20090727Vol III Technical Hearing.pdf

O'RIGINAL.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
Idao PU~lic Utilities Commission
Office of the Secretary
RECEIVED
JUl 27 2009
Bo, Ida
BEFORE
COMMISSIONER JIM KEMPTON (Presiding)
COMMISSIONER MARSHA SMITH
COMMISSIONER MACK REDFORD
...'iti
PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:July 14, 2009
VOLUME III - Pages 141 - 386
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CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone] * [phone]
Email csbt§heritagewifi.com
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1 APPEARANCES
2 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. Kiine, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
RICHARDSON & 0' LEARY
by Peter J. Richardson, Esq.
Post Office Box 7218
Boise, Idaho 83702
RACINE, OLSON, NYE, BUDGE
& BAILEY
by Eric L. Oisen, 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 Miiier
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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For Idaho Irrigation
Pumpers Association:
For NIPPC:
For Snake River Alliance:
For Idaho Conservation
League:
CSB REPORTING
[phone]
APPEARANCES
1 I N D E X.2
3 WITNESS EXAMINATION BY PAGE
4 John R.Gale Mr.Kline (Direct)142( Idaho Power)Prefiled Direct Testimony 1455Prefiled Supp.Testimony 157
Prefiled Rebuttal Testimony 1646Mr.Richardson (Cross)192
Ms.Ackerman (Cross)2057Mr.Olsen (Cross)206
Mr.Purdy (Cross)2108Mr.Miller (Cross)215
Ms.Bridge (Cross)2169Mr.Woodbury (Cross)217Commissioner Redford 22710Commissioner Smith 237
Commissioner Kempton 24011Mr.Kline (Redirect)246
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Karl Bokenkamp Mr.Kline ( Direct)25113(Idaho Power)Prefiled Direct Testimony 258.Prefiled Rebuttal Testimony 27814Mr.Kline (Direct-Cont 'd)310
Mr.Richardson (Cross)31415Ms.Ackerman (Cross)330
Mr.Olsen (Cross)33116Ms.Bridge (Cross)337
Mr.Woodbury (Cross)34017Commissioner Redford 351
Commissioner Kempton 37318Mr.Kline (Redirect)379
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CSB REPORTING INDEX(208 )890-5198
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1 EXHIBITS
PAGE
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
Premarked
16 FOR THE INDUSTRIAL CUSTOMERS OF IDAHO POWER:
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3 NUMBER DESCRI PTION
17 Identified 328
20 FOR THE IDAHO IRRIGATION PUMPERS ASSOCIATION:
21 Identified 332
CSB REPORTING
Wilder, Idaho 83676
4 FOR I DAHO POWER COMPANY:
5 1. Natural Gas Price Forecast
6 2. 20 Year NPV of Revenue Requirement
7 3. Differential in 20 Year NPV of
Revenue Requirement
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4. Letter from Steven Stein to Karl
Bokenkamp, dated March 5, 2009,
wi th attachments
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8. Senate Bill No. 1123
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9. Petition for a Partial Waiver of
Competi ti ve Bidding Guidelines
13 10. Exhibit sponsored by Karl
Bokenkamp, 9 pages
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210. Load Forecasts for 2012 & 2013,
Corrected
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403. IPC' s Response to Commission
Staff's First Production Request
to Idaho Power
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EXHIBITS
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1 BOISE, IDAHO, TUESDAY, JULY 14, 2009, 1:20 P. M.
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4 COMMISSIONER KEMPTON: The hearing will
5 come to order. Mr. Kline, you were in the midst of
6 presenting witnesses and you're up.
7 MR. KLINE: Yes, Idaho Power's next
8 wi tness is Ric Gale.
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10 JOHN R. GALE,
11 produced as a witness at the instance of the Idaho Power
12 Company, having been first duly sworn, was examined and
13 testified as follows:
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15 DIRECT EXAINATION
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17 BY MR. KLINE:
18 Q Could you please state your name for the
19 record?
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A My name is John R. Gale.
Q And are you referred to as Ric Gale?
A Yes.
Q Thank you. By whom are you employed and
24 in what capacity?.25 A I'm employed by the Idaho Power Company
CSB REPORTING
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142 GALE (Di)
Idaho Power Company
1 and I'm the vice president of regulatory affairs..2 Q And are you the same John R. Gale that
3 filed direct testimony, supplemental direct testimony,
4 and rebuttal testimony in this proceeding?
5 A Yes.
No dates assigned to any of those
Thank you.
Did you also prefile any exhibits?
I believe I prefiled a petition,
Exhibi ts 8 and 9, does that sound right?.13 And those would be with both your -- that's for all three
6 Q
14 of your testimonies?
A
Q
24 same today?
7 filings?
8 A
9 Q
Yes, 8 and 9.
Thank you, and do you have any changes or
17 corrections that you want to make to any of the testimony
10 A
18 that you prefiled?
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11 Exhibit
12 Q
No.
And today if I were to ask you the same
21 questions that were posed to you in your direct
15 A
22 testimony, supplemental direct testimony and rebuttal
16 Q
23 testimony, would your answers to those questions be the
.25 A Yes, they would.
CSB REPORTING
[phone]
143 GALE (Di)
Idaho Power Company
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1 MR. KLINE: Mr. Chairman, I request that
2 Mr. Gale's testimony, direct, supplemental direct, and
3 rebuttal testimony, be spread on the record as if read
4 and that Exhibits 8 and 9 be marked for identification.
5 COMMISSIONER KEMPTON: If there's no
6 objection, so ordered.
7 (The following prefiled direct,
8 supplemental, and rebuttal testimony of Mr. John R. Gale
9 is spread upon the record.)
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CSB REPORTING
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144 GALE (Di)
Idaho Power Company
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1 Q.Please state your name and business address.
2 A.My name is John R. Gale and my business address
3 is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what
5 capacity?
6 A.I am employed by Idaho Power Company ("the
7 Company") as the Vice President of Regulatory Affairs.
8 Q.Please describe your educational background and
9 business affiliations.
10 A.I received a BBA in 1975 and an MBA in 1981
11 from Boise State University. I maintain a close
12 affiliation with the uni versi ty and serve on the College
13 of Business and Economics' Advisory Council and on the
14 Board of Directors of the Alumni Association. I have
15 also attended the Public Utili ties Executive Course at
16 the University of Idaho and am now on the faculty of that
17 program covering "Regulation and Ratemaking."
18 I am an active member of the Edison Electric
19 Institute's Rates and Regulatory Affairs Committee, which
20 is the committee that is concerned primarily with
21 regulatory issues and ratemaking methods. I am the
22 current Chair of this committee.
23 Q.Please describe your work experience.
24 A.From 1976 to 1983, I was employed by the
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145 GALE, DI 1
Idaho Power Company
.1 State of Idaho primarily as an analyst in the Department
2 of Employment. In October 1983, I accepted a position at
3 Idaho Power Company as a Rate Analyst in the Rate
4 Department. I initially worked on rate design, tariff
5 administration, and line extension issues. In March
6 1990, I was assigned to the Company's Meridian District
7 Office where I held the position of Meridian Manager,
8 which was a one-year cross training position established
9 to provide corporate employees with an extensive field
10 experience. I returned to the Rate Department in March
11 1991 and in June, I was promoted to Manager of Rates. In
12 July 1997, I was named General Manager of Pricing and.13 Regulatory Services. In March 2001, I was promoted to
14 Vice President of Regulatory Affairs, my current
15 position.
16 As Vice President of Regulatory Affairs, I
17 oversee and direct the acti vi ties of the Pricing and
18 Regulatory Services Department. These activities include
19 the development of jurisdictional revenue requirements,
20 the oversight of the Company's rate adjustment
21 mechanisms, the preparation of class cost-of-service
22 studies, the preparation of rate design analyses, and the
23 administration of tariffs and customer contracts. In my
24 current position, I have the primary responsibility for.25 policy matters related to the economic regulation of
Idaho Power Company.
146 GALE, DI 2
Idaho Power Company
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1 I have testified frequently before the Idaho Public
2 Utilities Commission ("the Commission") on a variety of
3 rate and regulatory matters. I have also testified
4 before or submitted direct testimony to the regulatory
5 commissions in Nevada and Oregon, the Federal Energy
6 Regulatory Commission (" FERC"), the Bonneville Power
7 Administration, and the United States Senate Committee on
8 Energy and Natural Resources.
9 Q.What it the purpose of your testimony in this
10 matter?
11 A.I will briefly describe the new generating
12 resource for which the Company is seeking a Certificate
13 of Public Convenience and Necessity ("CPCN"). I will
14 discuss certain regulatory alternatives that are
15 available to the Commission that, if authorized, would
16 assist the Company in obtaining the necessary financing
17 for the new resource. Finally, I will propose the
18 specific ratemaking treatment sought by the Company as
19 part of its CPCN request.
20 THE PROJECT
21 Q.Please generally describe the new resource.
22 A.The resource project is a gas-fired, combined
23 cycle combustion turbine power plant that would be
24 constructed, owned, operated, and maintained by Idaho.25 Power. Idaho Power plans to construct and operate the
147 GALE, DI 3
Idaho Power Company
1 approximately 330 MW plant and associated facilities in.2 Payette County, Idaho. The name of the new resource is
3 Langley Gulch Power Plant ("Langley Gulch" or "The
4 Proj ect ") .
5 The Proj ect is split into two categories: (1)
6 the power island and (2) the other support facilities.
7 The major components of the plant's power island include
8 a gas turbine generator, a heat recovery steam generator,
9 a steam turbine, and steam surface condenser. Other
10 support facilities will include a warehouse, office, and
11 operation control buildings to support the plant. The
12 Langley Gulch plant will be water-cooled using secured
.13 surface water rights on the Snake River.
14 Q.What is the planned schedule for construction
15 and commercial operation of the Proj ect?
16 A.With the Commission's approval of the CPCN,
17 construction of the Langley Gulch Power Plant will begin
18 in the summer of 2010. The Proj ect is scheduled to be
19 commercially operational by December 2012. To support
20 this schedule, most permits will need to be secured by
21 the spring of 2010.
22 Q.What transmission facilities need to be
23 constructed to interconnect the Langley Gulch Project
24 with the rest of the Idaho Power system?.25
148 GALE, DI 4
Idaho Power Company
1 A.There are two segments of transmission line.2 construction that are necessary to integrate the Project
3 with the Idaho Power system. One piece is 2.5 miles of
4 new double circuit 230-kV transmission line that will
5 cross Bureau of Land Management lands to connect to the
6 existing Ontario-Caldwell transmission line. The second
7 section is approximately 18 miles of new 138-kV
8 transmission line to be constructed along public
9 right-of-way to connect to the Caldwell-Willis line.
10 REGULTORY CONSIDERATIONS
11 Q.The Company has filed for CPCNs for several
12 peaking facilities over the last decade, including
.13 Evander Andrews units 2 and 3 in 2001, Bennett Mountain
14 in 2003, and Evander Andrews 1 in 2006. How is this
15 request different than those filings?
16 A.All of the proj ects mentioned were simple cycle
17 combustion turbine peaking plants, which are smaller in
18 size, significantly less capital intensive, and much
19 quicker to construct. Because of these characteristics,
20 peaking plants do not present the same type of regulatory
21 and financing risks that a combined cycle combustion
22 turbine proj ect like Langley Gulch does . Additionally,
23 the turmoil in today's capital markets creates a
24 different financing environment than what was present.25 when the
149 GALE, DI 5
Idaho Power Company
1 previous CPCN applications were before this Commission..2 Company Witness Ms. Lori Smith discusses the challenge of
3 financing major capital projects in the present economic
4 and financial environment in her testimony.
5 Q.Gi ven the differences between Langley Gulch and
6 the peaking units previously described, is Idaho Power
7 proposing any regulatory or ratemaking changes to its
8 CPCN request that can make this proj ect more attractive
9 to the financial community?
10 A.We are proposing two regulatory alternatives
11 for the Commission's consideration. Both alternatives
12 build from traditional CPCN filings that include the.13 establishment of the need for the resource, the resource
14 selection process, construction timelines, capacity and
15 operating characteristics, and firm commitment estimates
16 for both the power supply and transmission components of
17 the proposed resource. In this filing, the Company is
18 asking the Commission to also consider either (1) a
19 ratemaking order that would permit all or a portion of
20 the Construction Work in Progress ("CWIP") the Company
21 incurs as it constructs the Project to be included in
22 current rates on an annual basis or (2) to assertively
23 state in the CPCN Order how the Commission intends to
24 treat the.25
150 GALE, DI 6
Idaho Power Company
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1 Company's investment in Langley Gulch for ratemaking
2 purposes at the time Langley Gulch goes into service.
3 Q.Please describe the CWIP al ternati ve you
4 propose.
5 A.Utilizing this alternative, the Company would
6 submi t annual filings to the Commission following the
7 close of each year - potentially on or before March 1.
8 The Commission could audit the Company's filing and
9 authorize the Company to include its investment costs in
10 rates at the time of the annual Power Cost Adjustment
11 rate change (or some other date of its choosing).
12 Utilization of this approach would allow Staff three
13 months to audit the cost information and would implement
14 rate changes in a non-disruptive manner. To alleviate
15 potential concerns regarding the prudency of
16 expenditures, in addition to the ability to audit, the
17 Commission could also limit CWIP recovery to a percentage
18 of booked and audited costs. In the final year, the
19 accumulated plant in service would be evaluated against
20 the Company's Commitment Estimate in the same manner as
21 other projects I cited earlier in my testimony that were
22 constructed under the CPCN process.
23 Q.How would the inclusion of annual CWIP
24 amounts into rates reduce the cost of financing the
25 Project?
151 GALE, DI 7
Idaho Power Company
1 A.As Ms. Smith notes in her testimony in this.2 proceeding, current financing conditions are extremely
3 difficul t. Issuing large amounts of equity at this time
4 is simply not prudent. The authorization of CWIP for
5 this proj ect would provide a strong signal of regulatory
6 support for capital projects to the financial community
7 and provide increased cash flow throughout the
8 construction of the proj ect, thus decreasing the need for
9 equi ty issuances.
10 Q.Turning to the second regulatory al ternati ve
11 you described earlier. How would the inclusion of
12 specific ratemaking determinations in the CPCN order be.13 helpful in financing the Proj ect?
14 A. A Commission order that adds certainty to the
15 ratemaking treatment the Company could expect to receive
16 if it proceeds with the Langley Gulch Power Plant would,
17 in the Company's opinion, enhances its ability to obtain
18 financing. This type of ratemaking commitment is
19 currently being discussed in the Idaho Legislature in
20 Senate Bill 1123. A CPCN Order that would provide the
21 needed certainty would include language specifying that
22 the Commission:(1) concurred with the need for the
23 resource in the size and time frame stated in the
24 application; (2) accepted the Commitment Estimate for.25 total Project cost, including both the power supply and
transmission segments;
152 GALE, DI 8
Idaho Power Company
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1 (3) stated that costs incurred in an amount up to the
2 Commi tment Estimate could be deemed to be reasonable and
3 prudent subj ect to a "soft cap"; (4) stated that at the
4 time the Proj ect was closed to plant and placed in rate
5 base and cost recovery could begin at the time Langley
6 Gulch begins full commercial operations; and (5) stated
7 that the return on equity the Company could expect to
8 earn on the Project investment would be the authorized
9 rate in effect at the time the Proj ect is placed ~n
10 service.
11 Q.Please clarify what you mean by the term "soft
12 cap."
13 A. A soft cap when applied to a Commitment
14 Estimate means that the Company could be assured that
15 amounts incurred up to the Commitment Estimate amount
16 would be determined to be prudent. Should the cost of
17 the Project be less than the Commitment Estimate, the
18 savings would directly benefit the customer through a
19 lower amount in rate base. On the other hand, should the
20 project come in over the Commitment Estimate, amounts
21 above the Commitment Estimate would have to be justified
22 before the Commission and mayor may not be determined as
23 prudently incurred.
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153 GALE, DI 9
Idaho Power Company
1 Q.Does this Commission have the ability to bind.2 future Commissions to the degree that you are requesting?
3 A.No. However, as a practical matter given the
4 construction time frame for the Langley Gulch project, it
5 is likely that all or most of the current Commissioners
6 will be serving at the time the Proj ect becomes
7 commercial. Addi tionally, if during the pendency of this
8 proceeding the Commission should obtain the legal
9 authori ty to issue orders that would commit future
10 Commissions to the ratemaking determinations made by this
11 Commission, it would be the Company's intent to file an
12 amended request seeking such a commitment.
