we would
3 assume the risk of labor escalation from March 1st
4 through September 1st and that was capped at two percent
5 of that which was $550,000.
6 Q Would you say that six months for the
7 detailed design would be about right?
8 A Certainly, a large part of it could be
9 done, no question about it.
10 Q Did you as a task in your bid suggest
11 various al ternati ves for financing the proj ect?
12 A We assumed traditional utility
13 financing.
14 Q Which is?
15 A Fifty percent equity, fifty percent
16 debt.
17 Q But you didn't ever make a determination
18 of whether the SO percent debt was possible?
19 A We made the assumption that it was
20 possible.
21 Q Okay. Does the EPC contract talk about a
22 hard cap and a soft cap?
23 A No.
24 Q So that type of -- there's nothing in your
25 agreement that provides for that?
CSB REPORTING
[phone]
585 PORTER (X)
Idaho Power Company
.
.
.
1 A No.
2 COMMISSIONER REDFORD: I guess that's all
3 the questions I have, Mr. Porter. Thank you very much.
4 THE WITNESS: Thank you.
5 COMMISSIONER KEMPTON: Thank you,
6 Commissioner Redford. Commissioner Smith.
7
8 EXAMINATION
9
10 BY COMMISSIONER SMITH:
11 Q I just want to be sure I understood one of
12 your answers to Commissioner Redford. What did you mean
13 when you used the term "owner' s engineer" as applied to
14 Power Engineers?
15 A It's a vernacular. When a company such as
16 Idaho Power would like to get engineering experience for
17 a resource would go out and hire an engineer and they
18 call it an owner's engineer. Basically, I'm hiring a
19 consul tant to come help me with this.
20 Q Okay, and when he asked you the question,
21 and I think you answered yes, that you had prior
22 knowledge from Power Engineers, I think implying that you
23 had some kind of special information or access that other
24 bidders didn't have, is that what you intended to
25 convey?
CSB REPORTING
[phone]
586 PORTER (X)
Idaho Power Company
.
.
1 A No, I mean, what I intended to convey was
2 simply we were working with -- Power Engineers was
3 working with us and certainly, any other bidder would
4 have access to any of these consultants out there to talk
5 about combined cycle proj ects, so there would have been
6 no advantage for us to -- no disadvantage to anybody by
7 us talking to Power Engineers, hiring them as an
8 engineering consultant for us.
9 Q All right.
10 A Am I clear on that?
11 Q I don't know who you meant by "us. II
12 A Okay, let me make clear on that. That was
13 the Benchmark proposal.
14 Q Okay.
15 A That was my group.
16 Q So Power Engineers was actually employed
17 by Idaho Power Company for engineering expertise and
18 there was a separate contract by the Benchmark group
19 proposal to also get their help?
20
21
22
23
24.25
A No, that's not correct.
Q Okay.
A I'm sorry.
Q i clearly didn't understand any of it.
A Good question. Okay, my group did the
Benchmark proposal.
CSB REPORTING
[phone]
587 PORTER (X)
Idaho Power Company
.
.
1 Q Yes.
2 A And we are the ones that went out and
3 contacted Power Engineers. The evaluation team did not,
4 as far as I know did not, contact any consultants other
5 than Mr. Stein and R. W. Beck. That was theirs. They
6 are completely separate proj ects. Does that make sense?
7 Q Yeah, that clears it up because it sounded
8 to me like this was Idaho Power's engineer and then you
9 went off and got a separate agreement with them to help
10 you out, but that i s not the way it happened.
11 A That is correct.
12 Q You went, the Benchmark proposal group
13 went, and got Power Engineers to give them engineering
14 help in designing your proposal and your proj ect?
15 A That's exactly right and I apologize for
16 that.
17 Q And what engineering assistance other
18 bidders may have procured we don't know, but they
19 probably could have or did on their own their own
20 consulting and engineering?
21
22
A True.
COMMISSIONER SMITH: All right, thank you.
23 That clears it up.
24.25
CSB REPORTING
[phone]
588 PORTER (X)
Idaho Power Company
.1 EXAMINATION
2
3 BY COMMISSIONER KEMPTON:
4 Q Mr. Porter, page 27, line 19 on your
5 rebuttal, this is rebuttal to Mr. Sterling's original
6 filing, direct filing. To paraphrase Mr. Sterling's
7 concern, there are some areas of risk that are higher
8 than others and uncertainty as distinct from other
9 options in the procurement process and in the contracting
10 process and on and on to get to the $427 million. He
11 broke that out into the factors that he did and without
12 being specific about those, from a general standpoint, do
.13 you disagree that there is room for examining soft caps
14
15
and hard caps in terms of the $427 million?
A Well, I do agree that cost discipline is
16 necessary, but I feel like the way we approached it with
17 a commitment estimate is the proper way to do it. I feel
18 that the way we developed our estimate, of course, was
19 through contracts, through estimates from outside
20 resources, from inside resources who have the expertise
21 to give us good estimates, and we used actual costs. We
22 used actual labors and manpower that we could calculate.
23 I mean, we know we need X many trucks. We know how much
24 trucks cost. We know we're going to have X amount of.25 engineers on the project. We know what their labor rates
CSB REPORTING
[phone]
589 PORTER (X)
Idaho Power Company
.
.
.
1 are, so we were able to take a lot of actual data, along
2 wi th good estimates from outside parties and inside
3 parties to create an estimate that we believe along with
4 prudent contingencies is the amount we think it is going
5 to cost to build the proj ect.
6 My concern on this part of my testimony
7 was that on the soft cap, reducing in his proposal, we
8 were reducing those estimates down to in most cases SO
9 percent. Some of them were completely thrown out, but I
10 looked at that and said I can't do that for SO percent.
11 For instance, the gas line, McMillan gave us an estimate
12 of what it would cost to build the gas line of $2.1
13 million, so that's what we put in as our estimate. Now,
14 he had, of course, a band width around it. He said
15 that's my estimate. That's my median number. It's going
16 to be plus or minus SO percent, but to go to the SO
17 percent level is in my opinion unrealistic and that was
18 confirmed in this case.
19 We just last week got the Northwest
20 Pipeline's bid to build that gas line for us and it came
21 in almost identical to McMillan's median number, the $2.1
22 million, and so it confirmed that that median price that
23 they had used in that estimate they gave us was a good
24 bid and so that's what my point was is that these are the
25 estimates we believe it's going to take to build this
CSB REPORTING
[phone]
590 PORTER (X)
Idaho Power Company
.
.
1 proj ect and to come up with a -- to deal with a soft cap
2 that's based on numbers that I can't build it for, I
3 don't think that's right, so that was my point.
4 Q There are a lot of estimates that have
5 been made in about the same time frame that you made
6 estimates on this contract proposal, you know, across the
."
7 whole spectrum of it in transportation and in other areas
8 where people are being pleasantly surprised, I suppose,
9 by reductions in material costs, et cetera that are
10 running in the 15 to 20, 21, 25 percent range on the
11 contract. Is there any reason to assume that that
12 wouldn't happen in this case? Not that I'm suggesting
13 that that's a hard and fast rule, Ilm not suggesting that
14 at all, but isn't there room for that sort of thing to be
15 happening as a result of the economy?
16 A Well, some of that already has happened.
17 When we refreshed our bid the first part of the year, the
18 EPC contractor lowered their price by 7 to $8 million and
19 we were able to capture that and add that into our
20 commitment estimate. We hope to take advantage of that
21 here on September 1st with going out to bid for this
22 major equipment, hoping to capture that, so the project
23 does we're planning on some of that, we're hoping for
24 some of that, of course, but in reality, you've got costs.25 out there that we've bid on now in 2008, basically and
CSB REPORTING
[phone]
591 PORTER (X)
Idaho Power Company
.
.
.
1 early 2009 that won't be constructed until 2010 to 2012
2 and, you know, there's quite a bit of risk. I mean, this
3 market has been very volatile and what will happen with
4 construction prices and materials and those kinds of
5 things in 2011 and '12 could be anything. I mean, it's
6 been very volatile.
7 Q And I think perhaps that's the point that
8 Mr. Sterling is trying to make, although he can certainly
9 speak for himself in his own personal testimony, but my
10 reading of this is that he's attempting to balance the
11 risk of the ratepayers and the obj ecti ves of the Company
12 in obtaining financing in separating some of the items
13 for an off-ramp for Commission review above the hard cap.
14 It's not saying that the money wouldn i t be available for
15 construction of the plant. The extra part in the soft
16 cap would be there for review, but it is suggesting that
17 there's enough uncertainty there that perhaps in the
18 ratemaking treatment that you wouldn't have to go all the
19 way to the commitment of $427 million before you examined
20 some things at the top of it where there might be
21 realistic flexibility and examination of prudency both.
22 A Well, my opinion is that whatever that
23 number is for that soft cap, it should be what we think
24 we can build the proj ect for with contingencies. That's
25 my opinion and so is there some flexibility, there's some
CSB REPORTING
[phone]
592 PORTER (X)
Idaho Power Company
.
.
.
1 things that could be explored there, clearly f but once
2 again, it should be, I think, is what you really think
3 you can build the plant for.
4 Q And if I were an engineer, Mr. Porter,
5 that's exactly what I would say. You had some experience
6 in transmission, so I don't know if I'm getting beyond
7 the area you would prefer to not testify in, but the
8 issue has come up concerning non-firm transmission and
9 the problems of moving that in --
10 A Yes.
11 Q -- and also in loop flow and I don't want
12 to actually get into loop flow, but I would just like a
13 general discussion of those two areas as far as the
14 problems they actually present in terms of Idaho Power
15 being able to meet its power supply requirements with or
16 wi thout added peakers if there is a shortage and your
17 having to go to non-firm energy and you have to continue
18 doing what you're doing now, but you're doing it in the
19 future, would you explain what the risk is associated
20 wi th any regulatory aspects of FERC, NERC or anybody else
21 in regulatory requirements, reliability standards and
22 then what loop flow can actually do that's uncertain and
23 what effect that could have and where it might occur on
24 those lines as they're currently established?
25 A I'll take a shot at it and please keep
CSB REPORTING
[phone]
593 PORTER (X)
Idaho Power Company
1 asking me the questions so I can fully answer it, but.2 let's start off with summertime what's going on. During
3 the summertime, all of our transmission capacity to the
4 west side which is the market we draw upon is built up
5 wi th purchases. We use those lines tremendously during
6 the summertime, so what happens is any time -- and has
7 been expressed before, a large chunk of that is on
8 non-firm transmission, so it is the first thing to get
9 cut, so any time there's any kind of a transmission
10 overload caused by loop flow or caused by an outage
11 someplace, then the non-firm is the first thing to get
12 cut and what we are required to do is hold so much
13 reserves in our system and what happens is once you.14 start, the first thing we would do is see if there's any
15 other way we can supply that resource, and during the
16 peak summer times, it's very difficult.