.13 RATEMING REQUEST
14 Q.After considering the application of the
15 regulatory alternatives just described, what is the
16 Company asking the Commission to include in its Langley
17 Gulch CPCN order?
18 A.Idaho Power believes that the results of the
19 RFP clearly demonstrate that the Langley Gulch Project
20 represents an opportunity for its customers to obtain a
21 very cost-effective resource. To take advantage of that
22 opportunity, the Company is asking the Commission to
23 include ordering language that will enhance the Company's
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154 GALE, DI 10
Idaho Power Company
1 chances to obtain financing for the Proj ect..2 Specifically, Idaho Power requests that the Commission
3 find that:
4 (1) The construction of the Langley Gulch
5 Power Plant is consistent with Idaho Power's resource
6 plans and is an appropriate resource to supplement and
7 support the Idaho Power system and its customers.
8 (2) The December 2012 on-line date is
9 consistent with Idaho Power's resource plans and the
10 anticipated load requirements of Idaho Power's retail
11 customers.
12 (3) The approved total Commitment Estimate is.13 $427,400,000, which includes the power plant and the two
14 transmission projects described previously in my
15 testimony related to the Ontario-Caldwell connection and
16 the Caldwell-Willis connection.
17 (4) The Commitment Estimate is subj ect to a
18 soft cap that provides retail customers with the full
19 benefit of the Project being completed under the
20 Commitment Estimate, while providing the Company with an
21 opportunity to justify any costs above the Commitment
22 Estimate as prudent should that be the case.
23 (5) The Company can recover prudently incurred
24 costs for fuel, fuel storage, and fuel.25
155 GALE, DIll
Idaho Power Company
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1 transportation through the Company's existing Power Cost
2 Adjustment mechanism.
3 (6) The Company can include in rates through
4 annual ratemaking adjustments of booked and audited CWIP
5 investment with a final reconciliation at the time of
6 commercial operation or, in the alternative;
7 (7) The Company can expect to include in rates
8 at the time of commercial operation the specific
9 ratemaking determinations I described previously in my
10 testimony.
11 Q.Can Idaho Power assure this Commission that if
12 the Commission authorizes either of the alternatives
13 requested, that the Company has the ability to finance
14 the Proj ect?
15 A.No it cannot. Providing the regulatory
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assurances would give Idaho Power a better chance to
obtain financing, but in today's environment, we simply
do not know if it can be done. The Company will be
reviewing its financing al ternati ves for the Proj ect
throughout this spring and, if necessary, may supplement
or amend this request based on its findings.
Q. Does this conclude your testimony?
A. Yes, it does.
156 GALE, DI 12
Idaho Power Company
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1 Q.Please state your name and business address.
2 A.My name is John R. Gale and my business address
3 is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company ("the
6 Company") as the Vice President of Regulatory Affairs.
7 Q.Have you previously submitted direct testimony
8 in this docket?
9 A.Yes, I submitted direct testimony addressing
10 the ratemaking and regulatory matters associated with
11 Idaho Power's March 6, 2009, filing for a Certificate of
12 Public Convenience and Necessity ("CPCN") for the Langley
13 Gulch Power Plant ("Langley Gulch" or "the Proj ect") .
14 Q.What is the purpose of your supplemental
15 testimony in this matter?
16 A.I will provide an update to the status of Idaho
17 legislation previously discussed in my direct testimony
18 and describe the relationship of that legislation to the
19 Company's ratemaking request. I will also specify Idaho
20 Power's preference between the two ratemaking
21 alternatives.
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157 GALE, SUPP DI 1
Idaho Power Company
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1 Q.What is the status of the legislation
2 designated as Senate Bill 1123?
3 A.Senate Bill 1123 was signed into law on April
4 9, 2009, and will become effective on July 1, 2009, as
5 Idaho Code § 61-541. For the convenience of the
6 Commission's review, I have included a copy of the
7 enacted legislation as Exhibit No. 8 to my testimony.
8 This law provides a public utility with the ability to
9 file an application with the Commission for an order
10 specifying in advance the ratemaking treatments that
11 shall apply when the costs of the proposed facility are
12 included in the utility's revenue requirement for
13 ratemaking purposes.
14 Q. To obtain the benefits of Senate Bill 1123,
15 what does a utility need to include in its Application to
16 the Commission?
17 A.The utility requesting advanced ratemaking
18 determinations must provide a description of the proposed
19 proj ect; how the utility plans to address the risks
20 associated with the project; the proposed date of lease,
21 purchase, or commencement of construction; the proposed
22 cost recovery; and any proposed ratemaking treatments.
Q.Has Idaho Power addressed these requirements in
24 its Application and supporting testimony?.25 A.Yes~
158 GALE, SUPP DI 2
Idaho Power Company
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1 Q.Does Senate Bill 1123 require the Commission to
2 make certain determinations regarding Idaho Power's
3 acti vi ties as a regulated utility?
4 A.The law provides that the Commission will
5 determine whether:(1) the utility has a
6 Commission-accepted integrated resource plan in effect,
7 (2) the proj ect is in the public interest, (3) the
8 utili ty has considered other resources, (4) the proj ect
9 is reasonable compared to other resource options such as
10 energy efficiency, demand-side management, and other
11 al ternati ve sources of supply or transmission, and (5)
12 the utility participates in regional transmission
13 planning.
14 Q.Based upon the information the Company has
15 presented in this case, will the Commission be able to
16 make these determinations with regard to Idaho Power?
17 A.Yes.
18 Q.With the enactment of Senate Bill 1123, does
19 Idaho Power wish to supplement and clarify its requested
20 ratemaking treatment of Langley Gulch?
A.Yes. Although my initially filed direct
22 testimony addresses most of these items specifically, the
23 Company requests that the Commission issue its order
24 finding:.25
159 GALE, SUPP DI 3
Idaho Power Company
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1 1.The return on equity ("ROE") authorized
2 for Langley Gulch will be the same as the ROE authorized
3 for the rest of the Company's rate base when Langley
4 Gulch achieves commercial operation and that the ROE for
5 Langley Gulch will change with Commission-authorized
6 changes to the Company's ROE over the life of the
7 Project.
8 2.The depreciation life for the Proj ect is
9 35 years asset deprecation for the production plant and
10 45 years asset depreciation for the transmission plant.
11 3.The construction of the Langley Gulch
12 Power Plant is consistent with Idaho Power's resource
13 plans and is an appropriate resource to supplement the
14 Idaho Power system.
4.The December 2012 on-line date is
16 consistent with Idaho Power's resource plans and the
17 anticipated load requirements of Idaho Power's retail
18 customers.
19 5.The approved total Commitment Estimate is
20 $427,366,729, which includes the power plant and the two
21 transmission interconnection proj ects described
22 previously in my testimony related to the
23 Ontario-Caldwell connection and the Caldwell-Willis
24 connection..25 6.The Commitment Estimate is subject to a
160 GALE, SUPP DI 4
Idaho Power Company
1 soft cap that provides retail customers with the full.2 benefi t of the Proj ect being completed under the
3 Commitment Estimate, while providing the Company with an
4 opportunity to justify any costs above the Commitment
5 Estimate as prudent should that be the case.
6 7.The Company can expect to include in its
7 rates, at the time of commercial operation, the specific
8 ratemaking determinations I described previously in my
9 testimony.
10 Q.With the enactment of Senate Bill 1123, both
11 ratemaking alternatives put forth by Idaho Power in its
12 ini tial direct testimony are legally available to the
.13 Commission to incorporate into the final CPCN order.
14 Does Idaho Power have a stated preference between the
15 alternatives?
16 A.Before indicating a preference, there are two
17 points to call to the Commission's attention. First, the
18 two alternatives can work together, if the Commission
19 desires, and, second, a stated Company preference will
20 likely change with the circumstances present for both
21 Idaho Power and its customers.
22 Q.How would the two alternatives work together?
23 A.The Commission could order the ratemaking
24 treatment provided under the Senate Bill 1123 and either.25
161 GALE, SUPP DI 5
Idaho Power Company
1 prospectively (as part of this proceeding) or.2 subsequently (in future proceedings) authorize inclusion
3 of Construction Work in Progress ( "CWIP") associated with
4 the Proj ect investment into rates. The Commission could
5 also apply CWIP to all or a portion of the Langley Gulch
6 investment.
7 Q.What circumstances might influence a decision
8 regarding the preferred ratemaking al ternati ve.
9 A.The Company's cash flow requirements need to be
10 balanced against the state of the southern Idaho economy
11 and rate pressure on customers to recover other Company
12 costs. CWIP provides increased cash flow to fund
.13 operations and new construction, while smoothing rate
14 changes. However, CWIP also increases rate pressure in
15 the short term.
16 Q.What is the preferred alternative under current
1 7 circumstances?
18 A.Given the current economic situation in the
19 service territory and rate demands created by costs other
20 than the Langley Gulch project, including a significant
21 Power Cost Adjustment presently before the Commission,
22 the Company prefers that the Commission issues an Order
23 under the provisions of Senate Bill 1123. However , it is
24 important to recognize that these are very unsettled.25 times in the economy and the capital markets and raising
162 GALE, SUPP DI 6
Idaho Power Company
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1 capi tal in this scale is currently very problematic.
2 There is no guaranty the Company will be able to attract
3 this amount of capital under reasonable terms in the
4 current environment using anyone methodology.
5 Therefore, including CWIP in rate base must remain an
6 option for the future.
7 Q.Does this conclude your testimony?
8 A.Yes, it does.
9
163 GALE, SUPP DI 7
Idaho Power Company
.
.
1 Q.Please state your name and business address.
2 A.My name is John R. Gale and my business address
3 is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company ("Idaho
6 Power" or "the Company") as the Vice President of
7 Regulatory Affairs.
8 Q .Have you previously submitted direct testimony
9 in this docket?
10 A.Yes. I submitted direct testimony addressing
11 the ratemaking and regulatory matters associated with
12 Idaho Power's March 6, 2009, filing for a Certificate of
13 Public Convenience and Necessity for the Langley Gulch
14 power plant ("Langley Gulch" or "the Proj ect"). I also
15 submi tted supplemental direct testimony in this same
16 docket on April 28, 2009.
17
18
Q.What is the scope of your rebuttal testimony?
A.My testimony rebuts statements made and/or
19 positions taken by Community Action Partnership
20 Association of Idaho ("CAPAI") witness Terri Ottens,
21 Industrial Customers of Idaho Power ("ICIP") witness
22 Cynthia Mitchell, Northwest & Independent Power Producers
23 Coalition ("NIPPC")
24.25 /
164 GALE, DI REB 1
Idaho Power Company
.
.
1 wi tness Don Reading, and Idaho Public Utilities
2 Commission ("the Commission") Staff witness Rick
3 Sterling.4 CAAI
5 Q. On page 4 of her testimony, Ms. Ottens states
6 that "a regulatory public utility should, among other
7 things, make every attempt to pursue least cost
8 al ternati ves, best sui ted to meet the needs in question,
9 when it does acquire new resources, thereby minimizing
10 increases to rates." From the Company's perspective,
11 what are the "other things"?
12 A.The Company's stated goals in resource planning
13 are (1) to identify sufficient resources to reliably
14 serve the growing demand for energy wi thin the Company's
15 service area and (2) to balance costs, risks, and
16 environmental concerns. Selected resources need to
17 provide economic solutions reliably and in an
18 environmentally responsible way.
19 Q.On page 6 of her testimony, Ms. Ottens states,
20 "With an estimated cost of $247 million, Langley Gulch
21 will constitute approximately one-fourth of Idaho Power's
22 entire rate base." Is this an accurate statement?
23 A.No, it contains two factual errors. First, the
24 cost, in terms of the Commitment Estimate proposed by the.25 Company, is $427 million, including the transmission
165 GALE, DI REB 2
Idaho Power Company
.1 portion. Second, even at this higher amount, the Proj ect
2 will represent less than 20 percent of Company rate base
3 as determined in our last general rate case order. More
4 importantly, I think Ms. Ottens is saying that Langley
5 Gulch is a big investment that will have a significant
6 rate impact. I agree. However, the larger issue is that
7 whatever Idaho Power does to serve load in the next five
8 years is going to have a significant rate impact. Simply
9 doing nothing will not avoid additional costs and may
10 very well impact reliability and quality of service.11 ICIP
12 Q.Ms. Mitchell states on page three of her
13 testimony that the Langley Gulch in-service date has.14 slipped to December 2013 and accordingly the Company has
15 given the Commission an additional six months to review
16 its Application. Is December 2013 the in-service date?
17 A.No. The in-service date for Langley Gulch is
18 December 2012. As described in Mr. Vern Porter's
19 rebuttal testimony, the Company believes it is in its
20 customers' best interest to have Langley Gulch available
21 in the summer of 2012 and is actually pursuing a strategy
22 to make that happen. The strategy will include an
23 incentive payment, which I would urge the Commission to
24 include in.25
166 GALE, DI REB 3
Idaho Power Company
1 its final determination of the Company's Commitment.2 Estimate.
3 Q.On pages 5 and 6 of her testimony, Ms. Mitchell
4 lists a number of items that suggest that the Proj ect
5 might be delayed without a reliability consequence, such
6 as the contract load at Hoku not materializing and
7 addi tional demand-side resources appearing. Are there
8 other dynamics that counter these speculative assertions?
9 A.Yes. One important development not mentioned
10 is the delay from 2012 to 2015 in the anticipated
11 completion of the 500 kilovolt Boardman to Hemmingway
12 transmission project, which would open up access to
.13 resources from the west. With this transmission option
14 unavailable in 2012, it is even more important to have
15 additional generation in place by then. The other wild
16 card in planning for the future is the emergence of new
17 large loads in our service area. These potential new
18 loads are being attracted by the lowest industrial rates
19 offered by investor-owned utili ties in the nation and are
20 being actively recruited by Idaho cities, economic
21 developers, and other local agencies eager to get the
22 Idaho economy revived.
23
24 /.25
167 GALE, DI REB 4
Idaho Power Company
1 Q.Ms. Mitchell describes an emerging winter peak.2 for Idaho Power on page 6 of her testimony. Please
3 comment on her discovery.
4 A.Actually, Idaho Power has a history of being
5 dual peaking, which was more pronounced in the past than
6 it is today. However, continued irrigation operations,
7 increased air conditioning load, and a high natural gas
8 penetration for space heat have resulted in the summer
9 peak growing faster than the winter peak. Company
10 witness Michael Mace discusses in detail the nature and
11 history of the Company i s peak periods in his testimony.
12 Q.Continuing her discussion on Idaho Power's.13 secondary winter peak on page 25 of her testimony, Ms.
14 Mi tchell recommends a review of the Company's current
15 retail tariffs to "ensure that rate design is not at
16 cross purposes with energy efficiency activities and
17 programs. " What does Idaho Power presently do to ensure
18 this result?
19 A.On an ongoing and regular basis, management
20 from wi thin the Pricing and Regulatory Department (where
21 rates are designed) and from the Customer Relations and
22 Energy Efficiency Department (where programs are
23 developed) meet and discuss current issues and
24 developments in each of their respective areas..25 Development of new energy efficiency and demand response
programs, as well as new
168 GALE, DI REB 5
Idaho Power Company
.1 proposed rate design and regulatory issues, are discussed
2 and coordinated.
3 As stated in my direct testimony in the
4 Company's last general rate case (Gale Direct,
5 IPC-E-08-10), the Company is committed to providing
6 customers cost-based price signals which encourage the
7 wise and efficient use of energy and has designed rates
8 in such a manner. Idaho Power's goal is to design rates
9 reflecting the relative cost to operate the system.
10 Customers can then use this pricing information to alter
11 their discretionary patterns of usage, increasing
12 efficiency and lowering the overall cost of energy to the.13 system.
14 To implement this goal, Idaho Power proposed,
15 and the Commission approved, inclining block rates for
16 residential and small commercial customers, mandatory
17 time-of-use rates for large general and large power
18 customers, and load-factor pricing for irrigation
19 customers. These rate designs send seasonally
20 differentiated cost-based price signals to our customers
21 and provide specific opportunities for customers to
22 benefi t through energy efficiency acti vi ties.
23 Q.For the irrigation class, does a load-factor
24 energy pricing rate design interfere with or become.25 counter-productive to the goals of either the Company 's
169 GALE, DI REB 6
Idaho Power Company
.1 Irrigation Efficiency Rewards Program or the Irrigation
2 Peak Rewards Program?
3 A.No. Participants in the Irrigation Efficiency
4 Rewards Program receive rewards to improve the energy
5 efficiency of their existing irrigation systems or their
6 installation choices for new systems. The right-sizing
7 of equipment encouraged by this program should enhance
8 the customer's load factor. Therefore, load-factor
9 energy pricing has the potential to provide a second set
10 of benefits to the participants in the Irrigation
11 Efficiency Rewards Program.
12 The Irrigation Peak Rewards Program provides.13 economic credits to customers who allow the Company to
14 turn off specific irrigation equipment on a dispatchable
15 basis. Participants in this program generally shift
16 their usage to another time period. Therefore,
17 load-factor energy pricing should not make any
18 significant changes to their monthly load factor.
19 Q.Does the Company anticipate continuing actively
20 proposing new rate design?
21 A.Yes. In 2008, Idaho Power commissioned Dr.
22 Ahmad Faruqui, a nationally recognized expert in the
23 field of dynamic rate design to develop a white paper
24 entitled "Transitioning to ¡nnovative Rates at Idaho.25 Power:
170 GALE, DI REB 7
Idaho Power Company
.
.
1 Pathways to the Future. II Idaho Power continues to work
2 wi th Dr. Faruqui in developing new rate design. Since
3 2005, Idaho Power has successfully operated a Critical
4 Peak Pricing program in the Emmett Valley with customers
5 who piloted the Company's Advanced Metering
6 Infrastructure ("AMI ") system. Wi th the full
7 implementation of the AMI system, which is in its first
8 year of a three-year system-wide rollout, and with the
9 implementation of billing and data management systems to
10 manage the AMI data, Idaho Power's intent is to offer
11 additional programs, including dynamic pricing, for
12 customers in all rate classes.
13 Q. Does the Company have other pricing structures
14 that are supportive of the Company's energy efficiency
15 programs?
16 A.Yes. In Case No. IPC-E-04-15, the Company
17 proposed, and the Commission approved, a three-year pilot
18 of a Fixed Cost Adjustment ("FCA") mechanism for its
19 residential and small general service customers. The FCA
20 annually adjusts rates up or down to recover the
21 difference between the fixed costs authorized by the
22 Commission in the most recent rate case and the fixed
23 costs the utility actually recovers from customers during
24 the previous year. In this way, any financial.25 disincentive to the utility investment in energy
efficiency programs is removed.
171 GALE, DI REB 8
Idaho Power Company
1
3
Q.On page 32 of her direct testimony,Ms.
Mitchell discusses a shareholders'resolution regarding
Company planning for greenhouse gas ("GHG")reductions
and its relationship to demand-side management ( II DSM" )
programming.Please comment.
.2
4
5
6 A.Both prior to and after the shareholder
7 resolution vote, the Company has repeatedly been on the
8 record both in word and deed as completely supportive of
9 pursuing cost-effective energy efficiency, demand
10 response measures, and renewable resources. The
11 Commission and customer groups are aware of the expedited
12 ramp-up of these programs, resources, funding, and
.13 results. Absent the removal of the "cost-effective II
14 criterion, there is no GHG plan that would have Idaho
15 Power do more than it is already committed to do to
16 further DSM initiatives. Likewise, our commitment has to
17 stay in step with the public policy determinations of the
18 Commission.
19 In the final analysis, our energy future
20 requires ongoing energy efficiency, renewable resources,
21 and the Langley Gulch production plant.
22 Q.On page 34, Ms. Mitchell states that CWIP is
23 "an artifact of monopoly regulation that is unavailable
24 in the competitive business world." Do you agree with.25 her conclusion?
1 72 GALE, DI REB 9
Idaho Power Company
.1 A.No. In the real world customers sometimes make
2 prepayments to new production ventures for product that
3 will be received in the future. These payments can
4 become an important source of financing, which can enable
5 a company to build facilities to produce the product. In
6 Idaho Power's own service terri tory, it has seen Hoku
7 Materials use this method to finance facilities.
8 Q.Ms. Mitchell testifies that including CWIP in
9 rate base distorts the resource selection process in
10 three ways:(1) by encouraging utili ties to build power
11 plants rather than purchasing power, (2) by creating a
12 financial disincentive for energy efficiency , and (3).13
14
providing benefits to generation technologies with long
lead times. Do you see the same distortions to the
15 resource selection process used in Idaho Power's
16 Integrated Resource Plan ("IRP")?
17 A.I do not. First of all, I would think that
18 most industrial customers really want to optimize the
19 economic and reliability aspects of a resource selection
20 and would be indifferent to the buy versus build
21 decision. The Idaho Power IRP is indifferent to this
22 decision and does not make such a distinction when
23 selecting the resource portfolios. Those distinctions
24 come in the actual acquisition process, as there are some.25 resources that the
173 GALE, DI REB 10
Idaho Power Company
.1 Company has traditionally filled exclusively through
2 power purchase agreements, while others have included a
3 self-build option among the possibilities.
4 The inclusion of Construction Work in Progress
5 ("CWIP") can help finance a self-build option, thus
6 adding some discipline to a competi ti ve bidding process;
7 however, it is not a factor in the resource selection.
8 The reverse situation might be argued when the inability
9 to put CWIP into rate base takes a self-build option off
10 the table because of financing difficulties.
11 Q.Do you believe that CWIP is a financial
12 disincenti ve to energy efficiency?
13 A.Idaho Power, along with others, has given much.14 thought to the appropriate regulatory model for energy
15 efficiency. We have pursued ongoing recovery of energy
16 efficiency expenditures via a tariff rider, which
17 typically provides timely cash flow to the utility to
18 finance demand-side measures. Since these measures are
19 financed on the front end, while benefits are enjoyed
20 over the life of the measures, I would argue it is the
21 equivalent of CWIP recovery for supply-side investments
22 rather than a disincentive.
23 Many parties, including the ICIP, have
24 investigated the financial disincentives to energy.25 efficiency through a
.
174 GALE, DI REB 11
Idaho Power Company
.
.
1 fairly exhaustive process resulting in the current Fixed
2 Cost Adj ustment pilot previously discussed. Thus far,
3 the ICIP has expressed a preference to be excluded from
4 the FCA pilot. As I previously stated, the Company is
5 fully committed to the pursuit of all cost-effective
6 energy efficiency and demand response programs. The
7 inclusion or exclusion of CWIP in generation rate base
8 will not have a bearing on this commitment.
9 Q.Does the inclusion of CWIP in rate base create
10 a bias toward long-lead-time resources?
11 A.No. CWIP availability does not create a bias
12 toward long lead-time assets for the same reasons as it
13 does not favor Company-built options. Again, the reverse
14 is more likely; CWIP can help the financial viability of
15 a long-lead-time Company-built option, which should make
16 for a better resource decision.
17 Q.Please respond to Ms. Mitchell's concern of an
18 intergenerational impact of CWIP.
19 A.Ratemaking is rife with impacts that in
20 isolation appear to be unfair. In Ms. Mitchell's
21 example, a senior citizen starts paying for a resource
22 before it begins operating and may not live long enough
23 to fully enjoy its benefits. In isolation, it is
24 factually true. We have the similar generational.25 mismatch with our funding
175 GALE, DI REB 12
Idaho Power Company
.1 of demand-side resources - early payment through the
2 Energy Efficiency Rider with longer-lived benefits over
3 the life of the DSM measure. A generational dynamic in
4 the opposite direction is developing in the proposed
5 approaches to addressing carbon concerns, where it is
6 very likely that future customers are going to have to
7 bear the cost of existing carbon-intensive resources.
8 "Gold Medallion" homes and irrigation were once incented
9 and now are a cost concern. New industrial load raises
10 the costs of existing industrial customers. Bonneville
11 Power Administration Residential Exchange program
12 distributes residential and small farm credits during.13 some periods and withholds them in others, often
14 depending on the latest court ruling. The list goes on
15 and on. The bottom line is the Commission will have to
16 determine whether it is good public policy to allow all
17 or some CWIP into rates. On balance they have to weigh
18 all the rate impacts, including the higher long-term
19 rates that come from traditional cost plus AFUDC
20 treatment, the rate shock that comes when the large,
21 long-lead-time asset is placed into rates in a single
22 step, and the financing implications to the utility of
23 having CWIP available or not.
24 Q.Ms. Mitchell also makes statements regarding.25 CWIP and Idaho Power's current financial
176 GALE, DI REB 13
Idaho Power Company
.
.
1 si tuation and credit rating implications. Will you
2 address those issues?
3 A.No. Company witness Lori Smith will respond to
4 those issues. However, I would like to respond to the
5 totali ty of Ms. Mitchell's CWIP testimony by restating
6 the Company's position that CWIP is a tool that is
7 provided to the Commission to use at their discretion
8 ei ther fully or partially and either with or without the
9 ratemaking measures provided by Idaho Code § 61-541.10 NIPPC
11 Q.In his testimony on behalf of NIPPC, Dr.
12 Reading testifies that even though the Company is a
13 regulated utility in Oregon, the Company simply ignored
14 the Oregon Public Utility Commission ("0PUC" or "0regon
15 Commission ") Guidelines for Competi ti ve Bidding. Is Dr.
16 Reading correctly presenting the facts?
17 A.No he is not. The Company complied with the
18 Oregon Competi ti ve Bidding Guidelines when it initiated
19 the 2012 baseload resource RFP process that selected the
20 Langley Gulch project. In accordance with Guideline No.
21 2, on April 17, 2008, Idaho Power filed a Petition with
22 the OPUC requesting a partial waiver of the OPUC' s
23 Competitive Bidding Guidelines (lithe Petition"). A copy
24 of the Petition is attached as Exhibit No.9..25
177 GALE, DI REB 14
Idaho Power Company
1 In its Petition, the Company described the.2 events and risk factors that caused the Company to
3 accelerate its issuance of an RFP to acquire a baseload
4 resource to meet anticipated loads in 2012 ("RFP
5 Resource"). The RFP Resource, now known as Langley
6 Gulch, was intended to replace the 250 MW pulverized
7 coal-fired generating resource that had been scheduled to
8 be on-line for 2013 in the Company's acknowledged 2006
9 IRP.
10 In its Petition, the Company identified those
11 areas in which its RFP would not be in strict compliance
12 wi th the Competi ti ve Bidding Guidelines. The Company
13 also explained how it had structured its RFP so that it.14 would be in substantial compliance with the Competi ti ve
15 Bidding Guidelines and would provide a fair and
16 cost-effecti ve competi ti ve bidding process. As part of
17 that explanation, the Company described the extensive
18 review process the Idaho Commission would undertake.
19 During May, June, and July of 2008, Idaho Power responded
20 to data requests from the Oregon Commission Staff and
21 participated in a number of discussions with Staff to
22 explain the Company's filing and to provide Staff with
23 additional information concerning the reasons underlying
24 the filing of the Petition..25 Idaho Power's purpose in asking for the waiver
178 GALE, DI REB 15
Idaho Power Company
.
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
1 was to comply with Competi ti ve Bidding Guideline No. 2
2 under
3
4 /
5
6 /
7
8 /
9
179 GALE, DI REB 15a
Idaho Power Company
.1 which the OPUC can waive the competi ti ve bidding
2 requirements on a case-by-case basis. In so doing, the
3 Company apprised the Oregon Commission of the Company's
4 changing resource plans and gave the Commission an
5 opportuni ty to review and suggest changes to the
6 Company's RFP process. In filing the Petition, Idaho
7 Power also hoped to obtain the Commission i s concurrence
8 with the Company's position that strict compliance with
9 the Competi ti ve Bidding Guidelines would compromise the
10 Company's ability to move quickly enough to secure a
11 needed resource required to meet expected demand and,
12 therefore, strict compliance with the Competitive Bidding
.13 Guidelines would not be in the best interest of the
14 customers.
15 The Oregon Commission Staff interprets the
16 Oregon guidelines to require that in order to conduct a
17 RFP, a potential resource must have been explicitly
18 included in an acknowledged IRP. Ul timately, in August
19 of 2008, the OPUC Staff advised the Company that Staff
20 could not conclude that a baseload natural gas-fired
21 resource had been included in an acknowledged IRP and, as
22 such, the Company could not proceed with the waiver
23 request. They reached this conclusion despite the fact
24 that the Company had included a baseload coal-fired.25 generating resource scheduled to be on-line in 2013 in
its 2006 acknowledged
180 GALE, DI REB 16
Idaho Power Company
.1 IRP, the Company's 2008 IRP Update, and the Company's
2 responses to the Staff i s data requests. While Idaho
3 Power did not agree with the Oregon Staff's conclusion,
4 its only recourse at that point was to engage in a
5 contested case. A contested case would have been
6 extremely time consuming and expensive. Because the
7 Company planned on opening bids in the RFP process in
8 October, most of the benefits the Company had hoped to
9 receive from the petition process, i. e., suggested
10 changes to the Company's RFP process, would not have been
11 realized even if it ultimately prevailed. From the
12 Company's standpoint, the Petition had become essentially
13 moot. As a result, the Company accepted Oregon Staff's.14 recommendation that the Company withdraw the Petition and
15 address the results of the 2012 RFP in a subsequent
16 proceeding.
17 Q.The bulk of Dr. Reading i s testimony on behalf
18 of NIPPC consists of a comparison of the process Idaho
19 Power pursued in this 2012 baseload resource RFP with the
20 Oregon Competitive Bidding Guidelines. Do you have a
21 response to that portion of Dr. Reading's testimony?
22 A.I am not sure what relevance that portion of
23 Dr. Reading's testimony has to this proceeding. The
24 state of Idaho does not have competitive bidding.25 requirements in place and this Commission has already
opened another
181 GALE, DI REB 17
Idaho Power Company
.
.
1 docket, GNR-E-08-03, in which the Commission can address,
2 presumably with all three electric utilities in Idaho,
3 the question of what, if any, competi ti ve bidding
4 guidelines are needed in Idaho. Apparently NIPPC is
5 making a "preemptive strike II by presenting testimony in
6 this proceeding which, presumably, will also be presented
7 in the GNR-E-08-03 docket. Because the Commission has
8 the opportunity to undertake a comprehensive review of
9 the need for competi ti ve bidding guidelines in Idaho in
10 another current docket, I do not think it is fruitful to
11 engage in a point-by-point refutation of Dr. Reading's
12 testimony here.
13 If the Commission decides to proceed with
14 GNR-E-08-03, Idaho Power will participate in good faith.
15 However, in considering Dr. Reading's recommendation in
16 this case that the Commission terminate this proceeding,
17 adopt a new set of bidding guidelines like the Oregon
18 Competitive Bidding Guidelines, and repeat the RFP with
19 the guidelines in place, the Commission should be
20 cognizant of the following facts:
21 1.In July of 2006, PacifiCorp filed an
22 application with the OPUC under the Oregon Competitive
23 Bidding Guidelines to conduct a RFP for a baseload
24 resource to be available in 2012 (PacifiCorp' s Draft 2012.25 Request
182 GALE, DI REB 18
Idaho Power Company
.
.
1 for Proposals, UM 1208). After that lengthy proceeding
2 had been underway for two and a half years, PacifiCorp
3 wi thdrew its RFP prior to the completion of the case
4 citing the economic downturn and its belief that it might
5 be able to obtain better pricing. However, by that time
6 PacifiCorp had incurred nearly $800,000 in Independent
7 Evaluator's ("IE") fees and expected to incur another
8 $250,000 in IE fees to conclude the case (PacifiCorp's
9 Application for Reauthorization of Deferral Accounting,
10 UM 1285 (2), December 15, 2008).
11 2.Conducting RFPs under the Oregon
12 Competi ti ve Bidding Guidelines requires a very large
13 investment of Oregon Commission and Staff time and
14 resources to closely manage the utility's RFP process.
15 COMMISSION STAFF
16 Q.Did you review the testimony of the Commission
17 Staff witnesses?
18 A.Yes. I have no rebuttal comments to the
19 testimonies of Ms. Patricia Harms and Ms. Teri Carlock
20 and just a few regarding Mr. Sterling's testimony.
21 Q.What is your understanding of Mr. Sterling's
22 testimony?
23 A.Mr. Sterling is supportive of the need for the
24 resource and confirms the integrity of the resource.25
183 GALE, DI REB 19
Idaho Power Company
.1 acquisi tion process. Mr. Sterling expresses concerns
2 regarding the Company's decision not to consider
3 "build-and-transfer" bids into the selection process.
4 Mr. Sterling also states concerns regarding certain
5 aspects of the timing of the process - including its
6 relationship to Senate Bill 1123 - and the potential
7 "box" in which he feels the Commission was placed by the
8 Company. Additionally, Mr. Sterling takes a different
9 approach as to the application of caps to the Commitment
10 Estimate.
11 Q.What is Idaho Power's general response to Mr.
12 Sterling's testimony?
13 A.The Company views Mr. Sterling as an expert in.14 the areas of resource planning, resource costing, and
15 resource selection processes and values his support of
16 the need for the resource and the validity of the process
17 to acquire it. The Company has a different perspective
18 on the value of the "build-and-transfer" option in this
19 circumstance, which Idaho Power witness Porter will
20 address. I would like to respond to Mr. Sterling's
21 proposal to apply a cap to the Commitment Estimate and
22 his concern that the Company handcuffed the Commission
23 into a less than optimal set of decisions.
24.25
184 GALE, DI REB 20
Idaho Power Company
.
.
.
i Q.Please restate the Company i s request in this
2 proceeding related to the application of a cap to the
3 Commitment Estimate.
4 A.Idaho Power is requesting approval of a total
5 Commitment Estimate of $427,366,729, which includes the
6 power plant and the two transmission interconnection
7 proj ects related to the Ontario-Caldwell connection and
8 the Caldwell-Willis connection. We are requesting that
9 the Commitment Estimate be subj ect to a soft cap that
10 provides retail customers with the full benefit of the
11 Project being completed under the Commitment Estimate,
12 while providing the Company with the opportunity to
13 justify any costs above the Commitment Estimate as
14 prudent should that be the case.