17 You can possibly go to the east side to
18 get energy if you can get it, but keep in mind that on
19 the east side of the system, PacifiCorp is having the
20 same issues in Arizona and those areas are having the
21 same issues we are, that's their peak season and so often
22 supplies on the east side are limited and you may not be
23 able to get it or not, so what can happen is that now you
24 start eating into your reserves and reserves can be split.25 into two categories, spinning and non-spin reserve, and
CSB REPORTING
[phone]
594 PORTER (X)
Idaho Power Company
.
.
.
1 so what we do is we start eating into our non-spin
2 reserve and then as soon as we get into the spin reserve
3 portion of it, that's where reliability criteria says no,
4 you shall not. You shall shed load before you get into
5 your spin reserve, and along the way we've declared NERC
6 emergency alerts. We go from stage three to stage two
7 and then finally when you get to stage one, that's where
8 you're actually curtailing load and so that's our
9 responsibility with respect to reliability criteria. We
10 have to maintain sufficient reserves. When we get to a
11 certain point, we start cutting load.
12 Q And the numbers that Idaho Power gave us,
13 and this is an area you may want to defer, but in the
14 numbers that Idaho Power gave us, deficiencies in the
15 summer ,of 2012, do you go past your spinning reserve and
16 into your back-up reserve, your regulatory required
17 reserve on any of those months?
18 A I would defer to Mr. Bokenkamp on the
19 specify numbers, but it happens.It happens and a lot of
20 times you get there in a situation where you've got an
21 outage someplace, like we've got a Bridger unit down or a
22 Valmy unit down and then something, either loop flow
23 which happens because of problems on other people's
24 systems or something is going on that causes overloads on
25 that line and now you can get into that situation, so
CSB REPORTING
[phone]
595 PORTER (X)
Idaho Power Company
.
.
1 it's the battle you face every summertime, but it's not
2 even during the summertime. We've had issues where we've
3 gone into NERC emergency alerts in May. I mean, it can
4 happen.
5 Q Yesterday I asked the question if there
6 were penalties associated with violating the reliability
7 standards. The answer to that question at that time was
8 no, do you agree with that?
9 A No, the answer is yes. NERC reliability
10 standards require you to make sure you have sufficient
11 operating reserves on your system and if you violate it,
12 you can be fined, absolutely.
13 Q What range do the fines run?
14 A You know, it's been a long time.
15 Q Big would work.
16 A The number that I use when I'm talking to
17 my folks about compliance and whatnot is that NERC has
18 the ability to fine us up to a million dollars a day for
19 violation, depending on the severity of it, so it's a
20 pretty big stick.
21 COMMISSIONER KEMPTON: Okay, I i II leave
22 that, Mr. Kline, for additional definition by an
23 appropriate witness on the penal ties. Redirect?
24.25
MR. KLINE: I think both you and
Commissioner Smith took care of my redirect, so no.
CSB REPORTING
[phone]
596 PORTER (X)
Idaho Power Company
.
.
1 COMMISSIONER KEMPTON: Okay, what I'd like
2 to do is to allow the witness to step down. If you would
3 like the witness to come back and hold him for this -- I
4 think in fact the witness may step down.
5 MR. KLINE: We planned to have him here
6 until we completed our case and then maybe we i II ask you
7 to excuse him so he can go back to work.
8 COMMISSIONER KEMPTON: That's fine.
9 (The witness left the stand.)
10 MS. ACKERMAN: Ms. Ackerman, you may call
11 your witness.
12 MR. RICHARDSON: Actually, Mr. Chairman,
13 Ms. Mitchell is my witness.
14 COMMISSIONER KEMPTON: Very well.
15 MR. RICHARDSON: Thank you for
16 accommodating her schedule, Mr. Chairman. The Industrial
17 Customers of Idaho Power would call Cynthia Mitchell to
18 the stand.
19 COMMISSIONER REDFORD: Mr. Chairman?
20 COMMISSIONER KEMPTON: Commissioner
21 Redford.
.
22 COMMISSIONER REDFORD: Are you resting
23 your case?
24 MR. KLINE: No, sir. We still have two
25 other witnesses to present.
CSB REPORTING
[phone]
597 PORTER (X)
Idaho Power Company
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.
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1 COMMISSIONER REDFORD: Why are we going
2 out of sequence?
3 COMMISSIONER KEMPTON: It's the
4 announcements I made right after we came back from recess
5 and that is that Ms. Mitchell needs to catch a plane at
6 2 : 00 0' clock.
7 COMMISSIONER REDFORD: Okay, well, that's
8 good enough for me.
9 COMMISSIONER KEMPTON: And we may run just
10 a little bit long to try and work this out to the best of
11 our abilities.
12
13 CYNTHIA MITCHELL,
14 produced as a witness at the instance of the Industrial
15 Customers of Idaho Power, having been first duly sworn,
16 was examined and testified as follows:
17
18 DIRECT EXAMINATION
19
20 BY MR. RICHARDSON:
21 Q Good morning, Ms. Mitchell.
22 A Good morning.
23 Q Will you please state your name and
24 business address for the record, please?
25 A My name is Cynthia Mitchell and my address
CSB REPORTING
[phone]
598 MITCHELL (Di)
ICIP
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1 is 530 Colegate Court, Reno, Nevada, 89503.
2 Q And by whom are you employed?
3 A I'm the founder of Energy Economics, Inc.,
4 a consulting firm located in Reno, Nevada.
5 Q And did you cause to be prepared prefiled
6 direct testimony and exhibits numbered 206, 207 and 208
7 in this docket?
8 A Yes, I did.
9 Q And do you have any corrections or
10 additions to make to that prefiled testimony or
11 exhibits?
12 A I do.
13 Q Would you make those now for the record?
14 A Please turn to page 3, line 7. "Exhibit
15 207" should read "Exhibit 208."
16 Q Please proceed with your other
17 corrections.
18 A Page 3, line 8, December "2013" should
19 read" 2 0 12. II Page 4, line 2, "Finding 3" should read
20 "Finding 2." Page 4, line 5, "The Company's application
21 states that, II please insert the word "it relies on its."
22 Same page, line 23, "Exhibit 208" should state "207."
23 Page 5, line 7, at the end of the sentence, lithe Company
24 has not adjusted," please strike the word "not." Page 6,
25 line 8, "Finding 4" should read "Finding 3." At the end
CSB REPORTING
[phone]
MITCHELL (Di)
ICIP
599
.
.
1 of the document, page 38, lines 6 through 8, please
2 strike the sentence in parentheses in upper case, and
3 same page, lines 18 and 19, please strike the words in
4 upper case. That concludes all of my corrections.
5 MR. RICHARDSON: Thank you. Mr. Chairman,
6 we submitted an additional exhibit, but we're not going
7 to sponsor that. We will just hold that in abeyance.
8 What I had marked as Exhibit 211 we will not be
9 admi tting.
10 COMMISSIONER KEMPTON: That's the exhibit
11 that you marked 201 -- I'm sorry, 211?
12 MR. RICHARDSON: That's correct.
13 COMMISSIONER KEMPTON: So you're holding
14 that exhibit?
15 MR. RICHARDSON: That's right, thank
16 you.
17 COMMISSIONER KEMPTON: And the record will
18 reflect that.
19 Q BY MR. RICHARDSON: Ms. Mitchell, if I
20 were to ask you the same questions you're asked in your
21 prepared testimony as corrected today, would your answers
22 be the same?
23
24.25
A Yes, they would.
MR. RICHARDSON: Mr. Chairman, I would
move that the prepared testimony of Ms. Mitchell be
CSB REPORTING
[phone]
600 MITCHELL (Di)
ICIP
.
.
18
19
20
21
22
23
24.25
1 spread upon the record as if it were read in full and
2 exhibits numbered 206, 207 and 208 be marked for
3 identification purposes.
4 COMMISSIONER KEMPTON: If there's no
5 obj ection, it is so ordered.
6 (The following prefiled direct testimony
7 of Ms. Cynthia Mitchell is spread upon the record.)
8
9
10
11
12
13
14
15
16
17
CSB REPORTING
[phone]
601 MITCHELL (Di)
ICIP
.1 I.Introduction and Overview
2
3 Q.Please state your name and address and
4 summarize your qualifications.
5 A.My name is Cynthia Mitchell. My address is 530
6 Colegate Court, Reno Nevada 89503. I am the founder of
7 Energy Economics, Inc., a consulting firm located in Reno
8 Nevada. A copy of my resume is attached as Exhibit 206.
9 I am testifying on behalf of the Industrial Customers of
10 Idaho Power.
11
.
.
Q.What is the purpose of your testimony?
12 I provide technical support to Dr. Reading'sA.
13 testimony relative to the stale nature of the load and
14 load growth forecasts relied upon by Idaho Power in
15 support of its request for a CPCN to build the Langley
16 Gulch Power Plant. The purpose of my testimony is to
17 provide a review and analysis of Idaho Power Company's
18 (IPC) proposed 330 MW CCCT Langley Gulch generation
19 facility with a proposed in service date of January (?)
20 2012 from an Integrated Resource Planning (IRP)
21 perspective.
22 Can you speak generally regarding the properQ.
23 role of IRP in the ratemaking context?
24 IRP requires supplementing tradi tional utilityA.
25 regulation with a comprehensive regulatory framework that
602 Mitchell, Di 1
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1 sets new checkpoints for the utility resource planning
2 and procurement process. The principal consumer benefit
3 of IRP when viewed as a regulatory construct lies in
4 changing the roles that regulator and also consumers play
5 in utility planning and procurement from those of "Monday
6 morning quarterbacks" to active players.
7 As a utility planning and procurement process,
8 the utility must consider the feasibility and economics
9 of non-utility generation including small power
10 production and co-generation proj ects. While IRP still
11 involves analysis of the existing and possible future
12 demand for energy on an utility system-wide basis , its
13 cornerstone is a more fine-grained consideration of
14 existing and future energy needs on a:
15 Discrete spatial or location-specific basis
16 wi thin the utility service terri tory, and
17 "End Use" basis that considers the required
18 useful energy service output such as light,
19 space heating and cooling, water heating,
20 refrigeration, motor drive, etc.
21 Through the IRP construct, existing and
22 possible future energy demand is not a " given", but
23 something that can be modified and or reduced through any
24 number of "demand side
25 /
603 Mi tchell, Di 1a
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1 management II (DSM) tools or techniques including but not
2 limited to energy efficiency (EE), conservation, load
3 management (LM) and demand response (DR).
4 IRP as a utility planning and regulatory
5 construct pre-dates this country 's late- 1990' s
6 deregulation/" competition" movement. This time around
7 (" IRP Round 2"), the energy policy and utility regulatory
8 issues have expanded beyond ratepayer economic and
9 utili ty financial investigations wi thin relatively robust
10 economic conditions and limited environmental
11 "externality" considerations. Now states and regions,
12 our country and world, face the sobering prospect of
13 possible ongoing relatively stagnant economic growth
14 given constraints on available and affordable investment
15 capital, resource inputs (oil, gas, metals, aggregate
16 materials, etc.), and innovative production capabilities.
17 This, coupled with the very real potential negative
18 environmental consequences of global warming via the
19 rising levels of C02 or "greenhouse gas" (GHG) emissions,
20 is very sobering indeed.
21 Interestingly, the recession with its downward
22 pressure on electricity demand, affords the Commission to
23 turn IPC' s otherwise Langley Gulch "Sow i s Ear" into a
24 "Silk Purse". Rather than commit IPC and ratepayers to
25 the very capital intensive long-lead time Langley Gulch
604 Mi tchell, Di 2
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1 during a recession with its resultant downward pressure
2 on electricity demand, the Commission has time to more
3 fully consider the timing, type, and location of possible
4 future generation resources in part through an
5 independently run competitive solicitation process. Also
6 the Commission in collaboration with IPC, state and local
7 governments, and businesses and industries has the
8 opportuni ty to more fully manage electricity demand
9 through a variety expanded and new energy efficiency,
10 load management, and demand response techniques.
11 II. Sumary of Findings and Recommendations
12
13 Q.Please summarize your recommendations and findings.
14
15 Finding 1: IPC has provided no compelling reason for the
16 Commission to expedite its review of IPC i S Langley Gulch
17 Application in order to meet future loads in the 2012
18 timeframe.
19 The Company's March 2, 2009 Langley Gulch
20 Application requests expedited review outside of the
21 Commission's IRP process in order to meet a purported
22 peak load deficit in June 2012. By first receiving
23 permission to file its June 2009 IRP in December 2009,
24 IPC set the stage to try and rush Langley Gulch through
25 wi thout the benefit of (1) an updated load forecast
605 Mi tchell, Di 2a
ICIP
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1 that reflects the effects of the recession on near- and
2 possible longer-term electricity requirements and (2)
3 integration of forecasted load and existing supply-side
4 resources wi th additional non-utility supply side
5 resources such as the recently-let wind generation RFP
6 and additional DSM energy efficiency and demand response
7 resources.
8 Interestingly, per IPC i S response to Staff's
9 Production Request #84, which provides what the Company
10 labels "2009 IRP" Peak-Hour Load and Average Energy Load
11 and Resources Balance 2009 through 2028, (see Exhibit
12 208) the Langley-Gulch in-service date has been slipped
13 from June 2012 to December 2012. Thus, IPC has handed
14 the Commission an additional six months to review its
15 Application.
16 Also, the Company's 2009 IRP Peak-Hour Loads and
17 Resources Balance table for winter 2012, shows for the
18 row entry "Network Set-Aside for Firm Purchases II :
19 November 2012 at 734 MW
20 December 2012 at 673 MW
21 January 2013 at 441 MW
22 February 2013 at 536 MW
23 March 2013 at 504 MW
24 April 2013 at 402 MW
25
606 Mi tchell, Di 3
ICIP
.1 If IPC can purchase 734 MW of firm purchases in
2 November 2012, it can in all likelihood purchase at least
3 the equivalent amount of 734 MW in December 2012 through
4 March or April 2013. Per the Company i s own analysis,
5 this shifts out the in-service date of Langley-Gulch an
6 addi tional 3 to 4 months.
7 Further, the Company's 2009 IPR Average Energy
8 Loads and Resources Balance table for 2013 shows for the
9 row entry "Network Set-Aside for Firm Purchases" all
10 months at 115 aMW. If IPC can purchase upwards of 734 MW
11 of firm purchases in November 2012 ON PEAK, it can also
12 in all likelihood purchase more than 115 aMW during
.13 non-peak periods in sufficient amounts to cover the July
14 and August 2013 monthly deficits of 369 and 276 aMW shown
15 respectively per Exhibit 207.
16 For these reasons alone when working with IPC' s
17 own data and assumptions, the Company has provided no
18 compelling reason for the Commission to expedite its
19 review of IPC' s Langley Gulch Application outside of the
20 2009 IRP process.
.
21
22 /
23
24 /
25
607 Mi tchell, Di 3a
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1 Finding 2: On a load forecasting and demand side
2 management (DSM) basis, IPC has not reasonably
3 demonstrated the need for the Langley Gulch Proj ect in
4 June 2012 (June 2008 IPR Update) or December 2013 (Staff
5 Production Request #84).
6 The Company's Application states that relies on
7 its June 2008 IPR Update to justify the proposed Langley
8 Gulch 330 MW CCCT. The 2008 IRP Update utilizes an
9 August 2007 load forecast that is based on pre-recession
10 demographic and economic indicators in Idaho that do not
11 take into account more current and likely future
12 condi tions for the state. The recession is resulting in
13 significant downward pressure on personal income,
14 employment, and economic acti vi ty. These factors strongly
15 affect electricity usage per customer, which in turn
16 drives the demand for electricity wi thin IPC' s service
1 7 territory.
18 IPC response to Staff Production Request #84
19 2009 IRP Loads and Resources Balance 2009 - 2028
20 represents to use a May 2009 load forecast. Exhibit 208
21 provides a comparison of four IPC load forecasts in 2010
22 and 2013 at 95% MW Peak and 70% aMW Energy:
23 Production Request (PR) 84 2009 IPR
24 August 2008 Load Forecast per IPC i S February
25 2009 IRP Addendum Boardman-Hemingway
608 Mitchell, Di 4
ICIP
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1 Transmission Proj ect
2 August 2007 Load Forecast per IPC' s 2008 IRP
3 August 2005 Load Forecast per IPC' s 2006 IRP
4 Because the load forecast per PR 84 2009 IRP is
5 apparently the most current, the peak demand MW or
6 average energy aMW difference or change from the most
7 current to the previous forecasts are shown in the rows
8 labeled "Change +/- MW" and "Change +/- aMW" of Exhibit
9 207. The data reflect that the following for both 2010
10 and 2013 Loads and Resources Balance:
11 On both a 95% MW peak and 70% aMW energy basis,
12 IPC' s most current load forecast per PR 84 2009
13 IPR is essentially the same as its August 2008
14 load forecast per February 2009 Addendum B-H
15 Transmission Proj ect .
16 Interestingly, again on both a 95% MW peak and
17 a 70% aMW energy basis, IPC's most current load
18 forecast per PR 84 2009 IRP is in all months
19 either higher or the same as its August 2007
20 load forecast per its 2008 IRP Update.
21
22 /
23
24 /
25
609 Mi tchell, Di 4a
ICIP
1 And, somewhat surprisingly, the same pattern.2 holds for a comparison to IPC i s August 2005
3 load forecast per its 2006 IRP. That is, the
4 more current 2009 IRP load forecast is in many
5 months either higher.
6 Without reviewing the underlying key
7 demographic and economic indicators that drive IPCs' PR
8 84 2009 IRP, it is not possible to determine the extent
9 to which the more current load forecast reasonably
10 reflects the near- and possibly longer-term effects of
11 the current recession. However, on the face of it
12 certainly does not appear that the Company has adjusted
.13 its 2009 IRP load forecast per Staff Production Request
14 #84 or any other previous load forecasts to reflect the
15 current recession.
16 My analysis indicates that even once the
17 economic recovery is underway, it will take some years
18 for personal income and employment to return to 2006-2007
19 levels. These levels will not be reached by the end of
20 2011 and, at the rates of increase forecast for that
21 period (Q3 to Q4 of 2011) are unlikely. Early indications
22 are that IPC' s 2009 energy usage is off by about 5% from
23 early 2008 levels.
24 There are other indications that components of.25 IPC's proj ected loads will be delayed or may fail to
610 Mi tchell, Di 5
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.
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1 materialize. For instance, the "Special Contract" load
2 Hoku Scientific Inc. (forecasted at 38 aMW/43 MW peak in
3 the June 2008 IRP Update), recently announced that may
4 have not have enough money to complete its polysilicon
5 plant in Idaho.
6 Also, there are recent additional DSM resources
7 not reflected in IPC' s 2008 IRP Update that further
8 reduce the need to the Langley Gulch Proj ect in June 2012
9 timeframe. For example, IPC is currently expanding its
10 very successful Irrigation Peak Rewards Program. For this
11 summer, it has added the option of a dispatchable demand
12 response program which will increase the demand
13 reductions derived from the program. IPC is also
14 proposing a commercial demand response program not
15 reflected in the June 2008 IRP Update.
16 There are also non-utility energy efficiency
17 and demand response acti vi ties and programs not reflected
18 in the 2008 IRP Update. For example, the Boise City
19 Council's recent meeting to discuss 10 potential energy
20 proj ects that could reduce demand through energy
21 efficiency. These
22
23 /
24
25 /
611 Mi tchell, Di Sa
ICIP
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1 projects include LEDs and energy efficient lighting and a
2 cogeneration plant at the West Boise waste water
3 treatment facility. 1
4 Further, as will be discussed in Section v:
5 DSM, it appears that IPC has been shrinking rather than
6 growing its forecasts of additional or new energy
7 efficiency savings from its 2006 IRP, 2008 IRP Update,
8 and 2009 IRP Addendum. Not only is this illogical, but
9 all other factors being equal, works to favor new
10 generation resources.
11 Finding 4: Winter peak demand is also important issue in
12 the IPC service territory.
13 As part of its current energy efficiency
14 programs, IPC' s rebates or cash incentives often favor
15 electric space heating over natural gas or propane
16 heating. Winter peak demand is an increasingly important
17 issue in the IPC service terri tory. While there is a
18 clear historical trend toward higher use in general and
19 particularly in summer, a distinct secondary winter peak
20 is emerging.
21 Recommendation 1: The Commission should consider Langley
22 Gulch based on IPC' s forthcoming August 2009 load
23 forecast as part of an integrated loads and resources
24 analysis via IPC's 2009 IRP.
25 Because IPC has provided no compelling reason
612 Mi tchell, Di 6
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1 for the Commission to expedite its review of IPC' s
2 Langley Gulch Application in order to meet future loads
3 in the 2012 timeframe, the Commission should consider
4 Langley Gulch based on its forthcoming August 2009 load
5 forecast as part of an integrated loads and resources
6 analysis via IPC's 2009 IRP. The August 2009 load
7 forecast should more reasonably reflect current, near,
8 and possibly longer term economic conditions and
9 resultant impacts of electricity demand.
10 Also, the near-term energy conservation, energy
11 efficiency, load cycling and demand response utility and
12 non-utility activities underway and emerging should be
13 reflected in the 2009 IRP. And, IPC should reverse its
14 recent pattern of shrinking proj ected new DSM savings.
15 Further, the Commission should require a
16 detailed analysis of IPC' s secondary winter peak and
17 possible DSM acti vi ties and programs to curtail its
18 growth. This could include a review
19
20 /
21
22 /
23
24 i How will Boise spend its energy stimulus grants?
IdahoStatesman.com, June 9, 2009.
http://www.idahostatesman.com/localnews/v-print/story/796461.htm25
613 Mitchell, Di 6a
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1 IPC' s current retail tariffs to ensure that utility rate
2 design is not at cross purposes with energy efficiency
3 acti vi ties and programs. For instance, it makes no sense
4 to send price signals that promote increased consumption
5 via declining block rates and high fixed customer charges
6 while developing and implementing energy efficiency
7 programs. The secondary winter peak appears to feed into
8 the Company's justification for new baseload generation.