15 Q.In what ways do you view the CPCN request for
16 the Langley Gulch project as different from the CPCN
17 requests for peaking facilities in recent years?
18 A.Idaho Power has filed CPCNs with the Commission
19 in 2001 (Evander Andrews #2 and #3), 2003 (Bennett
20 Mountain), and 2006 (Evander Andrews #1). All of these
21 projects were simple cycle turbine peaking plants
22 compared to Langley Gulch's combined cycle combustion
23 turbine design. They are smaller in size, less expensive
24 to construct, and quicker to construct than Langley
25 Gulch. Wi th smaller dollars to finance and less than a
185 GALE, DI REB 21
Idaho Power Company
.1 year from the issuance of a CPCN and the commercial date,
2 these proj ects were financially more secure than the
3 current Proj ect. The uncertainty in today 's capital
4 markets has added yet an additional complication to
5 Langley Gulch not experienced in previous proj ects.
6 Q.Why did the Company not propose a hard cap?
7 A.Idaho Power does not believe a hard cap is
8 necessary to ensure that the project is well managed in
9 an economic manner. The Company has a good track record
10 of bringing projects in at or below cost estimates as
11 demonstrated through our series of combustion turbines
12 and upgrades to our hydro facilities. Wi th the soft cap
.13 on the Commitment Estimate, the Commission is in full
14 control as the gatekeeper for the recovery of any
15 addi tional costs with the full burden of prudency on the
16 utility. Additionally, in this instance, the Project is
17 significantly less expensive than the second best option.
18 Q.Does the Company have concerns regarding Mr.
19 Sterling i s proposed implementation of a hard cap?
20 A.Yes. Mr. Sterling's proposal would introduce
21 new features that add risks to cost recovery that have
22 been absent from past CPCN cases where the Company has
23 provided Commitment Estimates. In my view, these new
24 features are not consistent with the intent of the new.25 law.
186 GALE, DI REB 22
Idaho Power Company
.
.
.
1 Past CPCNs approved by this Commission have allowed
2 utili ties to make a subsequent case for legitimate cost
3 recovery following completion of the proj ect if the
4 addi tional costs were incurred due to causes beyond the
5 utili ty' s control. Mr. Sterling's proposal does not
6 appear to have that flexibility.
7 Addi tionally, the language of the law does not
8 contemplate a hard cap, only a soft cap. See Exhibit No.
9 8 and refer to Section 61-541. II (b) (iii). Clearly a~ap
10 is provided for, but so is the opportunity for the
11 utility to present additional evidence on the prudence
12 and reasonableness of additional costs.
13 Ultimately, the Company must justify any amount
14 that exceeds the cap and parties can oppose the
15 addi tional cost recovery at that time. There is no
16 reason to presume that circumstances that may arise
17 should be eliminated from future consideration today.
18 Q.In discussing the need for a hard cap, Mr.
19 Sterling raises a concern about the Project becoming
20 essentially a money pit where the utility embarks upon
21 the construction, but then presents a series of
22 addi tional cost overrun requests that are justified in
23 part on the sunk costs of dollars already expended. What
24 is your response?
25
187 GALE, DI REB 23
Idaho Power Company
.
.
.
1 A.More than any other entity, the Company would
2 not want to be involved in a proj ect where costs were
3 spiraling. Our past proj ect management record does not
4 indicate a history of out-of-control proj ects. The
5 circumstances surrounding the development of a combined
6 cycle gas turbine project (i.e., the site, permitting,
7 proven technology, etc.) do not create excessive concerns
8 about a cost spiraling situation; however, as we have
9 seen recently, conditions can change rapidly and
10 situations beyond the Company's control can materially
11 alter costs. Idaho Power cannot guarantee that it will
12 not happen. Reporting requirements, audit controls, and
13 project updates can all assist in monitoring Langley
14 Gulch progress from both a timing and budget perspective.
15 Ultimately, if the Commission determines that a hard cap
16 is necessary to protect against a runaway situation, then
17 it would be reasonable to set it at the level of the
18 second-best alternative bid.
19 Q.Besides the introduction of a hard cap to the
20 Commitment Estimate is there anything else in Mr.
21 Sterling's recommendations on the Commitment Estimate
22 that causes the Company concern from a conceptual
23 standpoint?
24
25
A.Mr. Sterling's line item application of the
soft cap is a very conservative approach that micro-
188 GALE, DI REB 24
Idaho Power Company
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1 manages the Company. It is also a significant departure
2 from prior Commission treatment of commitment estimates
3 in CPCNs. Under its Application, the Company could bring
4 Langley Gulch into commercial operation early and under
5 the Commitment Estimate and still suffer cost recovery
6 disallowances because each line item did not come in as
7 precisely as originally estimated. I do think a line
8 item evaluation of overages could have value if the soft
9 cap on the Commitment Estimate was exceeded and the
10 Company was actually requesting additional recovery.
11 Then the component analysis of the cost variances could
12 be useful to the Commission in its deliberations to
13 determine if certain component costs justifiably drove
14 overall costs above the Commitment Estimate.
15 Q.Please sum up your response to Mr. Sterling's
16 recommendations of caps to the Commitment Estimate.
17 A.I would strongly urge the Commission to
18 evaluate the Project i s total Commitment Estimate as the
19 prudency test for bringing the plant on line. Line item
20 variances should be examined if the Company actually has
21 additional costs that it later brings to the Commission
22 for additional recovery. A hard cap is not necessary
23 and, if
24
25 /
189 GALE, DI REB 25
Idaho Power Company
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1 applied, should be set at the level of the cost of the
2 second-best bid received in the RFP.
3 Q.At the end of his testimony, Mr. Sterling
4 criticizes Idaho Power for handcuffing the Commission in
5 its decision making, stating that II Staff does not believe
6 that either ratepayers or the Commission should be held
7 hostage because of the Company's inability to plan and
8 acquire resources in a less time constrained manner. II
9 Please respond.
10 A.I agree with Mr. Sterling's assertion that the
11 Company should not handcuff the Commission and its
12 customers or hold them as hostage as a result of its
13 inabili ty to plan and acquire resources in an appropriate
14 manner. Limiting the Commission's options was certainly
15 not Idaho Power's intent. However, I disagree with Mr.
16 Sterling that the Langley Gulch CPCN application fits
17 that description. Resource filings are increasingly
18 complicated and subject to a tension between enough time
19 to process and enough current information to make a
20 quality decision. For example, we can look at
21 PacifiCorp' s recent experience in Oregon, where it filed
22 an application to conduct a RFP for a baseload resource
23 to be available in 2012. As discussed in the Company's
24 Response to the Intervenors' Joint Motion to Stay (pages
25 19-20) and referenced in my testimony above
190 GALE, DI REB 26
Idaho Power Company
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.24
25
1 on page 19, PacifiCorp withdrew its RFP two and a half
2 years into the RFP process due in part to a reduction in
3 the price of commodities and its belief that it might be
4 able to obtain better pricing. Had Idaho Power filed in
5 2006, like PacifiCorp did in Oregon, the Idaho Commission
6 would not have had an opportunity to consider some of the
7 impacts of the economic downturn and data closer to the
8 on-line date.
9 Addi tionally, a key difference between Idaho
10 Power's perspective and Staff' s perspective is the value
11 and viability of the "build-and-transfer" proposals. For
12 the reasons expressed in Mr. Porter's testimony, the
13 Company feels strongly that the "build-and-transfer"
14 option does not bring value to the process. If the
15 Commission agrees with the Company on the value of the
16 build and transfer option, then a six-month procedural
17 schedule should be adequate for regulatory review.
18 Should the Commission feel otherwise, then Idaho Power
19 will dutifully adjust our approach in future filings.
20 Q.Have you concluded your testimony?
21 A.Yes.
22
23
191 GALE, DI REB 27
Idaho Power Company
.
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17
18
1 (The following proceedings were had in
2 open hearing.)
3 MR. KLINE: With that, I would make
4 Mr. Gale available for cross.
5 COMMISSIONER KEMPTON: Mr. Richardson.
6 For the record, the request by Idaho Power to spread the
7 direct and rebuttal testimony was ordered and I'm sure
8 his request came across loud and clear.
9 Mr. Richardson.
10 MR. RI CHARDSON : Than k you, Mr. Cha i rman .
11 I just have a couple of questions.
12
13 CROS S - EXAMINAT I ON
14
15 BY MR. RICHARDSON:
16 Q Good afternoon, Mr. Gale.
A Good afternoon.
Q In your rebuttal testimony on page 22,
19 beginning on line 20, you talk about Mr. Sterling's soft
20 cap proposal and you state that it adds new features that
21 add risks to the cost recovery that have been absent from
22 past CPCN cases. Then you go on to state that these new
23 features are not consistent with the intent of the new
24 law. Do you see that?
25 A Yes, I do.
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192 GALE (X)
Idaho Power Company
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1 Q And by the new law, you're referring to
2 what's included in your Exhibit No.8; correct?
3 A Yes.
4 Q And do you recall in Exhibit No. 8 the new
5 law where it provides that the Commission is not bound by
6 traditional ratemaking methodologies?
7 A That's familiar. I was just trying to
8 find it and can you refer me in the Code?
9 Q It's in section paragraph 2 there at the
10 very beginning, the last sentence that reads, "For
11 purposes of this section, the requested ratemaking
12 treatments may include non-traditional ratemaking
13 treatments or non-traditional cost recovery mechanisms. II
14 A Yes, I see it.
15 Q Okay; so the fact that something hasn't
16 been done before isn't necessarily restrictive of this
17 Commission, at least under this new law; correct?
18 A I would agree the Commission has a lot of
19 latitude under the new law.
20 Q And at page 4 of your direct testimony,
21 beginning on line 16, you talk about the on-line date for
22 the Langley Gulch project and here you testify that the
23 operational date is going to be in December of 2012; is
24 that still accurate?.25 A No, I think the Company's rebuttal through
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193 GALE (X)
Idaho Power Company
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17
18
1 a number of witness have discussed the potential ability
2 to bring it in earlier.
3 Q And the new target date is what?
4 A It would be June of 2012.
5 Q And so that would be a construction period
6 of approximately a little less than two-and-a-half years;
7 is that correct?
8 A Let's see.
9 MR. KLINE: Mr. Chairman, I'm going to
10 obj ect. I think that's probably a better question for
11 Mr. Porter who is the witness on construction time.
12 THE WITNESS: I would -- oh.
13 Q BY MR. RICHARDSON: It's a simple math
14 question.
15 COMMISSIONER KEMPTON: I'm not sure it's a
16 simple math question.
MR. RICHARDSON: I can't hear you.
COMMISSIONER KEMPTON: Thank you. I'm not
19 sure it's a simple math question because there's an
20 incentive contract for an early construction that may
21 also figure into this.
22 Q BY MR. RICHARDSON: So may I ask a
23 question for foundation?
24
25
COMMISSIONER KEMPTON: Yes.
Q BY MR. RICHARDSON: Are you familiar with
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194 GALE (X)
Idaho Power Company
.1 the proposed on-line date? I'm not asking if you're
2 familiar with how a plant is built, but I'm asking if
3 you're familiar with the proposed on-line date for the
4 project.
5 A Yes, I am.
And what is that date?
Wi th the incentive strategy the Company is
8 attempting to deliver or to have the plant on-line by
.
6 Q
7 A
9 June of 2012.
10 Q
11 testimony?
12 A
13
Are you familiar with Ms. Smith's
I've read it.
Q Do you recall in her testimony where she
14 testifies that it would take four years to construct this
15 plant?
16 A
17 Q
18 you?
19
20
21
22
A
Q
A
Q
23 14 at line 12.
24.25
A
Q
No, I'm not recalling that.
Do you have her testimony available to
Ms. Smith's testimony?
Correct.
Direct or rebuttal?
It would be her direct testimony on page
I see it.
And does she not testify or is slated to
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195 GALE (X)
Idaho Power Company
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1 testify that it would take four years to construct the
2 plant?
3 A That's what her testimony says. She is in
4 the room.
5 Q I was wondering if you can reconcile your
6 June of 2012 on-line date with her testimony.
7 A Well, for purposes of the on-line dates
8 and the construction starts, I'd defer to Vern Porter for
9 my information.
10 Q Now, in your testimony you discuss
11 generally what's called CWIP or construction work in
12 progress, that's C-W-I-P, and the regulatory preapproval
13 legislation; correct?
14 A Yes, I do.
15 Q And you identify each of these as a tool
16 for risk management to help finance the project and my
17 question is, is it your proposal to proceed with one or
18 the other or one of the two?
19 A i discuss them both purposefully because
20 they are two tools that the Commission may decide to use
21 and they are two tools that can be used together and are
22 more beneficial together. I think my testimony also
23 draws a conclusion of which is the preferred tool from
24 the Company's standpoint..25 Q And that preferred tool is the regulatory
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196 GALE (X)
Idaho Power Company
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1 preapproval?
2 A Let me stay with my testimony so I'm
3 consistent. Pardon me, I think that's in my supplemental
4 so I'm still turning pages. Okay, page 6 of my
5 supplemental answers that question directly.
6 Q And the answer is you prefer the
7 regulatory preapproval process; correct?
8 A Yeah, in the full context of that answer,
9 but that is the short answer.
10 Q And the consequences of this Commission
11 regulatorily preapproving Langley Gulch for ratemaking
12 purposes would be that if this plant turns out not to be
13 used and useful that the ratepayers are still obligated
14 to pay Idaho Power's costs of this plant; is that true?
15 A Well, the consequences of authorizing or
16 issuing an order that has ratemaking assurances
17 consistent with the new legislation is that the
18 Commission would be deciding the ratemaking deal today
19 instead of when it comes on-line.
20 Q And is it your understanding that future
21 commissions could undo that deal?
22 A The purpose of the legislation is to
23 commit future commissions, should this Commission decide
24 to use it commit future commissions, that same.25 decision.
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197 GALE (X)
Idaho Power Company
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20
1 Q So back to my earlier question, if the
2 plant turns out not to be used and useful and this
3 Commission issues a regulatory preapproval order and down
4 the road the plant is constructed pursuant to that order
5 and it turns out that the recession turns into a
6 depression and as a result we don't have carbon
7 legislation from Congress because of the economic
8 conditions, if the plant turns out to be a lemon and this
9 Commission has approved it, future ratepayers would still
10 be obligated to compensate Idaho Power for its costs;
11 correct?
12 A It's not our expectation that the plant is
13 going to be a lemon, but you can construct a scenario
14 where the plant is completed and it can be viewed in
15 retrospect of not providing the benefits that were
16 anticipated or are anticipated at this time.
17 Q And Idaho Power has been on the cusp of
18 building other plants where it's pre-ordered equipment
19 that were not built; correct?
A There have been instances in the past
21 where we pre-ordered equipment and had to work around
22 it.
23 Q You're familiar with the requirement that
24 Idaho Power obtain a certificate of public convenience.25 and necessity prior to constructing a new plant, aren't
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198 GALE (X)
Idaho Power Company
.1 you?
2 A Yes.
Pardon me?
Yes.
Do you know what's the purpose for that
I can only assume a purpose for that.
What's your understanding of the purpose
9 for that requirement?
3 Q
That the Commission would be generally
11 aligned with the Company's decision to build that
4 A
12 resource, the general size and magnitude that's
.
5 Q
And what do you mean by the phrase would
15 generally be aligned with the Company, what does that
6 requirement?
7 A
Well, I'm assuming that the purpose of the
lS certificate, at least in part, is that the Commission
8 Q
19 represents that the Company has made a case for that
10 A
20 resource to the extent that it issues the certificate.
21
13 represented.
And do you know if that certificate
22 requirement requires the Company to obtain a certificate
14 Q
23 prior to constructing the plant, prior to beginning
16 mean?
17 A
Q
24 construction?.25 A I have not refreshed myself with the code
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199 GALE (X)
Idaho Power Company
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.
1 related to the certificate requirement.
2 Q Are you the Company's policy witness?
3 A I am the Company's regulatory policy
4 witness.
5 Q And you're steering a process here where
6 the Company is in front of the Commission asking for a
7 certificate of public convenience and necessity and
8 you're telling me you haven't reviewed the requirements
9 for getting one?
10 A I have not looked at the code in this
11 instance.
12 Q So you don't know whether or not it
13 requires the Company to obtain a certificate prior to
14 beginning construction?
15 A I assume it does, but I haven't refreshed
16 on the language of the code prior to testifying.
17 Q Based on your assumption that it does, can
18 you tell me whether or not ordering turbines, putting
19 down payments on turbines, retaining construction
20 companies, obtaining permits if all that doesn't add up
21 to beginning construction?
22
23 opinion.
MR. KLINE: Obj ection, calls for a legal
24.25
COMMISSIONER KEMPTON: Sustained.
MR. RICHARDSON: May I respond,
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200 GALE (X)
Idaho Power Company
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20
1 Mr. Chairman?
2 COMMISSIONER KEMPTON: That question that
3 was obj ected to constitutes a regulatory decision and the
4 interpretation of that piece of statute in my mind is
5 open to the conj ecture of anybody that attempts to make a
6 determination and provide it to the hearing separate from
7 on our position an AG' s opinion.
8 MR. RICHARDSON: I'll withdraw the
9 question, Mr. Chairman.
10 Q BY MR. RICHARDSON: Would you agree,
11 Mr. Gale, that it's the Commission's job to decide
12 whether or not a certificate is issued for construction
13 of a new plant?
14 A Would you repeat the question, please?
15 MR. RICHARDSON: Would you read the
16 question back, please?
17 (The last question was read back by the
18 Notary Public.)
19 THE WITNESS: Yes.
Q BY MR. RICHARDSON: Did you read
21 Mr. Sterling's testimony in this case?
22
23
A Yes, I have.
Q And do you recall where he says that the
24 Commission has been handcuffed into making this decision.25 by Idaho Power?
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201 GALE (X)
Idaho Power Company
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20
21
22
1 A I remember that testimony.
2 Q On page 12 of your direct testimony,
3 beginning on line 11, you were asked whether or not Idaho
4 Power could assure the Commission that the Company has
5 the ability to finance this proj ect and you responded
6 that no, it cannot, and on page 3 of Mr. Bokenkamp' s
7 testimony, he states that he believes delaying the
8 construction of the Langley Gulch proj ect would be a very
9 risky strategy . Given your identified uncertainties
10 surrounding financing, wouldn't you agree that the
11 Company's ability or concern about its ability to finance
12 the proj ect is also a very risky strategy to proceed with
13 this proj ect versus a power sales agreement or a tolling
14 agreement?
15 A I'm sorry, Mr. Richardson, I was still
16 looking for the reference to Mr. Bokenkamp. Did you say
17 page 3?
18 Q I did say page 3.
19 A Of his direct?
Q It's his rebuttal.
A Oh, rebuttal?
Q Yes. Page 3, beginning on line 4 of
23 Mr. Bokenkamp' s testimony, he's asked to respond to
24 Dr. Reading's recommendation that we restart the RFP and.25 that we delay the issuance of a CPCN and he says -- is
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202 GALE (X)
Idaho Power Company
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1 asked if those recommendations are reasonable and
2 according to Mr. Bokenkamp, he suggests that it's a very
3 risky strategy that we're proposing and my question to
4 you, and I'll restate it because it wasn't very artful,
5 is given the uncertainty surrounding financing that
6 you've identified, isn't ita risky strategy for the
7 Company to pursue the self-build option as opposed to a
8 power purchase agreement or a tolling agreement?
9 A Thank you, and in the context that Karl
10 Bokenkamp is discussing it, he's talking about a risky
11 strategy, I believe, from a reliability standpoint.
12 Going back to my relevant testimony, the Company and
13 my testimony does say that we cannot assure that the
14 project will be financed at that time, but I state the
15 two tools that may help finance that proj ect and I think
16 that balanced against the difference between the
17 al ternati ves that the Commission could very easily
18 consider using one of those two tools to help us finance
19 that project so that risk can be mitigated by either or
20 both of the two tools.
21 Q But it's still a risky strategy, is it
22 not, to proceed with the self-build as opposed to a power
23 purchase agreement or a tolling agreement as compared to
24 those options?
25 A Well, what I cannot address and perhaps
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203 GALE (X)
Idaho Power Company
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1 Ms. Smith can is the financial assessment of the other
2 al ternati ves.
3 Q And on page 8 of your direct testimony,
4 beginning on line 3, you state that issuing large amounts
5 of equity at this time is simply not prudent. Do you see
6 that?
7 A Yes, I do.
8 Q And do you see any relationship between
9 the Company's disinclination to issue large amounts of
10 equi ty, thereby having the Company's shareholders fund
11 the project as opposed to engaging in construction work
12 in progress in current rates, thereby having the
13 ratepayers fund the proj ect?
14 A I think it's the timing. The point that
15 we're trying to make and I'm trying to make here is the
16 timing. Issuing equity when you're below book value is
17 just not a very prudent financing strategy for a company
18 and in a different cash flow situation and in a different
19 market price for our stock, the Company might find itself
20 in a position where it could very easily finance this
21 proj ect. It's just in part a victim of the current
22 circumstances.
23
24 Mr. Chairman. Thank you, Mr. Gale.
MR. RICHARDSON: That's all I have,
25 THE WITNESS: Thank you.
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204 GALE (X)
Idaho Power Company
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1 COMMISSIONER KEMPTON: Ms. Ackerman.
2 MS. ACKERMAN: Yes, Mr. Chairman, thank
3 you.
4
5 CROSS-EXAMINATION
6
7 BY MS. ACKERMAN:
8 Q Mr. Gale, could I turn you to your direct
9 rebuttal testimony
10 A Yes.
11 Q at page 18 and then continuing on to
12 page 19? I won't read it to you, but there generally you
13 testify as to the cost to PacifiCorp of hiring an
14 independent evaluator to monitor and oversee RFP' s that
15 that company has undertaken and the question I've got for
16 you is how much did Idaho Power pay Mr. Stein and R. W.
17 Beck for their analysis for purposes of this case in that
18 RFP, in Idaho~ s RFP?
19 A I don't have personal knowledge of what we
20 paid Mr. Stein, although potentially Mr. Bokenkamp might
21 have personal knowledge of that.
22 Q So Mr. Bokenkamp would be the person that
23 I should ask that question to?
24.25
A Better witness than me.
MS. ACKERMAN: Okay, thank you, no more
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205 GALE (X)
Idaho Power Company
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1 questions.
2
3 Ms. Ackerman. Mr. Olsen?
COMMISSIONER KEMPTON: Thank you,
4
5 Mr. Chairman.
6
7
8
9 BY MR. OLSEN:
10 Q
MR. OLSEN: Yes, thank you,
CROSS-EXAMINATION
How are you doing, Mr. Gale? I just have
11 a couple of questions here and if I could turn you to
12 your direct rebuttal testimony on page 4.
13
14
COMMISSIONER KEMPTON: Mr. Olsen, your
volume is consistently low. If you brought that
15 microphone around to the front, maybe, of your computer
16 or closer it may help.
17
18 me.
19
20 eat the thing.
21
22 Olsen.
23
24
25 testimony.
MR. OLSEN: I'll put it right in front of
COMMISSIONER KEMPTON: You don't have to
THE WITNESS: Okay, I'm there, Mr.
MR. KLINE: I'm sorry, I'm not, where?
MR. OLSEN: Page 4 on his direct rebuttal
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206 GALE (X)
Idaho Power Company
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.
1 Q BY MR. OLSEN: And in here you were
2 talking about some reliability issues that you say
3 counterbalance Ms. Mitchell's assertion that the project
4 can be delayed without consequence. Do you see that in
5 the question and the answer?
6 A Yes.
7 Q And then one of the, I guess you'd call
8 it, a wild card down here at the bottom, lines 17 through
9 22, is potential new loads. Do you see that?
10 A Yes.
11 Q And we heard Mr. Mace testify of a
12 potential new load of 240 megawatts or something like
13 that as I recall.
14 A Yes.
15 Q Okay. Now, how do you plan for new loads
16 if there's not sufficient, I guess, capital outlay to
17 know that they're going to happen, because we have Hoku
18 on the one hand you say we have a contract with, have
19 made investment and then we have these what if's, could
20 you explain to me that process?
21 A First of all, I want to thank you for that
22 question because how you plan for new loads is a
23 difficult thing to accomplish for us right now and we do
24 have a number of large loads, including the one that Mr..25 Mace mentioned at the end of his testimony, who are
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207 GALE (X)
Idaho Power Company
.1 interested in having capacity on the system. Where we've
2 drawn the line thus far is for a customer the size of a
3 special contract, meaning above 25 megawatts, is we've
4 pushed them to an actual contract. That's why Hoku gets
5 planned for and that 240 doesn't, but one more statement
6 of context for that.
7 You get a 240 megawatt customer come
8 knocking on the door, that's difficult. That's a
9 difficult riddle, I think, for all of us and in part, the
10 reason that that first combined cycle bid was up to 600
11 was to see if there was something that could be done to
12 solidify and answer that one large load question..13 Q Okay, well, so the uncertainty, unless you
14 have a contract, you don't include it in load
15 forecasting, but given that proposition there, what
16 relevance do these large loads have, because it wouldn't
17 seem to be relevant, would it, because you don't put them
18 in the planning process until a certain point?
19 A They're relevant from this aspect and we
20 are often, we the Company are often, caught in a
21 difficult position with economic development agencies,
22 cities, counties and so forth that are looking to attract
23 large load and we don't have the head room or capacity in
24 our system to be able to answer their question or answer.25 them affirmatively that we have the capacity to serve
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208 GALE (X)
Idaho Power Company
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20
1 them. Even the Hoku contract has summer restrictions
2 that are substantial.
3 That's not what they asked for and we had
4 to shape their load in order to accommodate that special
5 contract and I can tell you as someone that sits down and
6 talks with every large load that wants to come above 25
7 megawatts, one of the first things we do is ask them how
8 they can curtail in the summer. Even someone that calls
9 today and wants to come on the system, we talk to them
10 about what they can bring to the table that we can manage
11 their load during our summer peak.
12 Q And I have one other comment in here and
13 I'm not trying to be too cheeky or whatever, but you've
14 probably seen the movie Field of Dreams, Kevin Costner?
15 A Yes.
16 Q Okay, and his tag line in there, build it
17 and they will come, isn't this kind of the speculation,
18 this new load is and your relationship you're trying to
19 draw with
A I would say if we had built 600 megawatts,
21 we would build it and they would come. I think that we
22 have the need for 300 just upon our normal growth and our
23 contracted load.
24
25
MR. OLSEN: Okay, no more questions.
Thank you.
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209 GALE (X)
Idaho Power Company
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17
1 COMMISSIONER KEMPTON: Mr. Purdy.
2 MR. PURDY: Thank you, just a couple.
3
4 CROSS-EXAMINATION
5
6 BY MR. PURDY:
7 Q Mr. Gale, I just wanted to clear up one
8 error that you have pointed out on page 2 of your
9 rebuttal regarding Ms. Ottens' testimony. In there you
10 note toward the end of page 2, actually, line 18 that
11 Ms. Ottens estimated the cost -- stated that the
12 estimated cost for Langley Gulch was 247 million when in
13 fact you pointed out it's 427 million. Will you accept
14 my representation that that's a typo and we'll clear that
15 up when Ms. Ottens gets on the stand?
16 A I will.
Q Just to remove that as a stumbling block,
18 thank you, and similarly, Ms. Ottens testified that the
19 estimated cost is roughly a quarter of the Company's
20 existing rate base. You pointed out that it was closer
21 to 20 percent which by math would be a fifth, so we'll
22 accept your numbers just so I can clear the way to ask
23 you the questions that I actually have.
24
25
A Yeah.
Q Which are that -- now, forgive me if I'm
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210 GALE (X)
Idaho Power Company
.1 being a little dense or overly simplistic here, but in
2 light of the statute that was passed this summer and in
3 light of how the Commission has historically allowed rate
4 base recovery or given rate base assurance to a utility
5 ei ther prior to actual construction commencement or
6 shortly thereafter, how has the Company, first of all,
7 made a precise calculation as to the cost, I mean the
8 $427 million that it intends to abide by somehow, or do
9 you see the rate base assurance that you seek from the
10 Commission as just that, rate base assurance and if the
11 cost turns out to be something else, then the Commission
12 is somehow locked into allowing recovery of that
13 amount?.14 A I think that if it's 427, ultimately if
15 they accept the -- let's just say commitment estimate. I
16 think the commitment estimate that in my view anything up
17 to the commitment estimate if they approve it under the
18 statute would be allowable to be placed in rates.
19 Anything less than that would be adjusted so the
20 customers would obtain that benefit and anything higher
21 than that, at least my testimony would say we would want
22 a chance to make our case, but that certainly doesn't
23 lock the Commission into any approval.
24 Q Well, you have not locked yourself into.25 anything, you have not locked yourself into the $427
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211 GALE (X)
Idaho Power Company
.1 million figure either, have you?
2 A The 427 million, and Mr. Porter can
3 support it better than I can, but in talking with the
4 folks that work the Langley Gulch project, that is our
5 best estimate.
6 Q Presumably, I mean, the point of this, as
7 you say, your preference would be to receive rate base
8 assurance from the Commission, so, therefore, that means
9 that at some point in the future in some separate
10 proceeding you would need to come before the Commission
11 and actually ask to include the Langley Gulch plant
12 investment in rates; correct?
.13 A Well, I'm going to be just a tad picky.
14 It's ratemaking assurances of which the rate base is part
15 of it and we're asking for once it's placed into
16 commercial operation that it could be placed into rates,
17 so there would be some filing prior to that, at least I
18 would envision some filing prior to that, to file tariffs
19 and such to actually accomplish that.
20 Q All right, and, of course, the Company has
21 not made any attempt that I can see in any of its
22 testimonies to estimate the overall magnitude of the rate
23 impact that this will have aside from saying $427 million
24 increase to rate base. Have you made any such.25 calculation as to overall rates?
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212 GALE (X)
Idaho Power Company
1 A I'm going to give you an answer, but I.2 need to give you a preamble first.
3 Q Okay.
4 A Making a rate impact statement is
5 problematic because you can layer in a 400 and some
6 million dollar rate base into our current revenue
7 requirement and you're going to get a substantial
8 increase; however, that's not what will play out. The
9 facili ty is scheduled to come in in 2012. The Company's
10 system and revenue requirement won't be the same in 2012
11 as it is now. Our power supply cost will vary and we
12 will be operating the system up until that point largely
13 until the plant comes on leaning on power purchases and.14 such to provide the energy, so we have done some analysis
15 that would -- some analyses that would compare a do
16 nothing, realizing that that has a reliability
17 consequence, but a do nothing versus Langley and in 2012,
18 in the summer of 2012, there's a slight, slight
19 advantage, less than a percent, for do nothing. As soon
20 as you get into the next year, the advantage is for
21 Langley versus do nothing and if you add carbon, there's
22 no carbon in that analysis, if you add carbon into it, it
23 gets substantially better for Langley.
24 Q That scenario is based on, I assume, a.25 number of assumptions including
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213 GALE (X)
Idaho Power Company
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.
1 A You have to.
2 Q -- that your load growth forecast is
3 accurate, that your projection of off-system purchases is
4 accurate and so forth?
5 A Yes.
6 Q All right.
7 A All those things, I would agree with
8 that.
9 Q All right.
10 A But I would also say, I mean, there's a
11 reason that the Company prefers to do Langley over do
12 nothing and then Langley over the options and those are,
13 those can all be viewed as economic.
14 Q Just out of curiosity, what was the
15 overall rate increase that the Company received in its
16 most recent general rate case, do you recall?
17 A I believe it was between three and four
18 percent in base rates.
19 MR. PURDY: Okay, that's all I have.
20 Thank you very much.
21
22
23
24.25
COMMISSIONER KEMPTON: Mr. Miller.
MR. MILLER: Thank you, Mr. Chairman.
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214 GALE (X)
Idaho Power Company
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.25
1 CROSS-EXAINATION
2
3 BY MR. MILLER:
4 Q Hello, Mr. Gale, just one quick question,
5 if I could. On page 9 of your direct rebuttal, you were
6 asked about the shareholders' resolution and what impact
7 it might have on DSM programming and in your response,
8 you do mention renewables. I just want to make sure I
9 understand the response. Is your response directed
10 specifically at DSM programs in terms -- I guess another
11 way to put it is, is it the Company's position that it
12 basically is accomplishing currently what the resolution
13 was designed to do?
14 A Well, this particular question and answer
15 is directly related to whether we would do more on energy
16 efficiency given the greenhouse gas shareholders'
17 resolution and my answer is no, unless you change the
18 cost-effective criterion.
19 MR. MILLER: That's all I have. Thank
20 you, Mr. Chairman.
21 COMMISSIONER KEMPTON: Ms. Bridge.
22 MS. BRIDGE: Thank you, Mr. Chairman.
23
24
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215 GALE (X)
Idaho Power Company
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.
1 CROSS-EXAMINATION
2
3 BY MS. BRIDGE:
4 Q Mr. Gale, I just have one question. Will
5 the greenhouse gas reduction strategy be incorporated
6 into the 2009 IRP?