9 Finding 4: ICP is not facing the sort of financial
10 difficulty that would suggest that current recovery of
11 CWIP is appropriate.
12 IPC' s stock has been selling well above book
13 value over most of the last decade and was selling above
14 book as late as the end of the fourth quarter of 2008.
15 The current stock market meltdown and credit crunch (plus
16 a sale of over 1 million shares of stock in the fourth
17 quarter of 2008) took them below book value at the end of
18 the fourth quarter, although the stock price has
19 increased somewhat in recent months. The relationship of
20 the stock price to book value is of key importance
21 because issuing new stock below book value will dilute
22 the holdings of existing shareholders.
23 Further, CWIP is inappropriate for several
24 reasons.It is both inconsistent with competi ti ve market
25 processes and essentially blunts incentives associated
614 Mi tchell, Di 7
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.1 wi th integrated Resource Planning, has adverse
2 intergenerational impacts. If adopted, it reduces the
3 utility's business risk, though we have not seen IPC
4 volunteer for a lower return on equity or less equity in
5 its capital structure.
6
7 III. Organization of Testimony
8 Section iv: Load Forecasting
9 Section v: DSM and Rate Design
10 Section VI: Integration of Loads and Resources
11 Section VII: Construction Work in Progress (CWIP)
12
13.14
16
18
20
.
iv. IPC Load Forecast: The Recession and Demand forElectrici ty
15 /
17 /
19 /
21
22
23
24
25
615 Mi tchell, Di 7a
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1 Q.Please explain your findings relative to the
2 recession and demand for electricity.
3 A.IPC's Langley Gulch Application states that
4 "having this Proj ect available to meet future loads is
5 extremely important. Therefore, to the extent the
6 Commission can expedi te its review of this Application,
7 it will redound to the benefit of customers and system
8 reliabili ty. "2 Also, IPC Witness Mr. Bokenkamp
9 represents that "Load growth wi thin Idaho Power's service
10 terri tory is primarily what drives the need for new
11 generating resources. "3 IPC works with number of
12 households and employment proj ections, along with
13 customer consumption patterns, to develop customer
14 forecasts and load proj ections. These proj ections were
15 updated in IPC' s August 2007 annual load forecast which
16 is then in turn is used as the sales and load forecast
17 for the 2008 IRP Update. (p. 9 2008 IRP).4
18 Several factors related to load growth are cited as
19 supporting the need and timing of Langley Gulch:
20 Large historical load growth (from 1990 to
21 2008)
22 2004 & 2006 Integrated Resource Plans called
23 for a new baseload resource
24 Possible new large loads in IPCo service
25 territory
616 Mi tchell, Di 8
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1 Shift in timing of federal water releases.2 All but the change in federal water releases
3 are based on the pre-recession situation in Idaho and do
4 not take into account more current, and likely future,
5 economic indicators for the state.
6 The recession has caused load growth to level off or
7 decline throughout the U.S. and worldwide.5 Figure 1:
8 "U. S. Electricity Consumption and Annual Growth in
9 Consumption
10
11 /
12
13 /.14
15
16
17
18 2 Application item 26.
19 3 Testimony page 3, lines 9-10.
20 4 In the 2008 IPR Update, both the average energy and peak-hour load
forecasts declined relative to the 2006 IRP.
21
5 For example, the EIA's May 12, 2009 Short Term Energy Outlook
22 reports that the recession has led to reduced demand from the
industrial sector. The EIA expects total electricity use to decline
23 0.8% this year
(http://www . eia. doe. gov lemeul steo/publ cont.',:nts. html ?featureclicked=1&
24 ). The International Energy Agency recently forecast its first
electricity use decline since 1945..25
617 Mi tchell, Di 8a
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13
. 14
.
12
15
16
17
18
19
20
21 /
22
23 /
24
25
1 1998-2008 with Forecast to 2010" shows that from 1998
2 through 2007, the annual electricity growth rate was
3 posi ti ve in every year but for a slight negative growth
4 rate of -0.7% in 2001, while approaching a zero growth
5 rate (0.2%) in 2006. 2008 shows a marked decrease of
6 -1.6% in annual growth in electricity consumption. The
7 2009 forecast continues with a decline of -0.8%, with a
8 slight rebound forecast in 2010 of 1.5%.
9
10
11
/
618 Mi tchell, Di 9
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1.2 Figure 1: U.S. Electrcity Consumption and Anual Growt in
Consumption 1998-2008 with Forecast to 20103
4 U.S. Total Electricit Consumption
6
13
Bilion 12
kilewtt 11
hours 10
perdey 9 ...
8
3.7'1
1 1.70/
: Forecast5
.. Consumption. . . . ...... ..
7
9
Annual Growt'"
2.8%3%
2%
1% Chengfrom0% Prior
-1% Year
-~Io
-34
8
10
11 1998 1999 20 201 20 203 2004 20 200 2007 208 20 2010
12 Short-Term Energy Outlook, May 20 --
13.14
Source: Energy Infonnation Administration, Short-Term Energy Outlook, May 122009:ht://w.'ÎI.do,go~~O,gl
15 It has attributed this decline to the seriousness of the
current economic recession16 (http://www.ibtimes.com/articles/20090SSS/iea-forecasts-
first-electricity-use-decline-since-194S. htm). The North17 American Electric Reliability Corp forecasts a decline in
electric consumption to 2006 levels this summer due to
18 the effect of the recession on industrial power use
(http://news. yahoo. com/ s/nm/20090S19/us nm/us utilities
19 nerc summer/print). Similarly, the ISO-NE Regional
System Plan 2008 "reports that peak demand for
20 electricity in New England is projected to be somewhat
lower than the previous 10-year demand forecast, largely21 due to lower growth in the long-run forecast of personal
income
22 (http://tdworld. com/business/iso-new-england-plan-1008/) .
iso NE 's 2009 forecast shows that demand for electricity
23 in New England declined in 2008 and that growth in future
demand is likely to slow because of economic conditions24 (http://isonewengland.net/nwiss/grid mkts/key facts/ct pr
ofile. pdf) ..25
619 Mi tchell, Di 9a
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1.2
3
4
5
6
7
8
9
10
11
12
13.
15
16
17
18
19
20
21
22
23
24.25
Table 1 "Idaho Power Company Form 10-K Reported
Energy Usage First Quarter 2008 and First Quarter 2009"
shows that from 2008 to 2009, Residential and Commercial
energy (MWh) usage was down -3.5% and - 4 .2% respectively,
with a larger decline of -8.2% in industrial energy (MWh)
usage. The average decline for these three customer
categories totals nearly -5%.
--0___0_0
Table 1: Idaho Power Company Form 10-K
Reported Energy Usage First Quarter 2008 Ri First Quarter 2009
1st Q08 1st 009 % Change
Energy Use (MWh) Energy Use (MWh) 1Q08 to 1Q09
1,588,912 1,533,859 -3.5%
998,994 956,875 -4.2%
850,838 780,973 -8.2%
3,438,744 3,271,707 -4.9%
11,061 7,257 -34.4%
11.3%
Residential
Commercial
Industrial
SUB-TOTAL
Irrigation
Off-system sales
The demand for electricity while influenced by
a number of factors, is largely correlated to changes in
population, personal income, and the levels of economic
acti vi ty. Idaho Division of Financial Management's (DFM)
April 2009 Idaho Economic Forecast6 provides the
following information and data for the State of Idaho
concerning changes in these key indicators.
A. population
State population growth has been substantially
620 Mitchell, Di 10
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.
.'
1 curtailed in recent months. In the last quarter of 2008
2 Idaho's population increase was just 0.14 % .Forecasts to
3 2011 show that while the rate of increase in the
4 population is likely to rise from late 2008 levels, it is
5 not expected to reach the levels recorded in 2006 and
6 2007.7
7 1.Migration
8
9 /
10
11 /
12
13 /
14
15
16
17
18
19
20
21
22 6 April 2009 most recent available at time of testimony filing.
23 7 Idaho Economic Forecast Quarterly Detail, April 2009,
http://dfm. idaho. gov/Publications/EAB/Forecast/2009/April/quarterly
24 detailable.pdf
25
621 Mi tchell, Di lOa
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.
ie
.
13
14
15
16
17
18
19
20
21
22
23
1 A similar pattern is evident regarding
2 migration. Net migration slowed between 2006 and 2008
3 (in the last quarter of 2006 net migration was 20,600
4 whereas by 2008 this figure had fallen to 3,500), and is
5 forecast to be negative in late 2009 and early 2010
6 (Figure 2). By the end of 2011, net migration is still
7 expected to be substantially lower than in 2006 (nearly
8 30,000 1st quarter 2006 and forecast at 13,900 in the
94th quarter of 2011).
10
11 Figure 2: Net Migrtion to Idao 2006-2008 with Forecast to 2011
12 30 .-~. ~. ~ -.---,.. '~'_._--.._'-__...___ ._.__._ .__...._.. .. __._._..... . ... _...__..._____
2S
20 1.._._- -- .....
ßL-
l J
5 .-.----------...-~-.---..
!
o l
.L --_.....__.... ~-.- .~, .,.-
1
iQ.Ql Q2 Q3 Q.Ql Q2 Q3 Q.Ql Q2 Q3 0.4 ! Ql Q2 Q3 Q.Ql Q2 Q3
2007 20 200 2010 201
Ql Q2 Q3
2006
Source: Idao Economic Forecast Quarly Detal, Apri12009
2 4 http://dfm.idaho.gov/Publications/EAB/Forecastn009! April quarter! vdetailtable. pd t
25
622 Mi tchell, Di 11
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( .
.
1 While the number of new starts is forecast to increase
2 beginning in the 2nd quarter of 2009, the levels recorded
3 in 2006 are not expected to return by the end of 2011.8
4
5 Figure 3: Idaho Housing Stas 2006-2008 with Forecast to 2011
6 25,000 1----
~J~
i
. ß~ L__~"__
~~v;:io.it.=
E:i2
7
8
9
10
11
12
13
10,000 ,. ---
¡
5,000 l_..._.._______.___
,L------
1m m ~ ~ 1m m ~ ~ 1m m ~
I 2006 2007' 2008, : i 2009 2010
14
15
~L
2011 I
16 i
Q41m m ~Q4 ¡m m Q3 Q4 m m ~
i17
18 Source: Idaho Economic Forecast Quaerly Detail, Apnl 2009
htt:i !dfr,idaho,gov/PublicatìonAB/ForecOOAPdQ~ly.tltae,pçf
19
20 Gi ven that changes in average load are
21 overwhelmingly correlated with changes in the number of
22 customers served, the recent and forecast lower
23 population growth and housing starts will reduce the
24 near-term need for new generation.
25
624 Mi tchell, Di 12
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.