7 A The greenhouse gas strategy, I'd like to
8 run with that a little bit, if I could. First of all, as
9 LaMont Keen said, we take that seriously. I think in my
10 view a lot of greenhouse gas strategy is ongoing at the
11 Company and you can look to a number of places where that
12 is emerging. Now, one thing that we're doing through the
13 fall is to improve our disclosure and the shape that that
14 ul timate strategy might take could play out in the IRP.
15 I just haven't talked with the IRP folks to know exactly
16 how they want to handle it and in my mind, that's a
17 logical place for it to be discussed, too, but it will
18 play out in the back half of this year.
19 MS. BRIDGE: Okay. Thank you, no more
20 questions.
21 COMMISSIONER KEMPTON: Okay. Mr. Kline,
22 rebuttal? Oh, I'm sorry, I've got to go through my folks
23 up here. Commissioner Redford. Mr. Woodbury.
24.25
MR. WOODBURY: Thank you, Mr. Chairman.
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216 GALE (X)
Idaho Power Company
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.
.
1 CROSS-EXAMINATION
2
3 BY MR. WOODBURY:
4 Q Mr. Gale, I'd like to just clear up a
5 question that was raised in your conversation with
6 Mr. Olsen, and in my discussion with Mr. Mace earlier
7 this morning, we were talking about the 2009 load update,
8 May 2009, and the removal of 700 megawatts in new
9 customer load in that forecast and was that 700 in the
10 2008 forecast, August 2008?
11 A Mr. Woodbury, I just don't know that
12 answer.
13 Q And actually what caused me -- I was
14 wondering whether the Company had removed all new
15 customer load or still some remains.
16 A I think there's a reasonable expectation
17 that maybe Mr. Bokenkamp can answer that one.
18 Q Okay. In Mr. Mace's testimony, also, he
19 talks about a combination of load forecasting and lead
20 times, which seems to necessarily mean that the Company
21 is always operating with less than optimum facts because
22 facts will always be changing in the future. If the
23 Company is not does not obtain a certificate in this
24 case or if the Company is unable to finance at reasonable
25 terms, what then will the Company do?
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217 GALE (X)
Idaho Power Company
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18
1 A Well, I think if you just look to the
2 energy crisis, I think we're resilient under fire. I
3 would say that first. I also believe that Mr. Bokenkamp
4 has discussed at least in his, potentially his,
5 testimony, but it may be a data request, kind of the list
6 of things that we might be able to do from an operating
7 standpoint, and Ms. Smith would be the best one to talk
8 about the financial situation.
9 Q Okay. With respect to Langley Gulch, you
10 have done some permitting, you've got your site lease,
11 you have your water right and I'm not sure, are you
12 pursuing other permits right now?
13 A My guess is we would. Again, ask
14 Mr. Porter.
15 Q No, not would you, are you waiting to get
16 Commission approval before you are acting on other
17 permits?
A May I direct you to Mr. Porter on that
19 one?
20
21
Q To Porter?
A Mr. Porter, yes. I mean, he can speak to
22 the timing and the activities and the elements related to
23 the project.
24
25
Q I would refer you to your Exhibit No. 8
which is the Idaho Code Section 61-541 and that is the
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218 GALE (X)
Idaho Power Company
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.
1 Company's requested recovery in this case. On page 2 of
2 Exhibit 8, (4) (a) (i), "In reviewing the application, the
3 Commission shall also determine whether the public
4 utili ty has in effect a commission-accepted integrated
5 resource plan. II Is it your understanding that accepted
6 means acknowledged?
7 MR. KLINE: And I'm going to object. I
8 think that does ask for him to interpret the statute.
9 Q BY MR. WOODBURY: Mr. Gale, what is your
10 understanding of how the Commission treats Company
11 filings of integrated resource plans? Does the Company
12 seek to have those plans approved?
13 A No, they don't seek to have them approved.
14 The word is either acknowledged or accepted and I'm
15 stuttering at the moment.
16 Q Okay, could you indicate which integrated
17 resource plan you believe is currently in effect?
18 A Well, certainly the 2006 and then we've
19 had an update since then.
20 Q And the update in 2008 was a filing by the
21 Company, do you know whether that was noticed?
22
23
A I'm not recalling, Mr. Woodbury.
Q Okay. In 2008, the Company would have
24 been scheduled, I guess, to file an integrated resource.25 plan, do you know why the Company did not file an
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219 GALE (X)
Idaho Power Company
1 integrated resource plan in 2008?.2 A As I recollect, I thought there was a
3 desire to get the resource plans with the other Idaho
4 utili ties into some type of synchronization.
5 Q That was pursuant to Commission Order?
6 A Yes.
7 Q In commenting in your rebuttal testimony
8 on page 3, you state Ms. Ottens is saying that the
9 Langley Gulch is a big investment that will have a
10 significant rate impact and you say I agree. What will
11 be the rate impact if Langley Gulch is approved?
12 A Well, this has to do with my answer a
.13 little earlier about trying to assess and evaluate a rate
14 impact. I believe it was in answer to Mr. Purdy and if
15 you just simply lay that rate base and depreciation and
16 such onto our current rates, you get a number closer to
17 what's in Ms. Smith's testimony which I think was six or
18 seven percent. If you play it forward into 2012 and
19 escalate the revenue requirement and evaluate it against
20 other alternatives, it's diminished, I think, closer to,
21 i think, three or four percent, and then in comparison to
22 al ternati ves, maybe nothing at all, because you can't
23 just view the rate impact in isolation. There's going to
24 be a set of costs under which you're operating at that.25 point in time.
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220 GALE (X)
Idaho Power Company
.1 Q In 2012 is it possible that the Company
2 will also have its Hells Canyon licensing cost to
11 A
3 recover?
4 A One can always be optimistic.
And do you know what the effect of that
No, I didn't calculate it for today.
If a tolling agreement had been selected
9 instead of the Company's Benchmark proposal, would it not
5 Q
10 have been required to commence delivery in June 2012?
6 would be?
7 A
I'd like to defer that to Mr. Bokenkamp.
Can you explain why the Boardman-Hemingway.13 transmission upgrade is being delayed from 2012 to
8 Q
I will as best I can. The process to site
16 that line and to involve the community and work things
12 Q
17 out with different agencies and so forth is taking,
14 2015?
18 frankly, much longer than what we had originally
15 A
19 anticipated.
20 Q And if that transmission line had been in
21 place in 2012, how would that have affected the Company's
22 ability to serve load?
23 A
24 Mr. Bokenkamp..25 Q
That is a great question for
On page 4 of your rebuttal testimony, you
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221 GALE (X)
Idaho Power Company
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.
.
1 speak of the wild card is the emergence of new large
2 loads and you state that cities are still actively
3 recrui ting large loads into your service area. Is Idaho
4 Power still receiving requests to serve loads despite the
5 economic conditions?
6 A Yes, I can affirmatively say that last
7 week I talked with a consultant for two large loads about
8 locating on the western side of our property above 25
9 megawatts.
10 Q And can you give some -- are there other
11 examples?
12 A Those are the most recent examples.
13 There's been several since we've signed the Hoku or since
14 we -- yeah, since we signed the Hoku contract.
15 Q You state that your Exhibit 8, which is
16 the Idaho Code 61-541, that the language of that law does
17 not contemplate a hard cap, only a soft cap.
18 A Yes, I do state that.
19 Q Did Idaho Power play any role in the
20 drafting of that statute?
21 A The genesis of that statute goes back a
22 number of years to some legislation that a number of us
23 saw, a number of us utili ties saw, in Iowa and we've been
24 contemplating that type of assurance for quite awhile,
25 going back to even when the CWIP statute was reviewed, so
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222 GALE (X)
Idaho Power Company
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.
1 yeah, we've been in discussions, we've been in
2 discussions with PacifiCorp and an individual there by
3 the name of Brent Gale who led that legislation in Iowa,
4 so yeah, we have talked about this legislation for a
5 number of years.
6 Q Could you not interpret the language on
7 page 1 of that exhibit, paragraph (2) (b), where it says
8 that ratemaking treatments for a proposed facility
9 include but are not limited to to give the Commission the
10 latitude to use a soft cap?
11 A Could I interpret it that the Commission
12 has the latitude for a soft cap?
13 Q I mean, you indicate the language does not
14 contemplate a hard cap, couldn't this language be
15 interpreted to give the Commission that flexibility?
16 A Well, what I am relying on is without the
17 public utility having the burden of moving forward with
18 addi tional evidence, so to me if we have the ability to
19 bring additional evidence later, that's a soft cap, not a
20 hard cap. A hard cap seems like you're just out of luck
21 on your contingencies.
22 Q Would Idaho Power have required a hard cap
23 from the other bidders?
24.25
A I'm qualifying my answer a little by
saying that I don't actively work RFP processes, but I do
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223 GALE (X)
Idaho Power Company
.
.
1 believe that some of the causes, such as force maj eure,
2 gives them ability to -- gives the equivalent of a soft
3 cap, meaning force majeure would give them an opportunity
4 to--
5 Q Of course, but without force majeure, you
6 would hold them to the commitment estimate?
7 A We would hold them to the commitment
8 estimate, so you have to prove your force majeure and in
9 a way, that is exactly what we would be attempting to do
10 wi th anything we would bring back later.
11 Q You state on page 24 that if the
12 Commission does entertain a hard cap that it's reasonable
13 to set it at the level of the second-best al ternati ve
14 bid. Why do you choose that?
15 A Well, that came out of our discussions as
16 we were preparing rebuttal and thinking about ultimately
17 if the Commission would come to a hard cap where would it
18 make sense. From our perspective, anything less than a
19 second bid there's still value in the Company's initial
20 commitment estimate.
21 Q Does the Company view that $95 million as
22 money it left on the table?
23
24.25
A No.
Q Would you have provided the same type of
flexibili ty to another bidder allowing it that cushion
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224 GALE (X)
Idaho Power Company
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20
1 between its bid and the next lowest?
2 A Well, again, I think there are certain
3 contract provisions that allow those bidders to come back
4 in certain circumstances and I really, I think our
5 si tuation is more analogous than -- is analogous
6 period.
7 Q In your discussion regarding build and
8 transfer proposals and the Company's opposition, I guess,
9 now, at least in the 2012 RFP, the Company has before
10 entertained build and transfer, has it not?
11 A It's my understanding I think that's how
12 you would characterize the
13 Q Is it build and transfer or is it
14 turnkey?
15 A Turnkey.
16 Q But those were Evander Andrews and the
17 Bennett Mountain?
18 A I'm recalling just Bennett Mountain, but I
19 could be wrong.
MR. KLINE: Mr. Chairman, I think you're
21 going beyond the scope of Ric's testimony. Certainly,
22 Karl can address that better.
23 MR. WOODBURY: Oh, i could direct it to
24 another, but he speaks on page 27, starting at line 9,.25 regarding build and transfer proposals.
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225 GALE (X)
Idaho Power Company
.
.
1 MR. KLINE: I'm sorry.
2 MR. WOODBURY: That's in his rebuttal
3 testimony.
4 MR.KLINE:Page 27?
MR.WOODBURY:Page 27,line 9.
MR.KLINE:Withdrawn.
THE WITNESS:Oh.
MR.KLINE:Yeah,I forgot.
5
6
7
8
9 Q BY MR. WOODBURY: Is build and transfer
10 allowed in other states in this region to your
11 knowledge?
12 A I don't know. My context in my testimony
13 is that there are concerns that the Company now has with
14 build and transfer and those are expressed by Mr. Porter
15 and mine is just in the view of if you think of build and
16 transfer from the Company's perspective, then I don't
17 think we handcuff the Commission. If you think of build
18 and transfer more like Mr. Sterling, then maybe we did.
19 That's the whole point of that paragraph.
20
21
22
MR. WOODBURY: May I have a minute?
(Pause in proceedings.)
23 further questions.
MR. WOODBURY: Mr. Chairman, Staff has no
24.25
COMMISSIONER KEMPTON: Thank you,
Mr. Woodbury. Commissioner Redford.
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226 GALE (X)
Idaho Power Company
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.
19
1 COMMISSIONER REDFORD: Thank you,
2 Mr. Chairman. So I don't get an objection from
3 Mr. Kline, I would like to just ask a couple of things,
4 and especially I don't want to take extra time, as far as
5 the construction, as far as the price and so on, should I
6 be asking Mr. Porter or Mr.
7 MR. KLINE: Bokenkamp?
8 COMMISSIONER REDFORD: Yes.
9 MR. KLINE: Certainly, I will never object
10 to your asking a question to a witness and I know this
11 particular witness will be able to steer you to whoever
12 is the more appropriate person.
13 COMMISSIONER REDFORD: Okay, thank you
14 very much.
15
16 EXAMINATION
17
18 BY COMMISSIONER REDFORD:
Q Mr. Gale, what was your role, if any, in
20 the procurement process; that is, the drafting of the RFP
21 evaluation, engineering issues and so on, did you have
22 anything to do with all those things?
23
24.25
A I had no role.
Q Good, okay; so you weren't privy to the
Benchmark negotiation or developing its bid at all?
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227 GALE (Com)
Idaho Power Company
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.
1 A My first interaction came as a member of
2 the management team that heard the process and the
3 proj ect come together towards the end of it.
4 Q You didn't have any role in the evaluation
5 process?
6 A No, sir.
7 Q You know, I need to know again what you
8 mean by build and transfer. Maybe I can narrow that a
9 li ttle bit. Does that mean that the contractor would
10 build the plant on his own nickel and then later on
11 either transfer the ownership to Idaho Power and/or enter
12 into a purchase power agreement and/or a tolling
13 agreement?
14 A I will tell you my understanding and you
15 have, I think, two engineers coming behind me that are
16 better at it, but my understanding is that the entity
17 would construct the proj ect and transfer it over to the
18 Company and I think that Mr. Woodbury's characterization
19 of turnkey is probably a good one. That would be my
20 interpretation of build and transfer.
21 Q Okay, that's outside of the definition of
22 a purchase power agreement or a tolling agreement?
23
24.25
A Yes, sir.
Q Okay. You've also talked about the IRP
process and your testimony was that really the IRP is the
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228 GALE (Com)
Idaho Power Company
.
.
1 2006 IRP with adjustments; is that correct?
2 A Well, I want to be sure. There are parts
3 of my testimony that talk about the IRP and how it's
4 related to maybe a bias for the Company to either go with
5 a build or go with a buy, I do talk about that. The IRP
6 process itself, I will endeavor to answer questions, but
7 that would be better answered by Mr. Bokenkamp who runs
8 that process.
9 Q Oh, good, I won't ask you questions on
10 that, then. We've talked about the soft cap. Now, what
11 is your definition, if you have one, of a hard cap?
12 Would that be a fixed price contract?
13 A Yeah, a hard cap would be an amount that
14 once you went over it, you would be at complete risk.
15 Q Okay, and did you have anything to do with
16 the drafting of a contract or anything in that process?
17 A Which contract?
18 Q The contract -- any contract, whether it
19 be the contract with Beck, the contract with your
20 engineering, procurement and construction manager or did
21 someone else do it?
22 A Yeah, I apologize. The only contracts
23 that I deal with that we've talked about today are those
24 special contracts with the customers..25 Q Okay. Again, in today' s Sta tesman, and
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229 GALE (Com)
Idaho Power Company
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13.14
1 not that I believe everything I read in any newspaper, is
2 another article about Hoku and it talks about, whether
3 it's true or not, it talks about Hoku being financially
4 incapable of constructing the plant and that they're
5 looking for another buyer. Based upon that and the
6 previous testimony, wouldn't you adjust your estimate as
7 far as load or capacity in your IRP to significantly
8 reduce Hoku' s contract deli verables?
9 A I can add some color to that. I talked
10 with a senior officer from Hoku this morning and the
11 characterization I would add to the news reports is that
12 they are slowing down, not stopping, construction, very
careful to say that. They're trying to match their
construction to their cash flow which is their critical
15 element right now and that none of their contracts
16 related to that construction have been canceled, and the
17 last point of emphasis was that they are working with
18 their customers to work through this so they can operate,
19 because they have a lot of money in the project already
20 and the customers have a real vested interest in
21 obtaining that product going forward.
22 Now, that's the contract we have right
23 now, Commissioner, and we are hopeful that they can get
24 up, ramp up, be operating. We had them curtailed in the.25 summer through 2012 at this point in time, so they have
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230 GALE (Com)
Idaho Power Company
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1 qui te a bit of time to get their operation going, and
2 then I guess the counterpoint is they are in because they
3 have a contract. We have no factor for the others, you
4 know, build it and they will come or whatever. There is
5 no other factor for the rest that haven't signed
6 contracts.
7 Q Based on your conversations with Hoku,
8 have they given you any idea of when their plant will
9 finally be constructed and ready for power and on their
10 construction schedule?
11 A I am hopeful still to see them meet the
12 special contract that we have before you now.
13 Q So you don't have any idea about
14 construction schedules or anything of that notion?
15 A I don't have anything different than what
16 we have before you.
17 Q Getting back to the issue of your IRP,
18 tradi tionally doesn't the utility give an updated IRP
19 every year?