20
21
22
23
24.25
1 B.Personal Income
2
3 /
4
5 /
6
7 /
8
9
10
11
12
13
14
15
16
17
18
19
8 Idaho Economic Forecast Quarterly Detail, April 2009,
http://dfm. idaho. gov/Publications/EAB/Forecast/2009/April/
auarterlydetailable. pdf
625 Mi tchell, Di 12a
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20
21 /
22
23 /
24
25
1 The depth of the recession is such that
2 available forecasts indicate that personal income is
3 likely to remain well below 2006/early 2007 levels beyond
4 2011 (Figure 4). In the 1st quarter of 2007 per capita
5 personal income in Idaho reached $27,159 in 2000 $. By
6 the fourth quarter of 2008 it had declined to $26,387 (a
7 drop of 2.8%). Personal income is forecast to decline to
8 $26,025 in the 2nd quarter of 20109 and then increase to
9 $26,415 by the 4th quarter of 2011.10 That is, by the end
10 of 2011 per capita personal income (in real 2000 $) is
11 forecast to be only a little higher than at the end of
12 2008 and still almost 3% lower than its peak in the first
13 quarter of 2007. Beyond 2011, even if personal income
14 continued to recover at the rate forecast for the end of
15 201111, it would not reach 2007 levels until 2013.
16
17
18
19
/
626 Mitchell, Di 13
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15
16
17
18
19
20
1
2
3
4
5
6
Figue 4: Idaho Per Capita Personal Income 2006-2008 with Forecast to 2011
27,400 T---.---.-~---- ....
7
27.200 ~-
8
9
27,000 L_.
I
26,800 i----.-
;26,00 -j--
I
10
11
.,
~.~ 26,400.s
j
12
¡
26,200 r..
26.000 I
25 800 i, i13
14 25,600
25,400 ~~ i o.l as !Q4 !.Ql I o.l as ! Q41 Ql lo. as Q41 Ql o.l O3! ~~'Q:r 03 ~I Q4-1 Ql i o. -1031. Q41
~006 I : ~007 I ~008 2009 I ~010 I . !2011 I i
Source: Idaho Economic Forecast Quaerly Detal, April 2009
http://dfm.iOOo.i2væubllca2iwIFQt~20091 Apll.,iYØltale..pdf
21 9 These trends have led to a decline in personal income, for the
first time since 1986
22
10 Idaho Economic Forecast Quarterly Detail, April 2009,
23 http://dfm. idaho. gov /Publications/EAB/Forecast/2009/April/
quarterlydetailable. pdf
24
25
11 Between Q3 and Q4 of 2011 per capita personal income is forecast
to rise 0.422%
627 Mi tchell, Di 13a
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1 c.Economic Acti vi ty
2 The Idaho Division of Financial Management
3 summarized the economic situation in 2008 as follows:
4 "After several years of strong growth, Idaho's
5 economy shrank last year, and it is expected to turn in
6 disappointing performances in both this year and next.
7 The extent of last year's decline can be seen in several
8 indicators. Idaho nonfar.employment shrank 1% in 2008,
9 which is its weakest performance since 1987. The state's
10 goods-producing sector was disproportionately hard hit in
11 2008. Weighed down by double-digit declines in its
12 construction, lumber and wood products, and computer and
13 electronics sectors, the goods-producing sector fell over
14 8% last year. The nongoods-producing sector's employment
15 did not decline, but advanced by a meager O. 6%-i ts
16 weakest showing according to records that go back through
17 1991. "12
18 They are also reflected in the Gross State
19 Product. As shown in Figure 5, Idaho's real GSP
20 increased each year between 2005 and 2007. In 2008,
21 however, it remained almost level with the 2007 figure,
22 recording a 0% change for that year. In the U. S. as a
23 whole real GDP increased 0.7% between 2007-2008, so the
24 recession has hit Idaho's economy even harder than is the
25 case for the nation as a whole. 13 In terms of industry
628 Mi tchell, Di 14
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1 sectors, the greatest contributor to Idaho's stagnant GSP.2 was the construction sector (-1.58 percentage points) .14
3 Since housing starts contribute to load growth, this
4 downturn in construction is likely to reduce demand for
5 electricity in the near term.
6
7 /
8
9 /
10
11 /
12
13.14
15
16
17
18
19 12 State of Idaho Division of Financial Management, Idaho Economic
Forecast, April 2009:
20 http://dfm. idaho. gov/Publications/EAB/Forecast/2009/April/Idaho
0409.pdf page 15
21
13 Economic Slowdown Widespread Among States in 2008, Bureau of
22 Economic Analysis, June 2, 2009:
http://www.bea . gov/newsreleases/regional/gdp state/gsp
23 news release . htm
24 14 Regional Accounts Tables, Bureau of Economic Analysis,
www . bea . gov.25
629 Mi tchell, Di 14a
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.
.
1 Figure 5: Idaho Gross State Product (GSP) and Percent
2 Change in GSP: 200~-2009
3
4 _Percent change GSP --Real GSP
46,000 I
45,500 1
45,0001- .
44,500 1--..
i "., Lie 1.
¡ 43,500 . _..
43,000 L.
42,500 L_.
42,000 L.__
41,500 L_...
.~..
! S.O
-_._._._"..~..._l 7.0
I. -_.--_...... ...------.16.0
5
6
7
8
9
Go'"
5.0 \l
:.c..
-S
1:4.0 or
!
~orGo
3.0
2.0
10
11
12 ...._.._.-.........~.... . ...-... - -....
.... .............13
14
15 2005 2006 2007 2ooS.
, ..__.___.__._~_._______._.,__"._____._._._.._.._..
16 Source: Bureau of Economic Analysìs, Regìonal Accounts
17
18 The forecast for 2009 is even worse than the situation in
19 2008:
20 "Idaho nonfar. employment is forecast to
21 decline almost 5% in 2009. This decline reflects
22 continued weaknesses in several sectors being joined by
23 . employment drops in other sectors that were spared last
24 year. As was the case in 2008, goods-producing employment
25 is especially hard hit. It is forecast to decline over
630 Mi tchell, Di 15
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1 difficulties. Construction employment is forecast to
2 decline another 17%. Lumber and wood production is
3 proj ected to fall 23%. Computer and electronics
4 manufacturing, which is weighed down by layoffs, declines
5 20%. Mining employment, which grew last year, decreases
6 30%. Job losses are also expected to be widely
7 distributed among the categories of the heretofore immune
8 nongoods producing sector. In fact, of all its
9 categories, only information and state and local
10 governments post job gains. But these increases do not
11 offset the expected decreases. As a result, services
12 employment is forecast to be down 3.7% and trade
13 employment is down 4.4%.
14
15 /
16
17 /
18
19 /
20
21
22
23
24
25
631 Mi tchell, Di 1Sa
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1 Government employment is up slightly. Overall,
2 nongoods-employment should fall 3% in 2009. Idaho nominal
3 personal income falls 0.2%, but grows 0.1% after
4 adj usting for deflation. Housing starts are expected to
5 fall to about 5,700 units. In 2009, in-migration is
6 forecasted to slow significantly, causing Idaho
7 population to expand just 1% that year. "15
8 Figure 6 reflects how nonfarm employment in Idaho peaked
9 in the 4th quarter of 2007 and then declined throughout
10 2008. It is forecast to continue to fall until the 4th
11 quarter of 2009. Even by the end of 2011, nonfarm
12 employment is expected to be 3.6% lower than at the end
13 of 2007 (see Figure 4). As with personal income, beyond
14 2011, even if employment levels recovered at the rate
15 forecast for the end of 201116, they would not reach 2007
16 levels until the final quarter of 2012 and the beginning
17 of 2013.
18
19
20
21 /
22
23 /
24
25 /
632 Mi tchell, Di 16
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.
.
.
14
15
16
17
18
19
20
21
1
2
Figure 6: Idaho Non-Far Employment 2006-2008 with Forecast to 2011
3
670,00 T--.-..--..-.------...-.--.c..-----...---...--.-.- _ ._.._
4 66,00 :
I65,00 I /' ------ ---. . - -
-)/---6300 t.."-. - --.-.., ,
j 620,00 I!
:::: L_____.. _ ._..____......_.
590,00 1.__________._.__.____...___ _
58,000 l._.__-_.___m~ m
5
6
7
8
9
10
11
12
-'1 i., 1m ..;r., m '.. 1m Itf m I., IlO3lQ4 QiIQ2!03 '1Cl
. ii7 j ~00 _ i ~ ~010. ~Oll:13
Source: Idaho Economic Forecast Quaerly Detal, Apnl2009
http;//dfm.idahQ.gov/PublicatIonsIEAB/Forecast/2009/ Aprìl quarer! vdetailtable.pdf
22 15 State of Idaho, Division of Financial Management, Idaho Economic
Forecast, April 2009:
23 http://dfm. idaho. gov /Publications/EAB/Forecast/2009/April/
quarterlydetail table. pdf
24
16 Between Q3 and Q4 of 2011 total nonfarm employment is forecast to
25 rise 0.91%.
633 Mitchell, Di 16a
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.
i.e
.
1 Figure 7 shows that for employment in the goods
2 producing sector, the forecast is for an even greater
3 proportionate decline. By the end of 2011, employment in
4 this sector is forecast to be 22% less than at its peak
5 in the 1st quarter of 2007. Beyond 2011, even if the rate
6 of increase forecast for the end of 201117 doubled in
7 subsequent years, it would not be until 2014 that
8 employment in the goods producing sector would reach the
9 levels recorded in 2007.
10 Figure 7: Idaho Goods Producing Employment 2006-2008 with
11 Forecast to 2011
12
13
130.00 j
120.00
,J
14
15
16
17
100,000
~
l
18
I
90.000 L._.._.__
~~L__
~J
~~ f. ~Iæ læ-I~~læ læ 1m ~Iæ læm ~Iæ t 1m ~Jæ It ~ifl
19
20
21
22
23
24 Source: Idaho Economic Forecast Quaerly Detail, April 2009
http://dfm.idao .govlPublicationsEABlForeast/2001 Aprl/guaerlydltale.pdf25
634 Mi tchell, Di 17
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.
20
21
22
23
24.25
1 Construction employment registered a
2 particularly marked drop in the 4th quarter of 2008 (-5%
3 compared to the 3rd quarter). Employment in this sector
4 is expected to continue to fall
5
6 /
7
8 /
9
10 /
11
12
13
14
15
16
17
18
19
i 7 Between Q3 and Q4 of 2011 employment in the goods producing sector
is forecast to rise almost 1.3%. Doubling this rate leads to a
quarterly increase of almost 2.6%.
635 Mitchell, Di 17a
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.
1 until the second quarter of 2010, after which small
2 increases (around 1%) are forecast.18 By the end of 2011,
3 the number of people employed in construction, one of
4 Idaho's hardest hit industries, is forecast to be only
5 two-thirds of the number employed in the industry at the
6 end of 2006. That is, employment in this sector would
7 have to increase by more than one third in 2012 to regain
8 its 2006 levels.
9 This analysis indicates that even once the
10 economic recovery is underway , it will take some years
11 for personal income and employment to reach 2006-2007
12 levels. These levels will not be reached by the end of
13 2011 and, at the rates of increase forecast for that
14 period (Q3 to Q4 of 2011) are unlikely to be reached
15 until 2013 or beyond.
16
17 D.Comparison of Key Factors Influencing
18 Electricity Demand: IPC August 2007 Load Forecast and
19 Idaho Division of Financial Management April 2009
20
21 Q. Please explain your comparison of the most
22 recently released IPC data on per capita personal income
23 and non-farm employment.
24
25
A.The following is a comparison of IPC' s August
2007 load forecast as presented in its June 2008 IRP
636 Mi tchell, Di 18
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.
.
1 Update to the most recent April 2009 forecasts produced
2 by Idaho' s Division of Financial Management
3 1.Per Capita Personal Income
4 Figure 8 compares the IPC August 2007 load
5 forecast of per capita personal income with the April
6 2009 forecast from the Division of Financial Management
7 (DFM). The IPC forecast shows a steady upward climb in
8 personal income to 2011. This contrasts with the more
9 recent DFM forecast which shows per capita personal
10 income declining from 2007 to 2010, before beginning to
11 increase again in 2011. Even with the increase in 2011,
12 however, per capita personal income is forecast to remain
13 below 2006 levels between 2008 and 2011. The difference
14 between the two forecasts increases from 2008 on. By
15 2011, the difference is over six per cent (see Figure 9),
16 with the DFM forecasting substantially lower per capita
17 personal income than those in IPC' S August 2007 load
18 forecast.
19
20
21
22
23 18 Idaho Economic Forecast Quarterly Detail, April 2009,
http://dfm. idaho. gov/Publications/EAB/Forecast/2009/April/
24 quarterlydetailtable.pdf
25
637 Mitchell, Di 18a
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1.2
3
4
5
6 /
7
8 /
9
10 /
11
12
13.14
15
16
17
18
19
20
21
22
23
24
25.
638 Mitchell, Di 19
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.
.
.
10
11
1
2 Figure 8: Idaho Per Capita Personal Income IPC August 2007 and
DFM April 2009 Forecasts
3 28,500
i:. ..IPC (adju,tedto 2000$)
.. DFM 2009 (200 $l
f-i
4 28,000
5 27,500
6 27,000 -
7
-
~g 26,500-
::"'
8 26,000
9 25,500
25,000 ..
24,500
2006 2007 2008 2009 2010 2011
12
Source: IPC IRP 2008 Update and Idaho Economic Forecast Quarerly Detail, April 2009
1 3 http://dfm.idaho,go\'/PublicationsEAB/Forecast/2009/April!quaer!Ydetaltable. PSf
14
15 Figure 9: Percent Difference IPC August 2007 and DFM
16 April 2009 Forecasts of Per Capita Personal Income
17
18
19
20
21
22
23
24
25
:.:1 I .1..
1.00% f ''' ---....-.....
:~-- ---~I=
.. .2.00
.3.00" _.-......_.. ...._.._ ...
i-400 ,
i
.5.00 f.
I
-6.00 f.
!
.700 i. I 2006 I 2007 I
~!~.~~~ere~~l-'-~%.' .~_'--~'r~'.~~.:-_~.~_ __1
ì 2010 I
j. .. '~S:7a".d~J.
2011 i
-6.45".ì
200
'1.55"t--
200
.3.91%
639 Mi tchell, Di 20
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.
.24
25
1
2
Source: IPC IRP 2008 Update and Idaho Economic
Forecast Quarterly Detail, April 2009
http://dfm. idaho. gov /Publications/EAB/Forecast/2009/April
/ quarterlydetail table. pdf
3
4 2.Non-Far. Employment
5 A similar situation is evident in the two
6 forecasts for non-farm employment (see Figures 10 and
7 11). Figure 10 compares the two forecasts of total
8 nonfarm employment. It shows that the August 2007 load
9 forecast a steady increase in total employment to 2011.
10 The more recent DFM forecast shows a decline in
11 employment beginning in 2008 and continuing to 2010.
12 Employment is forecast to increase in 2011, but again it
13 is not expected to reach 2006 levels in the forecast
14 period. The difference between the two forecasts is even
15 more marked for employment than for personal income.
16 Figure 11 shows that the DFM forecast for total nonfarm
17 employment is 8.5% below that of the IPC August 2007 load
18 forecast. In the manufacturing sector the difference
19 rises to over 25% in 2010.
20
21 /
22
23 /
640 Mi tchell, Di 21
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.
20 /
21
22 /
23
24 /
25
1
2 Figure 10: Idaho Total Employment: IPC August 2007 and DFM April 2009
Forecasts3
4
5
700,000
6 680,000
7
660,000
8
9
~ 64,000
~j
l 620.00010
11 600,000
12
580,000
13
560,000
14
15
16
17
1S
19
2006 2007 2008 2009 2010 2011
..,Pc __OFM 200
641 Mitchell, Di 21a
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.
.
.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
1
2
Source: IPC IRP 2008 Update and Idaho Economic
Forecast Quarterly Detail, April 2009
http://dfm. idaho. gov /Publications/EAB/Forecast/200 9/April
/ quarterlydetail table. pdf
3
4
5 /
6
7 /
8
9 /
642 Mitchell, Di 22
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.
.
1 Figure 11: Percent difference Between IPC August 2007 and DFM April 2009
2 Forecasts of Total Nonfar and Manufacturing Employment: 2006-2011
3
4 10% .
5
I
i5% L.:~
0% L.. .j---
i
I
· Total nonfarm employment . Mani¡facti¡ring employment
2008 2009 2010 2011
6
7
8
9
~
-10% i
I
,
;
-15% i
15 Source: !PC IRP 2008 Update and Idaho Economic Forecast Quarerly Detail, April 2009
bI:/lsl.ida.govlPyblicatlQnsAIVF oreast/2QQ/ Ap;rillg~r1yde~tP4
10
11
i!
-20% L
I
-25% L____
-30% L______.
17 Section v: DSM and Rate Design
18
19
12
A.Current DSM Programs
A.
Q.Please provide your general understanding of
20 IPC' s current DSM programs.
13
14 2006 2007
Per its 2008 DSM Annual Report, IPC reports
22 energy efficiency and demand response program savings of
16
23 140,156 MWh of energy and 72 MW of peak load reduction in
24 2008. The bulk of energy (MWh) savings came from the
industrial sector (( 2 9%), whereas irrigation provided
643 Mi tchell, Di 23
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21
25
.
10 /
11
12
13
. 14
15
16
17
18
19
20
21
22
23
24.25
lover half of peak load reduction. Market Transformation
2 and Commercial programs both accounted for 23% of MWh
3 savings, with the residential sector and other programs
4 ( 16%)
5
6 /
7
8 /
9
644 Mitchell, Di 23a
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.
.
.
1 and irrigation (8%) accounting for the remaining savings
2 DSM programs have expanded rapidly since 2002, when only
3 17,117 MWh of savings were realized. 19
4 IPC' s DSM program categories are as follows:
5 Energy Efficiency Programs that focus on
6 reducing energy usage, usually throughout the year.
7 Demand Response Programs that are designed to
8 reduce customers' electricity loads at specific times of
9 the day and year when demands on the electricity supply
10 system are highest. IPCo offered two demand response
11 programs in 2008 (for residential customers and
12 irrigation customers) and expects to expand its DR
13 offerings to the commercial and industrial sectors in
14 2009. IPCo is also planning to extend its irrigation DR
15 program to include a dispatchable option. One of IPCo' s
16 planned C/I programs is a pilot proj ect to determine the
17 extent to which load could be reduced through cycling air
18 conditioning in the small commercial sector. A broader
19 C/I demand response program, the FlexPeak Management
20 Program, is also being introduced.20
21 Market Transfor-ation Activities: Idaho Power
22 participates in the Northwest Energy Efficiency Alliance
23 (NEEA), which aims to introduce energy efficiency
24 products into the marketplace and create a viable market
25 for them through market transformation activities.
645 Mitchell, Di 24
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.
10
11
12
13.14
15
16
17
20
21
22
23
.
1
2
3
4 /
5
6 /
7
8 /
9
18 19 Idaho Power, Demand Side Management Annual Report 2008, Appendix
4, page 95. These figures include the Oregon portion of IPCs' service19 territory.
24
20 This program is being administered by a third-party contractor.
The contractor, EnerNOC, signed a five-year contract with IP in
February 2009 to run a demand response program active in June, July
and August for large CII customers (~200 kW average billing demand.
Customers will contract directly with EnerNOC and receive capacity
and energy payments in return for reducing their load during peak
demand periods. The program's target demand reduction goals are 2 MW
in the sumer of 2009, rising to 30 MW in the summer of 2010, with an
additional 10 MW each year thereafter to 2013. Billie Jo McWinn,
Commercial Demand Response, Idaho Power, 2009 Integrated Resource
Plan Advisory Council Meeting, March 19, 2009, Slides 41-51.25
646 Mitchell, Di 24a
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1 IP also helps to foster market transformation
2 through appliance or building code modifications or
3 enforcement. 21
4 B.Secondary Winter Peak
5 As part of its DSM ini tiati ve, Idaho Power
6 offers a range of rebates or cash incentives on a space
7 heating equipment, new homes including manufactured
8 homes, and weatherization services, that appear to favor
9 electric heat. Winter peak demand is an increasingly
10 important issue in the IPC service territory. The figures
11 below show historical monthly electricity demand for 1984
12 and 2007 (MWh 000' s). There is a clear historical trend
13 toward higher use in general but particularly in the
14 summer and winter months. This is reflected in the
15 forecasts for winter and summer peak demand (Figures
16 2-3) .
17 As part of IPC' s 2009 IRP, the Commission
18 should require a detailed analysis of IPC' s secondary
19 winter peak and possible DSM acti vi ties and programs to
20 curtail its growth. This could include a review IPC' s
21 current retail tariffs to ensure that utility rate design
22 is not at cross purposes with energy efficiency
23 activities and programs. For instance, it makes no sense
24 to send price signals that promote increased consumption
25 via declining block rates and high fixed customer charges
647 Mitchell, Di 25
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15
16
17
18
19
20
21
22
23
24
25
1 while developing and implementing energy efficiency
2 programs.
3
4 /
5
6 /
7
8 /
9
10
11
12
13
14
21 Idaho Power, Demand Side Management 2008 Annual Report, March 13,
2009, page 5-9; Jude Noland, IPC Files Commercial AC Pilot; Demand
Response Program OK'd, Clearing Up, May 25, 2009, No. 1391, p. 10
648 Mitchell, Di 2Sa
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1.2
3
4
5
6 ...
7 ..
""
,.
8
9
12
13.14
15
16
17
18
19
20
21
22
23
24.25
Figure X: Peak Forecast: Historical Monthly Seasonality 1984 vs 2007
(MWh OOO's)
1984 2007
,.
,..