20 A Well, we have been on a two-year cycle for
21 quite awhile and then we did the update when we went to
22 the three-year break. Frequently we provide updates to
23 commissions about where we are, but as far as a document
24 itself, I don't know that we provide a written document
25 update every year.
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231 GALE (Com)
Idaho Power Company
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.
1 Q But correct me if I'm wrong, aren't you
2 waiting until December to finalize and update your IRP?
3 A That's the target date for the IRP, yes.
4 Q Okay. Do you -- well, I won't ask that
5 question. Let's see, did you have anything to do with
6 negotiation with the EPC contractor?
7 A No, sir.
8 Q How about on Boardman-Hemingway, do you
9 have any idea, it may have been asked, when that
10 procurement procedure will be over and construction will
11 start?
12 A I'm not sure when construction will start.
13 I think our estimated year when we think it's available
14 is now 2015.
15 Q Are you still dealing -- is the difficulty
16 in getting this off the ground, is it with the
17 landowners?
18 A It is placement of the line is a big part
19 of it.
20 Q I'm sure you probably know FERC wants that
21 capabili ty and whether that will be quicker or slower, I
22 don't know. How does this new plant square with your
23 shareholders and their mandate?
24.25
A Oh, well, I view it as helpful in two
ways. Basically, the shareholders have given us this
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232 GALE (Com)
Idaho Power Company
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1 non-binding directive to get a carbon plant going and
2 part of that is figuring out well, the legislation going
3 foward and so forth, but what in my mind Langley does is
4 it helps in two ways. First of all, it is extremely
5 helpful to integrate renewables, and secondly, it is a __
6 I forget the term, but it's the best available technology
7 from the environmental aspect. It's a natural gas, not
8 coal, so it does provide an option if we need to off-load
9 our coal plants, so I think it gives us flexibility in
10 addressing carbon.
11 Q You don't run the risk of having the
12 shareholders say well, you know, we gave you a mandate
13 and you thumbed your nose at us and brought back a carbon
14 emitting plant?
15 A I don't think we're thumbing the nose at
16 shareholders at all. I think this is an honest answer to
1 7 those concerns.
18 Q Okay. Did you have anything to do with
19 writing the application in this matter to the Commission
20 for approval?
21 A I reviewed the application. We work
22 together with the legal team and our group on testimony
23 and applications, so we cross-fertilize.
24
25
Q In the application in one spot you talk
about CWIP or AFUDC, but when you get to the prayer,
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233 GALE (Com)
Idaho Power Company
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17
1 that's what you're asking us to do, the Commission to do,
2 you don't mention it and you haven't applied for CWIP or
3 AFUDC. Are you aware of that?
4 A Well, Commissioner, I view that if you
5 issue an order with a certificate that states that
6 potentially the Commission has a preference for CWIP of
7 the two tools, we could file for CWIP at the end of the
8 year. That's how I thought it would work. If CWIP was
9 going to be exercised as a tool, we'd finish the year,
10 file for CWIP at the end of the year and through
11 proceedings each year.
12 Q Under AFUDC or CWIP is there any monies
13 changed hands during construction; that is, are you
14 asking that rates be -- a surcharge be put on rates to
15 pay for CWIP when it's over the period of the
16 construction?
A I mean, with some direction in this Order
1S toward using CWIP, yes, we would file for rate changes
19 that would put all or part of the CWIP in as you work
20 through the project, but essentially, you're paying for
21 the proj ect in chunks.
22 Q So as the milestones in the proj ect are
23 met, you would ask for a rate change to recognize the
24 cost?
25 A Yes, sir.
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234 GALE (Com)
Idaho Power Company
.
.
17
1 Q I assume you wouldn't go into any of the
2 bidders or anything else or your EPC contractor, but have
3 you finalized an agreement with the EPC contractor?
4 A That I'm going to leave for another
5 witness.
6 Q Okay, and --
7 MR. KLINE: Mr. Porter.
8 THE WITNESS: Mr. Porter. That I'm going
9 to leave for Mr. Porter.
10 Q BY COMMISSIONER REDFORD: Okay, and so any
11 issues that might be in that contract would be better
12 asked of Mr. Porter?
13 A Yes, sir.
14 Q Okay. There was -- I realize that you
15 wanted the plant to be on-line June 1, 2012, hasn't that
16 date been slipped now to December of 2012?
A There's a little bit of a yo-yo there.
18 The original intent was to have it in June of 2012,
19 slipped it to December of 2012, but as we processed
20 through and talked with the -- and others can describe
21 this better, but as we've talked through, we believe
22 we're able to bring it back on-line in 2012, June of
23 2012.
24.25
Q June of 2012?
A Yeah.
CSB REPORTING
[phone]
235 GALE (Com)
Idaho Power Company
1 Q But for right now it looks like December.2 of 2012?
3 A I think that -- I believe this is
4 Mr. Porter as well. He can speak very specifically, but
5 I think it's in play.
6 Q That's fine. In the event you didn't have
7 the authority to build this plant and you had new
8 customers come on line, do you have the capacity to
9 purchase power and bring it to them, say, in the Treasure
10 Valley? Say you had a plant that came on that needed 25
11 megawatts and you don't have in your system the extra 25
12 megawatts, you would purchase that power and you would
.13 bring it to that customer, is that correct, and it would
14 be involved in the PCA then?
15 A That could be. I'd like to run with that
16 if i could, Commissioner. Having lived through the
17 energy crisis of 2000 and 2001, I know we're capable of
18 doing a lot of things quickly, including sticking diesel
19 generators in substations, so I know that we are
20 resilient, but the actual physical capabilities and what
21 we can bring in from where, Karl Bokenkamp understands
22 the system very well.
23 COMMISSIONER REDFORD: Okay. Well, I
24 don't have any more questions. Thank you very much,.25 Mr. Gale.
CSB REPORTING
[phone]
236 GALE (Com)
Idaho Power Company
.1
2
3 Smith.
4
5
6
THE WITNESS: Thank you.
COMMISSIONER KEMPTON: Commissioner
EXAMINATION
7 BY COMMISSIONER SMITH:
8 Q So Mr. Gale, this is a big case.
Yes.
I've been here a long time and this seems
11 like a really big case. Were you with the Company when
9 A
12 they proposed to build the Pioneer plant?
.
18
10 Q
13 A
14 Q
15 A
16 Q
17 Pioneer?
A
19 than Pioneer.
20
21
Q
A
No.
Okay, but you know about it?
Yes, I do.
Does anything about this remind you of
It actually reminds me more of Valmy II
In what way?
Valmy II was at a time when we were trying
22 to figure out where loads were going and we were on a
23 construction phase. It was actually after the Boardman
24 and so forth. We built Valmy I. We had Valmy II in.25 place just in time for a soft economy.
CSB REPORTING
[phone]
237 GALE (Com)
Idaho Power Company
.
.
1 Q This was in the '80s?
2 A Yes, early '80s, and it actually in my
3 mind, one of the assurances, I think, that can help the
4 Company build this plant now is to guard against that
5 soft economy in the future with the used and useful
6 argument after the thing is built.
7 Q And you mentioned the diesel generators in
8 2000, 2001.
9 A Everyone's favorite.
10 Q That was real popular, wasn' t it?
11 A It was. That's the opposite side of
12 things.
13 Q And they didn't really run, did they?
14 A I think every good thing we did in 2001 we
15 got spanked for.
16 Q But it still costs money?
17 A Yes, it does.
18 Q So in my thinking through this what I
19 really want to understand very clearly are the financial
20 consequences of the Commission saying we just don't think
21 the evidence is here to build it and we want more time.
22 Are you the person to help me understand clearly the
23 financial consequences of saying that?
24.25
A I think that most of the -- everyone of
the first four witnesses probably have a take on that. I
CSB REPORTING
[phone]
238 GALE (Com)
Idaho Power Company
.
.
.
15
1 think certainly the reliability is a big piece of it.
2 The ability to attract load is a piece of it.
3 Q For which you've been criticized publicly
4 by people for not having enough power and capacity to
5 attract new load.
6 A The financial consequences have been
7 discussed quite a bit in the testimony. There are
8 scenarios where it comes on and we are overcapacity and
9 the load hasn't quite caught up, I understand that. I
10 think the most compelling testimony is actually
11 Mr. Sterling's where he says the risk is asymetric. The
12 consequences of not being ready are more severe than
13 coming on too soon.
14 Q So you're not going to give me numbers?
A No, I'm not going to give you numbers.
16 I've talked about the rate impacts that we've run on do
17 nothing. I would underscore that every large customer
18 that we talk to, we talk about constraining them right
19 now and I think that's -- I mean, you could say well,
20 you're saying it, but you saw it in the Hoku contract, so
21 we have constraints that exist right now and then there
22 are all the other elements, I think, that are posi ti ve
23 about Langley that make it a compelling plant to me.
24
25 Mr. Chairman.
COMMISSIONER SMITH: Thank you,
CSB REPORTING
[phone] 239 GALE (Com)
Idaho Power Company
.
.
.
1 EXAMINATION
2
3 BY COMMISSIONER KEMPTON:
4 Q Mr. Gale, I have a couple of questions.
5 One of them, have you got your rebuttal testimony on
6 page 3, line 19? Let me know when you have it.
7 A Okay.
8 Q Okay, the language there says that it is
9 in the best interest of customers to have Langley Gulch
10 available in the summer of 2012 and the Company is
11 actually pursuing a strategy to make that happen. The
12 strategy will include an incentive payment, which I would
13 urge the Commission to include in the final determination
14 of the Company's commitment estimate. First question is,
15 is that currently included in the commitment estimate?
16 A No, I believe that the incentive is around
17 a million dollars. Mr. Porter can confirm that and the
18 reason I say that is I think if you could get it on-line
19 for the summer that the savings in net power supply costs
20 would dwarf that.
21 Q So the second question kind of brings up
22 the cost versus the reduction of uncertainty and that
23 question is when you made that determination to move
24 forward from December of 2012 forward to June, what that
25 effecti vely does, at least in my perception as a
CSB REPORTING
[phone]
240 GALE (Com)
Idaho Power Company
.
.
.
1 Commissioner looking at a decision on preapproval, is
2 that our time is more constrained in having to make that
3 decision ahead of the time that we would have the full
4 featured sales and load forecast that's done in mid
5 August, where the data comes in, so if the Company can
6 afford to back up by six months, the opposite side of
7 that coin in my mind would be that the Company would hold
S the December 12th date and that the Commission would then
9 have additional time, three or four months, to wait until
10 you had the data in August, had some preliminary
11 information in that before you incorporate it in an IRP,
12 we don't need the full IRP, but the update would be good,
13 and then go ahead and make a decision at that point. Do
14 you have a comment on that consideration?
15 A Well, my comment would be that whenever
16 you're going to have an extra piece of information, it's
17 hard to argue that you don't need that extra piece of
18 information. With this resource, there is always another
19 piece of information, another piece of information. I
20 would comment like I did with Commissioner Smith, I think
21 that the Langley Gulch project is compelling for a whole
22 variety of reasons and to have it available for the
23 summer of 2012 might be very desirable.
24 Q It's perhaps compelling, but I can ask
25 Mr. Porter or I can ask Mr. Bokenkamp to give a matrix of
CSB REPORTING
(20S) 890-5198
241 GALE (Com)
Idaho Power Company
.1 the considerations for where load isn't required now.
2 We've talked about Hoku and we've talked about
3 residential customers dropping off. We've talked about
4 Micron dropping off and we have estimates here and
5 estimates there. On the other side of that coin is the
6 issue that you have with the biological opinion on the
7 hydro system and the loss of power during the summer
8 months when you might need to use it because of flow
9 requirements. There's the Boardman-Hemingway issue.
10 There is the issue of, and I'LL ask
11 another question on this, of having a 50 percent carbon
12 ratio compared to a coal plant in operation where you can
.13 trade off the carbon depending on what comes out of the
14 Congress, but there hasn't been a point where we can look
15 at those and get the most information current, what is
16 actually happening, the summation of what actual loads
17 are.
18 There's an indication we've had this
19 morning that the forecast may actually be too low, that
20 we're having additional loads coming on, but the fact of
21 the matter is we don't have an answer to that and we
22 wouldn't have unless we could take a peak at some of the
23 information that comes in, and I used the terms of Idaho
24 Power, full featured sales and load forecast in mid.25 August.
CSB REPORTING
(208) 890-51~8
242 GALE (Com)
Idaho Power Company
.
.
.
1 Gi ven that kind of a survey of the issues,
2 why wouldn't it be important for the Commission in trying
3 to establish a preapproval process and to take the
4 responsibili ty of committing future Commissioners to a
5 rate base treatment, ratemaking treatment, why wouldn't
6 that be in the best interest of the public, again, to
7 have that opportunity to look at this information
8 sometime in the three-month, six-month period between
9 June and, say, September or October?
10 A Well, at the end of the day that will be
11 your deliberation on whether that August piece of
12 information is the tipping point. In my view, there are
13 many compelling reasons to move Langley forward so we can
14 have it in operation by the summer of 2012, and again, I
15 think the risk of not having it is disproportionate to
16 the risk of putting on a plant that might be a little
17 bigger or a little sooner than necessary.
18 Q Would you agree in that respect that as a
19 minimum, the Commission should then have an estimate of
20 the costs that are traded off between the points that
21 Mr. Sterling made and that is the pure cost estimate and
22 the risk estimate associated with those costs? Would it
23 be fair to say that the Commission should expect to have
24 some indication of the costs associated with
25 pre-Commission decision contract commitments by Idaho
CSB REPORTING
[phone]
243 GALE (Com)
Idaho Power Company
.1 Power related to EPC purchases, advance contracts, the
2 million dollars that you estimate on the incentive
3 contract to move to June and costs associated with
4 equipment purchases such as the Siemens turbine if we
5 extended another two or three months, some estimate of
6 what we're looking at if in fact the Commission were to
7 decide to slip a decision for three or four months,
8 because right now no one has given us that kind of
9 information that I know of, would that be a fair
10 expectation on the part of the Commission?
11 A First of all, I would encourage you to
12 question thoroughly the two witnesses coming up that are
.13 engineering-related to see if you cannot extract the
14 information that you need while we're at this hearing
15 ultimately if this is information that is holding you
16 up.
17 Q I was just giving you a chance to express
18 yourself.
19 A Thank you.
20 Q My last question and I will address this
21 to Mr. Bokenkamp and Mr. Porter, but the question of
22 using the gas plant as a tool to reduce the amount of
23 carbon emissions that the Company may be subjected to in
24 terms of Congressional legislation, what would be the.25 process -- how would that be done because we're in a
CSB REPORTING
[phone]
244 GALE (Com)
Idaho Power Company
.1 joint venture on a coal plant. Coal plants can't just be
2 trimmed down because somebody wants to step out of them.
3 What mechanism would you use that has any assurances to
4 it that you could actually do that, trade off your
5 natural gas plant for coal?
6 A Well, I would say Mr. Bokenkamp is very
7 knowledgeable on this, but I would offer you one example.
8 You could as carbon legislation emerges or as a carbon
9 plan might emerge that you would endorse, the distinction
10 being something that the Company would bring forward that
11 you would agree with or legislation comes forth and we
12 have to act, you could end up with a redispatch so that
.13 the coal plants are dispatching at a higher cost because
14 of either a premium that we would put on it potentially
15 out of an IRP process or from legislation. I mean,
16 that's one way that you could have shifting between the
1 7 resources.
18 COMMISSIONER KEMPTON: I don't have any
19 other questions. Mr. Kline, I think that pretty well
20 sums it up. The witness is free to step down.
21 THE WITNESS: Thank you.
22 COMMISSIONER KEMPTON: I'm sorry, how
23 about redirect, would you like redirect?
24 MR. KLINE: Well, maybe --.25 COMMISSIONER KEMPTON: I don't want to
CSB REPORTING
[phone]
245 GALE (Com)
Idaho Power Company
.
.
16
1 fumble this too many times. Staff can stand it, but i
2 don't think Idaho Power can, but would you like redirect?
3 MR. KLINE: I have just two or three
4 questions and I think they're worth doing.
5
6 REDIRECT EXAMINATION
7
8 BY MR. KLINE:
9 Q Mr. Gale, there's been quite a bit of
10 discussion during the course of your cross-examination
11 regarding the potential for new large loads; correct?
12 A Yes.
13 Q And those are customers that are what
14 size, Mr. Gale?
15 A Above 25 megawatts.
Q What about customers below 25 megawatts,
17 say a rate 19 customer, how big can they be and qualify
18 for those rates?
19 A Well, the 25 megawatts is the boundary
20 between special contracts which we bring individually to
21 the Commission. We can customize them. There's a lot of
22 flexibili ty in my mind for special contracts. Then up to
23 25 is -- from 1 megawatt up to 25 megawatts is served
24 under tariff which is Schedule 19. It's tariff service,.25 standard service.