-......lI.. --....-
""1' 4,. . - ~ '''¡; ¡ J
.~t~~~~~w\~~W~~'\~ral~~.wJ,t~~;in~M;:-ØJ:" 'i~'§J f '\ 1. 'tA t \ r- .\!I a R R Y CJ "I 11( t:, fT \- (J l M t M J J A g nA l A V \ ~ ~ t' ~ ( u L'\ l\ :i R 'f " IN (~ J' l' , .(
. 1i.JfØnal .Aiticm Pinn.$ø..~.:'llçt:,',et1. ,f ,:lïi ,..l10
Source: Brad Snow, Sales and Load Forecast, Slide 64, 2009 Integrated Resource Plan Advisory1 J Council Meeting, October 14,2008
Figure X: Peak Forecast - Winter
Foreø!I'ted Firm J-Vilte.r Pe((.l iJI 10 proiJabi#iy
(met;llllnrrSJ
649 Mi tchell, Di 26
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1
2
c.Shrinking Forecasts of New DSM
Q.Please explain how IPC' s forecasts of new DSM
3 are shrinking.
4 A.IPC's DSM programs have expanded in recent years
5 and are forecast to continue to grow to 2029. Figure 12
19
20
21
22
23
24
25
6 shows the monthly average load for 2009 to 2029 (in red)
7 and the forecast DSM from Energy Efficiency (green). A
8 notable feature of this chart is that, "New DSM Energy
9 Efficiency" (the pale green part of the DSM data) is a
10 very small proportion of overall DSM and average monthly
11 load.
Figue 12: DSM Energy Effciency
~
12
13
14
15
16
17
18
''-
l ....
l
f iMt
I..
-
.""""""""'" ,
Source: Phil DeVol, Average Energy and Peak Hour Deficits,
Idaho Power Presentation to 2009 Integrated Resource Plan
Advisory Council Meeting, December 17, 2008, Slide 31
650 Mi tchell, Di 27
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10 /
11
12 /
13.14
15
20
.
1 In its December 17, 2008 presentation to the 2009
2 Integrated Resource Plan Advisory Council Meeting, I PCo
3 showed that it planned to increase savings from new
4 Energy Efficiency Programs from the current level of
5 about 3 aMW to about 28 aMW in 20 years time. As
6 reflected
7
8 /
9
16
17
18
19
21
22
23
24
25
651 Mi tchell, Di 27a
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1 in Figure 13, its new plan, however, shows substantially
2 reduced goals relative to the 2006 IRP (the latter plan
3 aimed for 90 aMW after 20 years). 22
4
5
Figure 13: New DSM - Energy Efficiency (aMW) 2009 VS. 2006
150
6
120
7
8 ~
:ECl
90
9 60
10 30
11 o
12 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
IRP Planning Period (2009/2006=1)
13
.2009 IRP l.2006 IRP
14 Source: Cory Read, New 2009 iRDSM Avoìded Costs, 2009 Ittegrated Resource Plan
Advìsory Councìl Meetig, December 17,2008, Slìde 12
15
16 IPC' s plan regarding savings from new Demand
17 Response programs is also interesting. A similarly
18 limi ted role for DSM is evident in the forecast of DSM' s
19 peak reduction (Figure 14).
20
21
22
23
24 22 Cory Read, New 2009 IRP DSM Avoided Costs, 2009 Integrated
Resource Plan Advisory Council Meeting, December 17, 2008, Slides
25 11-12.
652 Mi tchell, Di 28
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1
2
3
4
5
6
7
8
9
10
11
12
13
14
Figue 14: DSM - Peak Reduction..
..
..
i.
1--
l..l-
".
~
-
.""""""""""
15 Source: Phil DeVol, Average Energy and Peak Hour Deficits,
Idaho Power Presentation to 2009 Integrated Resource Plan
16 Advisory Council Meeting, December 17, 2008, Slide 41
17 In 2009, the company is planning for about 100
18 MW in new DSM savings from these programs (Figure 15).
19 This figure is expected to rise to just under 240 MW
20 after five years. At that point, however, the planned
21 savings level off and no new incremental savings are
22 included in the plan forecast for the next 15 years. 23
23
24 23 Cory Read, New 2009 IRP DSM Avoided Costs, 2009 Integrated
Resource Plan Advisory Council Meeting f December 17 f 2008, Slides
25 13-12.
653 Mi tchell, Di 29
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1
2
3
4 320
5
6 240
~:æCl
Figure 15: New DSM - Demand Response (MW
400
7
8
9 80
10
11
12
160
o
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20
IRP Planning Periöd (200.9=1)
. 2009 IRP13 Source: Cory Rea, New 2009 IR DSM Avoided Costs, 2009 Integrated Resource Plan
Advisory Council Meeti, December 17,2008, Slide 13
14
15
16
17
1.Comparison of the Peak Demand Reductions
in the 2006 IRP, 2008 IRP Update, and 2009
IRP Addendum
18 Figure 16 shows the expected case peak savings
19 from energy efficiency programs in the 2006 IPR and the
20 2008 and 2009 updates. The 2008 IRP Update showed an
21 increase over the 2006 IRP savings levels. This increase
22 was reduced in the 2009 Addendum. This is somewhat
23 surprising given the current national focus on energy
24 efficiency - the reasons for the reduction are not
25 explained in the 2009 Addendum text.
654 Mitchell, Di 30
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20
1 Figure 16: Expected Case Peak Savings from Energy
2 Efficiency: 2006 IRP and 2008 and 2009 IRP Updates
3
4 300 -_. ._.._.._...._. ....._.
!
i
~ l~_= ~-~---------
I
i
~ 150 l. .-.------.
~L
.1
5
6
7
8
9
10
11
12
50
13
14 ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~
15 2006 ..200 ..200
16
17
18 Source: 2008 Integrated Resource Plan Update, Table 8, page
21; 2008 Integrated Resource Plan Update, Appendix A, page 60;
19 Integrated Resource Plan Addendum - February 2009, Page A-24
21 Figure 17 shows the forecast peak savings from demand
22 response programs in the 2006 IRP and the 2008 and 2009
23 updates . A similar reduction between the 2008 and 2009
24 updates is evident here, although again the reasons for
25 the anticipated reduction are not clear.
655 Mi tchell, Di 31
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1 Figure 17: Expected Case Peak Savings from Demand Response: 2006 IRP, and
2 2008 and 2009 IR Updates
3
4 I~--
!
_..~------_.__.._,.._,~-..._-'"-~.-.'"-. ---.,.----____._ '-___ 0___-,..,._.._---
5
6 1-1 ~ · · · · · · · · · · · · ·
~ ~ fi-----------~-----~-I
74 L.-______..._______
" 1-'----------70 "-.-
...
7
8
9 ----_..-.~-_._....._....--,.,...-..._---_.
10
11
12
_.__..__._---_.__._-_._----....._.._.._~-_...,..._._..- ..--..'. '_.,_.~.---_.__.-----~_....,_.._.-_._--...
J
68 L13
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
14 2006 ..2008 ..2009
15 Source: 2008 Integrated Resource Plan Update, Table 8, page
21; 2008 Integrated Resource Plan Update, Appendix A, page 60;
16 Integrated Resource Plan Addendum - February 2009, Page A-24
17
1S D. Greenhouse Gas Emissions
19 Q. How could possible GHG emission reduction goals
20 increase IPC' s future DSM savings?
21 A.The Company has yet to develop quanti tati ve
22 goals for reducing greenhouse gas emissions. This issue
23 came to the fore in a recent shareholders meeting, when a
24 resolution asking IPC to adopt specific goals for
25 reducing GHGs passed with 52% of the vote. The
656 Mi tchell, Di 32
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20
21
22
23
24
25
1 resolution requests that IPC adopt such goals by
2 September 30, 2009.24
3
4 /
5
6 /
7
8 /
9
10
11
12
13
14
15
16
17
18
19
24 Rocky Barber, Historic green victory at Idaho Power annual meeting
could mean higher electric bill, IdahoStatesman.com, May 21, 2009:
http://www.idahostatesman.com/localnews/story/777839 . html
657 Mitchell, Di 32a
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1 A GHG goal could encourage the Company to
2 expand its DSM program because meeting demand, including
3 peak demand, via the construction of additional
4 conventional generation would increase emissions. IPC 's
5 current plans envision a relatively limited role for DSM.
6
7 Section VI: Loads and Resources Integration
8 Finding 3: From an integrated loads and resources basis,
9 IPC has not reasonably demonstrated that a baseload
10 generation such as Langley Gulch as II least cost-best
11 fit".
12
13 As discussed earlier in my testimony in regard to Exhibit
14 207, even under IPC' s stale load forecast, the Company
15 could most likely meet average aMW energy requirements
16 during the 2013 timeframe with network firm purchases.
17 Thus, any possible future resource constraints appear to
18 be more of a peaking nature than year-round requiring
19 base load generation. Regardless, the duration and
20 location of possible constraints need to be more fully
21 analyzed. For instance, current and forecasted monthly
22 load duration curves showing the time duration of
23 resource deficits by percentile ranges (100 - 90%; 89 -
24 75%; etc.) should be provided, with the geographic
25 location within IPC service territory of the resource
658 Mitchell, Di 33
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1 deficits identified. In addition to the seasonal
2 occurrence of a deficit, resource shortages that only
3 occur for say 20% of the time in a given month versus say
4 50-60% and 80%+, warrant different supply-side
5 strategies.
6 As discussed in Section II. of my testimony,
7 with no compelling reason to expedite the Application,
8 the Commission has the ability to more carefully consider
9 a variety of additional supply- and DSM-resource options.
10 As discussed by Dr. Reading, the Commission should
11 require an independent competitive bidding process. Also,
12 any number of DSM options should be considered. It may be
13 that IPC' s new DSM Commercial Demand Response program
14 shown on Exhibit 207 as only providing peak reductions in
15 June, July and August, could be utilized in other months
16 as well. Also, not only might there be more than the 9 or
17 10 MW of new DSM energy efficiency shown per Exhibit 207,
18 whatever the amount, it should also be shown as reducing
19 not only average energy aMW requirements but also peak MW
20 requirements as well. Further, as discussed by Dr.
21 Yankel, there are additional peaking offsets to be had
22 via IPC' s very successful Irrigation Peak Rewards
23 Program. Lastly, it appears that the Company has failed
24 to include its residential air conditioning load
25 management program in its 2009 new DSM resources.
659 Mitchell, Di 33a
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1 Recommendation 3: As part of IPCs; 2009 IRP, the
2 Commission should require IPC to present more detailed
3 information as to the location and duration of possible
4 proj ected future resource constraints.
5 This should include a more complete consideration of
6 addi tional available resources through an independently
7 administered competi ti ve solicitation process and an
8 expanded analysis of increased utilization of existing
9 DSM energy efficiency and demand response programs as
10 well as additional new DSM resources.
11
12 Section VII: Construction Work in Progress (CWIP)
13 Q.Is Construction Work in Progress (CWIP) in rate
14 base appropriate for investments in new generation?
15 A.No. CWIP is inappropriate for several reasons.
16 It is both inconsistent with competi ti ve market processes
17 and essentially blunts incentives associated with
18 integrated Resource Planning, has adverse
19 intergenerational impacts. If adopted, it reduces the
20 utili ty' s business risk, though we have not seen Idaho
21 Power volunteer for a lower return on equity or less
22 equi ty in its capital structure.
23 Q.Will you discuss how CWIP is inconsistent with
24 competitive market principles?.25 A.First, it is an artifact of monopoly regulation
660 Mi tchell, Di 34
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1 that is unavailable in the competitive business world.
2 Consider the case of, for example, a new mine. The
3 mine's customers typically do not pay for a mining
4 company to build a mine before it comes into service. The
5 mining company's investors advance the funds to build the
6 mine and the mine gets paid for the metal that the mine
7 produces once it is operating, thereby generating a
8 return for the investors. The construction workers get
9 paid, but they're paid by the mining company's
10 shareholders in advance.
11 Utili ties are similar - except that under rate
12 regulation, they have an explicit method of recovering
13 pre-construction costs over the life of the plant.
14 Standard utility ratemaking gives an allowance for funds
15 used during construction (AFUDC) which provides for
16 interest and an equity return on money tied up during
17 construction. This AFUDC is added to the direct capital
18
19 /
20
21 /
22
23 /
24
25
661 Mi tchell, Di 34a
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1 cost of the plant. Once the plant comes into service and
2 is used and useful and providing (or delivering)
3 electrici ty, all of this money (direct costs and AFUDC)
4 is recovered over the life of a plant (through
5 depreciation and a rate of return on equity and debt on
6 the undepreciated balance) .
7 IPC' s request for cash payment for both
8 interest and their return on equity capital tied up in
9 CWIP before the plant is operational thus provides cost
10 recovery that virtually no other business can achieve and
11 that would be almost impossible in an unregulated
12 setting.
13 Second, there are intergenerational issues.
14 For example, an 85-year-old customer of the Company will
15 pay proportionately far more of the cost of the new
16 powerplant with CWIP than without CWIP.
17 Q.Will you explain how including CWIP in rate
18 base essentially can distort the type of choices that are
19 typically made in an IRP process.
20 A. There are three ways in which such distortions
21 can occur. CWIP in rate base encourages utilities to
22 build power plants rather than purchasing power (by
23 removing one of the disincentives to ownership - the cash
24 flow consequences of financing a plant in-house). We are
25 concerned that when utili ties determine their resource
662 Mi tchell, Di 35
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1 plans, they may choose ownership over PPA options based
2 on relatively flimsy grounds. Assurance that the utility
3 would receive rate base treatment of CWIP before the
4 plant comes into service would make ownership even more
5 compelling to the utility.
6 The inclusion of CWIP in rate base also creates
7 a financial disincentive to energy efficiency. Again, if
8 efficiency can avoid or defer a power plant, it can avoid
9 or defer the cash flow consequences of financing the
10 plant. But if those cash flow consequences are
11 automatically covered by ratepayers with CWIP, there will
12 be even less incentive for utili ties to promote
13 efficiency and we may see even greater demands for
14 shareholder incentives.
15 CWIP in rate base also provides the greatest
16 benefits to investments in long-lead-time power
17 generation technologies (large utility central station
18 plants instead of more modular renewable and combined
19 heat and power plants with shorter lead times).
20 Q.Can you give an example of the
21 intergenerational impacts of CWIP in rate base?
22
23 /
24
25 /
663 Mitchell, Di 3Sa
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1 A.Consider, for example, an 85-year-old customer
2 of Idaho Power. Even if she survives for 10 years, she
3 will pay for about 7 years of the cost of a new
4 powerplant under normal accounting, but will pay for the
5 plant for almost ten years will pay with CWIP in rate
6 base.
7 Q.Will you discuss business risk?
8 A.One key business risk facing an electric
9 utility is the construction risk - both the risk that
10 construction projects will be on time and on budget and
11 that they can be financed over the construction period.
12 CWIP in rate base significantly reduces Idaho Power's
13 business risk associated with construction. First, it
14 removes the finance risk. Second, it reduces the
15 consequences to the utility of being late or over budget
16 because (depending on the specifics of the mechanism) it
17 may cover cost overruns and schedule slippages.
18 Therefore, while we oppose CWIP in rate base, if the
19 Commission adopts it, it should recognize this risk
20 reduction by reducing Idaho Power's return on equity or
21 the equity in its capital structure at the same time to
22 reflect the lower risk.
23 Q.What arguments are made in favor of CWIP in
24 rate base?
25 A.The general argument is that including CWIP in
664 Mitchell, Di 36
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1 rate base will improve the utility's financial condition.
2 Q Is Idaho Power facing any sort of financial
3 difficulty that would suggest that current recovery of
4 CWIP is appropriate?
5 A No, not of a permanent nature. Idaho Power's
6 stock has been selling well above book value over most of
7 the last decade and was selling above book as late as the
8 end of the fourth quarter of 2008. The current stock
9 market meltdown and credit crunch (plus a sale of over 1
10 million shares of stock in the fourth quarter of 2008)
11 took them below book value at the end of the fourth
12 quarter, although the stock price has increased somewhat
13 in recent months.
14 The relationship of the stock price to book
15 value is of key importance because issuing new stock
16 below book value will dilute the holdings of existing
17 shareholders.
18 Moreover, we can measure the stress due to
19 construction programs on the utility by examining a
20 utility's ratio of CWIP to Capitalization (or rate base
21 that earns a return). This ratio has been in
.
22
23 /
24
25 /
665 Mitchell, Di 36a
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16
1 the 8-10% range over the last several years. A new large
2 generation project could take it as high as 20%, but only
3 for a brief period of time.
4 Q.Will you generally describe Idaho Power's
5 credi t rating?
6 A.Idaho Power's bond rating is a split rating.
7 Senior secured debt is rated A- by all three agencies.
8 Unsecured debt is one notch lower at BBB+ for Moody's and
9 Fi tch and two notches down at BBB for Standard and Poors.
10 The Rating outlook is stable at S&P and negative for the
11 other two agencies. 25 The outlook downgrades in March,
12 2008 from Fitch and June 2008 from Moodys was related to
13 issues in Power Cost Recovery ratemaking coupled with
14 below-average water conditions in the Pacific Northwest
15 and a large future capital construction program.26
Q.Is there any other information in the rationale
17 for the changes in outlook by the two credit rating
18 agencies that gives you concern?
19 A.Yes. There are two concerns. First, the two
20 rating agencies considering downgrades both pointed to a
21 large future capital construction program before Idaho
22 Power allegedly made the decision to go with its own
23 "build" program instead of buying new generation. The
24 Commission should determine whether the information given.25 to the rating agencies had demonstrated that Idaho Power
666 Mitchell, Di 37
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1 had prej udged its decision regarding new generation
2 before it was announced.
3 Second, the Commission needs to determine
4 whether Idaho Power's decision to build new generation
5 factored in the financial and credit agency metrics that
6 could lead to a downgrade and also factored in its
7 request for CWIP that would require ratepayers to pay up
8 front to finance its generation, while purchased power
9 options would not require payments before generation is
10 available.
11 Q What do these financial metrics tell you in
12 broad terms?
13
14 /
15
16 /
17
18 /
19
20
21
22
23
24 25 Idacorp 10-Q for first Quarter 2009, p. 49.
25 26 Idacorp 10-Q for second Quarter 2008, pp. 46-47.
667 Mitchell, Di 37a
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1
2 A Idaho Power's long-term financial condition
3 would be improved if it could postpone its large
4 construction program in new generation. It is currently
5 selling below book value (though that condition is likely
6 to be temporary given its long history of selling above
7 book value) and the rating agencies are concerned about
8 capi tal spending. While market conditions have eased in
9 the last few months, the cost of investment grade debt
10 financing has still risen relative to both past levels
11 and rates on government bonds. If construction can be
12 postponed due to lower demand, it would be beneficial not
13 only to ratepayers but to the company and its
14 shareholders, because high interest rate debt to finance
15 a large powerplant would not be locked in for years to
16 come, creating an unwanted legacy of the current crisis.
17 Q Have any financial an analysts agreed that
18 postponing construction proj ects during the current
19 credi t crunch would have value to utili ties and their
20 regulators?
21 A Yes. In a presentation to the NARUC Winter
22 Commi ttee Meetings, 27 Bank of America and Merrill Lynch
23 of course made the usual recommendations to raise rates
24 of return due to the crisis, but also pointed out that.25 utilities need to adjust their "internal hurdle rates"
668 Mitchell, Di 38
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1 when deciding whether to make capital investments and
2 deciding which capital investments to make. More energy
3 efficiency (which does not require capital because it is
4 expensed in Idaho) and less powerplant construction would
5 be a corollary of such a strategy. At least, deferring
6 generation that is not immediately required because of
7 reduced demand would be a rational response to current
8 conditions.
9 Q.Does this conclude your prepared testimony?
10 A.Yes it does.
11
12 /
13
14 /
15
16 /
17
18
19
20
21
22
23 27 Bank of America and Merrill Lynch, "Wall Street Turmoil: Outlook
for 2009 and Implications for Utilities and Regulators," Presentation
24 to NARUC Winter Committee Meetings, February 17, 2009..25
669 Mitchell, Di 38a
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1
2 open hearing.)
(The following proceedings were had in
MR. RI CHARDSON : Than k you, Mr. Cha i rman .
4 Ms. Mitchell is available for cross-examination.
3
5
6 Ms. Nordstrom?
7
8 questions.
9
COMMISSIONER KEMPTON: Mr. Kline?
MS. NORDSTROM: Idaho Power has no
COMMISSIONER KEMPTON: Mr. Richardson.
10 You don't have ahy questions right now, right, but it is
11 a habit. Ms. Ackerman.
17
18
19
20
21
22
12
13
14
15
16
23 Thank you.
24
25 Redford.
MS. ACKERMAN: I do not, sir, thank you.
COMMISSIONER KEMPTON: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Purdy.
MR. PURDY: No questions.
COMMISSIONER KEMPTON: Mr. Miller.
MR. MILLER: No questions, thank you.
COMMISSIONER KEMPTON: Ms. Bridge.
MS. BRIDGE: No questions.
COMMISSIONER KEMPTON: Mr. Woodbury.
MR. WOODBURY: Staff has no questions.
COMMISSIONER KEMPTON: Commissioner
CSB REPORTING
[phone]
670 MITCHELL
ICIP
.
.
.
1 COMMISSIONER REDFORD: I have no
2 questions.
3 COMMISSIONER KEMPTON: Commissioner
4 Smith.
5 COMMISSIONER SMITH: No questions.
6 COMMISSIONER KEMPTON: I don't want to
7 break the trend. I have no questions.
8 MR. RI CHARDSON : And Mr. Cha i rman, I have
9 no redirect.
10 COMMISSIONER KEMPTON: You're not going to
11 break the trend either. Well, Ms. Mitchell, you may step
12 down.
13 THE WITNESS: Thank you.
14 COMMISSIONER KEMPTON: And thank you for
15 appearing and I hope that your presentation will not
16 cause you to miss your flight.
17 (The witness left the stand.)
18
19 Ms. Mitchell be excused?
MR. RICHARDSON: And Mr. Chairman, may
20 COMMISSIONER KEMPTON: Yes. The hour
21 being what it is, I think it's opportune for us to take a
22 lunch break at this time and come back at 1: 15.
23 (Noon recess.)
24
25
CSB REPORTING
[phone]
671 MITCHELL
ICIP