CSB REPORTING
[phone]
246 GALE (Di)
Idaho Power Company
.
.14
1 Q And there's no negotiation of the
2 contracts for those folks, they just show up and say I'm
3 going to sign the uniform agreement and they're a
4 customer; right?
5 A Yeah, I don't believe they even sign
6 uniform agreements anymore.
7 Q That's probably right. I've been here too
8 long. Well, suppose that you have six 15 megawatt
9 customers show up, I mean, that's 90 megawatts just like
10 that and they could show up the day after tomorrow;
11 correct?
12 A Yes, your math is correct and they can
13 show up and ask for tariff service.
Q How does Idaho Power's rates for those
15 kinds of customers, not special contract customers, but
16 for Schedule 19 customers, how do the Company's rates for
17 those kinds of customers compare to rates charged by
18 other utilities?
19 A Well, our industrial tariff rates and our
20 special contract rates, other than Hoku, are among the
21 very lowest in the country for investor-owned
22 utili ties.
23 Q And with those kinds of rates, do you have
24 any opinion as to whether there's a likelihood that those.25 smaller customers might show up as well?
CSB REPORTING
[phone]
247 GALE (Di)
Idaho Power Company
.
.
18
1 A There is a likelihood. Those aren't
2 typically ones I engage with, but our deli very folks talk
3 to all the time.
4 Q Commissioner Redford asked you a couple of
5 questions about the schedule for IRPs and I just want to
6 make sure I'm clear on your answer. Is the schedule for
7 the full featured -- how often do we file the full
8 featured IRPs?
9 A The full IRP has been on a two-year
10 schedule for as long as I can remember and we happened to
11 get off it in trying to accomplish the synchronization
12 wi th the utili ties.
13 Q But we're back on a two-year schedule
14 now?
15 A To my knowledge, yes.
16 Q And in the in-between years, do we file
17 something?
A Well, I know that we filed the update.
19 Going back in time, I do not recall making filings in the
20 in-between years. It's just a long process. I don't
21 recall making filings in there.
22 Q Would you accept, subject to check, that
23 we now are required to file one in the off years?
24.25
A Sure.
MR. KLINE: Thank you. That's all I have.
CSB REPORTING
[phone]
248 GALE (Di)
Idaho Power Company
.
.
1 COMMISSIONER KEMPTON: I have one question
2 that your question, your rebuttal question, brought up.
3 MR. KLINE: Okay.
4 COMMISSIONER KEMPTON: It has to do with
5 the IRPs. The original IRP was set for June of whatever
6 year, 2009, at the time it was done back in 2007 and that
7 was at the Commission's order to try and phase something
8 in more balanced with Rocky Mountain Power and Avista.
9 MR. KLINE: That's my recollection, yes.
10 COMMISSIONER KEMPTON: Right, and so now
11 on our biennial schedule, are we on a December schedule
12 as adverse to a June schedule that was originally time
13 phased that way?
14 MR. KLINE: If my client asked me what I
15 thought the schedule for the next IRP would be, I would
16 say it's June of '11.
17 COMMISSIONER KEMPTON: In that case, we
18 would be in a situation where we're continuing to have
19 the IRP done at a time after the Commission would -- we
20 would have the IRP scheduled to be finished at a time
21 that the next full service sales and load schedule would
22 be done in August, so it seems to me you have competing
23 obj ecti ves or the Commission may, I wasn't here the first
24 time around, but one of them between the time when you.25 typically get your full service download for sales and
CSB REPORTING
[phone]
249 GALE (Di)
Idaho Power Company
.
.
1 load and the other one is the time phasing with the other
2 two utilities in the region, and it would seem to me that
3 in fact now that we have a December 2009 IRP scheduled
4 that those two questions should probably come forward. I
5 don't know that they pertain directly to this hearing,
6 but they certainly pertain to the issues that this
7 hearing presents.
8 MR. KLINE. I certainly wouldn't quarrel
9 wi th that and I would recommend that you raise that
10 question with Mr. Bokenkamp. He's in charge of the IRPs
11 and he can talk you to more intelligently about the
12 logistical problems of when you get a load forecast and
13 when you have to have an IRP done.
14 COMMISSIONER KEMPTON: That having been
15 said, the witness is free to step down.
16 (The witness left the stand.)
17 COMMISSIONER KEMPTON: I was seeing the
18 gleam in people's eyes and one has already departed, so
19 let's take a ten-minute break.
20
21
22
MR. KLINE: Thank you.
(Recess. )
23 come to order. Mr. Kline.
COMMISSIONER KEMPTON: The hearing will
.24
25
MR. KLINE: Before we bring on our next
wi tness, Mr. Chairman, I do need to correct an error that
CSB REPORTING
[phone]
250 GALE (Di)
Idaho Power Company
.
.
20
21
1 came up in my response to your question regarding the
2 schedule for the IRPs and my question to Mr. Gale as
3 well. The requirement that we file -- the requirement
4 still remains that every two years we file the full IRP.
5 In the years between the full IRPs there is a requirement
6 in Oregon that we file an update. That is not an Idaho
7 requirement and, of course, if we're filing one in
8 Oregon, we're certainly going to file it here as well,
9 but I misspoke and wanted to correct that.
10 COMMISSIONER KEMPTON: Okay; so it's
11 entered in the record.
12 MR. KLINE: All right, Idaho Power's next
13 witness is Karl Bokenkamp.
14
15 KARL BOKENKAMP,
16 produced as a witness at the instance of the Idaho Power
17 Company, having been first duly sworn, was examined and
18 testified as follows:
19
DIRECT EXAINATION
22 BY MR. KLINE:
23
24.25
Q Could you please state I'm sorry.
COMMISSIONER KEMPTON: Go ahead.
Q BY MR. KLINE: Could you please state your
CSB REPORTING
[phone]
251 BOKENKAP (Di)
Idaho Power Company
1 name and spell your last name for the record?.2 A Karl Bokenkamp, B-o-k-e-n-k-a-m-p.
And by whom are you employed and in what
4 capaci ty, Mr. Bokenkamp?
3 Q
I'm employed by Idaho Power Company and
6 I'm their general manager of power supply operations and
5 A
And are you the same Karl Bokenkamp that
9 prefiled direct and rebuttal testimony in this case?
7 planning.
8 Q
Yes, I am.
12 through 4 and Exhibit 10?
And did you also prefile Exhibits 1
.
10 A
Yes.
Do you have any additions or corrections
15 that you need to make to your prefiled testimony and/or
18
11 Q
Yes, I do. I have a couple.
19 they're located.
Why don't you go ahead and tell us where
20
13 A
The first one would be on my direct
21 testimony, page 17, line 5. I would like to strike the
14 Q
22 second word "also" and insert "after Northwest Pipeline
16 exhibits?
17 A
Q
A
23 and others. II
24.25
Q
correction?
All right, does that complete that
CSB REPORTING
[phone]
252 BOKENKAMP ( Di)
Idaho Power Company
.1 A Yes, it does.
All right, what's the next one?
The next one is on my direct rebuttal
4 testimony, page 7, line 16, and it would be to insert
2 Q
5 after the word "purchases" to insert "from the Pacific
3 A
Is there another one?
9 page 18, line No.9, and it would be to insert after the
Yes, again, direct rebuttal testimony,
.
6 Northwest. II
7 Q
The first "AURORA"?
The first "AURORA" in that line, yes.
Go ahead.
"And the revenue requirements model. II
15 Excuse me on that. Let's make that "and the revenue
8 A
16 requirements" and then to make "model" plural.
1 7
18
19
10 word "AURORA"
11 Q
Correct. Any more?
There's one other one on Exhibit 10.
20 rebuttal testimony?
And that's the exhibit that goes with your
21
12 A
Yes, that's the load and resource balance.
22 There was an error on one of the calculations that
13 Q
23 adjusted the -- that was in the line that says "Recent
14 A
24 Changes (Irrigation) II in parentheses..25
Q
A
Q
A
COMMISSIONER SMITH: What page?
CSB REPORTING
[phone]
253 BOKENKAP (Di)
Idaho Power Company
.
.
17
1 THE WITNESS: It's actually on -- let me
2 find that. Just a minute.
3 Q BY MR. KLINE: Is it on Exhibit 10, page 1
4 of 9?
5 A It's actually on several pages of Exhibit
6 10, so it would be on pages 5, 6, 7, and 8 of Exhibit 10
7 and the change is to -- is that each of the numbers that
8 were subtracted under the August column, so the negative
9 number that shows up, so on page 5 of 9 --
10 COMMISSIONER SMITH: August of 2009 or
11 2010?
12 THE WITNESS: August of each of those
13 years, so it would be of '09, '10, '11, '12 throughout
14 the peak hour load balance. We actually subtracted off
15 24 megawatts too much for the August adjustment to the
16 irrigation, in the irrigation change line.
Q BY MR. KLINE: Okay; so where is the
18 irrigation change line?
19 A It says "Recent Changes II in parentheses
20 II (Irrigation) II near the bottom. It's about the fourth
21 line up from the bottom.
22
23
Q Okay; so it's a negative number, "136"?
A Yes, the negative "136" should actually be
24 24 megawatts higher than that, so you just have to add 24.25 megawatts to the negative 136.
CSB REPORTING
[phone]
254 BOKENKAP (Di)
Idaho Power Company
.
.
1 COMMISSIONER SMITH: Do that for us.
2 Q BY MR. KLINE: So negative what?
3 A It would be negative "112."
4 Q Okay, and continuing on that same page, is
5 there another one for August '10?
6 A Yes, you'd add 24 megawatts to that one,
7 so the negative "180" would be, you would add 24
8 megawatts to that as well.
9 Q So what would that be for those of us who
10 aren't that quick doing it in our heads?
11 A "156, II negative "156. II
12 Q Negative "156, II okay.
13 A On page 6 of 9, the negative "225" would
14 change to negative "201, II and the negative "225" under
15 2012 would also change to negative "201" and likewise,
16 for the -- on page 7 of 9, both of those would change to
17 negative "201," and the same on page 8 of 9.
18 Q Okay, do you have any other changes that
19 you need to make to your testimony or exhibits?
20 A Well, I didn't work those out, but the
21 changes propagate through to the bottom line on that
22 surplus/deficit balance.
23 Q So you'd have to change the monthly
24 surplus/deficit as well?.25 A Yes.
CSB REPORTING
[phone]
255 BOKENKAMP (Di)
Idaho Power Company
.
.
17
18
1 Q Did you do that calculation?
2 A I didn't.
3 Q You probably better.
4 A I'd need to do a few checks on the page
5 for 2009 and '10 just because we don't show a deficit
6 there and I'm not sure whether that would have pushed it
7 over zero or not. I'd have to check that. For 2011 and
8 '12, 2011 since we're negative at "99," you'd add 24 to
9 that, so it would be negative "75. II
10 Q Which one is that, Karl? I'm wondering if
11 it might be better for us to just get some substitute
12 pages. I apologize, I didn't realize
13 A I can do that.
14 MR. KLINE: If it becomes a problem in
15 cross-examination, we'll bring Mr. Bokenkamp back, if
16 that's acceptable.
COMMISSIONER KEMPTON: It's acceptable.
THE WITNESS: There's one other point on
19 that is that it would also flow through to the graph on
20 the last page of the exhibit.
21 COMMISSIONER KEMPTON: Mr. Kline, why
22 don't we go ahead and try to get some additional charts
23 in here.
24.25
MR. KLINE: Right now?
COMMISSIONER KEMPTON: No.
.
CSB REPORTING
[phone]
256 BOKENKAMP (Di)
Idaho Power Company
.
.
17
1 MR. KLINE: Oh, yeah, I'LL bring them just
2 as fast -- probably tomorrow morning.
3 COMMISSIONER KEMPTON: All right.
4 Q BY MR. KLINE: All right, is that the last
5 correction, Karl?
6 A Yes.
7 Q All right. All right, Mr. Bokenkamp, with
8 those corrections, if I were to ask you the same
9 questions contained in your direct and rebuttal testimony
10 today, would your answers be the same?
11 A Yes.
12 MR. KLINE: All right. Mr. Chairman, I
13 would move that the prefiled direct and rebuttal
14 testimony as corrected be spread on the record as if read
15 and Exhibits 1 and 4 and Exhibit 10 as corrected be
16 marked for identification.
COMMISSIONER KEMPTON: If there is no
18 objection, so ordered.
19 (The following prefiled direct and
20 rebuttal testimony of Mr. Karl Bokenkamp is spread upon
21 the record.)
22
23
24.25
CSB REPORTING
[phone]
257 BOKENKAP (Di)
Idaho Power Company
1 Q.Please state your name and business address..2 A.My name is Karl Bokenkamp and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity.
5 A.I am employed by Idaho Power Company as the
6 General Manager of Power Supply Operations and Planning.
7 Q.Please describe your educational background.
8 A.I received a Bachelor of Science Degree in
9 Mechanical Engineering from the Uni versi ty of Illinois at
10 Urbana-Champaign in 1980. In 1995, I earned a Master of
11 Engineering Degree in Mechanical Engineering from the
12 Uni versi ty of Idaho. I am a registered Professional
.13 Engineer in the state of Arizona, and I have attended the
14 Stone & Webster Utility Management Development Program
15 and the Uni versi ty of Idaho's Utili ty Executive Course.
16 Q.Please describe your work experience with Idaho
1 7 Power Company.
18 A.I became employed by Idaho Power in 1995 as the
19 Director, and then Manager, of Thermal Production. In
20 this position I was responsible for managing Idaho
21 Power's Thermal Production Department. Primary
22 responsibili ties of the department included oversight and
23 control of Idaho Power's ownership shares in its three
24 jointly-owned coal-.25
258 BOKENKAMP, DI 1
Idaho Power Company
.1 fired generation resources, Bridger, Boardman, and Valmy,
2 and their associated fuel supplies.
3 In 2001, I accepted a new assignment as the
4 Manager of Power Supply Planning and was later promoted
5 to General Manager of Power Supply Planning. In this
6 position, I was responsible for building and managing
7 Power Supply's Planning Department. This department's
8 responsibili ties included operational planning, load
9 forecasting, stream flow forecasting, integrated resource
10 planning, cogeneration and small power producer contract
11 management, water management/river operations, and gas
12 and coal contract management.
13 In 2006, I was promoted to my current position.14 of General Manager, Power Supply Operations and Planning.
15 This position adds operational responsibilities, which
16 include asset optimization, wholesale electricity, and
17 natural gas transactions from real-time through
18 multi-year deals as well as real-time operations and
19 scheduling.
20 Q.Please outline the maj or topics you will
21 address in your testimony in this proceeding.
22 A. There are three major topics that comprise my
23 testimony. First, I will briefly review how the addition
24 of a baseload resource like the Langley Gulch power plant.25 ("Langley Gulch" or "Project") is consistent
259 BOKENKAMP, DI 2
Idaho Power Company
.
.
1 with the Company's 2006 Integrated Resource Plan and 2008
2 Update. Second, I will provide an overview of the
3 Request for Proposal ("RFP") process used to evaluate the
4 various resources that competed to provide the baseload
5 resource. Finally, I will explain why the Proj ect was
6 selected as the least-cost resource through the
7 competi ti ve RFP process.
8 Q.What drives the need for Idaho Power to acquire
9 addi tional resources?
10 A.Load growth wi thin Idaho Power's service
11 territory is primarily what drives the need for new
12 generating resources. In 1990, Idaho Power had
13 approximately 290,000 retail customers, and a firm
14 peak-hour load of less than 2,100 MW. Today, Idaho Power
15 serves over 480,000 retail customers in Idaho and Oregon,
16 and firm peak~hour load has grown to over 3,200 MW.
17 Average firm load has increased from approximately 1,200
18 aMW in 1990 to over 1,800 aMW in 2008.
19 Q.What role does the Company's integrated
20 resource planning process play in determining the need
21 for the acquisition of a base load resource?
22 A.The Company's integrated resource planning
23 process is the basis for establishing the Company's need
24 for the acquisition of additional resources. The IRP.25 considers supply-side resources (generators and market
260 BOKENKAMP, DI 3
Idaho Power Company
.1 purchases), demand-side resources (energy efficiency or
2 demand response programs) ~ and the transmission lines
3 necessary to integrate these resources. Because of the
4 Company's reliance on its hydroelectric generation, its
5 operations can be significantly affected by water
6 conditions. With this in mind, the Company's IRP
7 utilizes two planning criteria, one for average load or
8 energy and another for peak-hour load, and both are based
9 on receiving less than normal streamflows. For energy,
10 Idaho Power plans to be able to serve its average loads
11 under 70th percentile water and 70th percentile load
12 condi tions. For peak-hour load, Idaho Power plans to
13 serve its peak-hour loads under 90th percentile water and.14 95th percentile load conditions.
15 The preferred portfolio in the 2004 IRP
16 included a 500 MW baseload coal-fired resource, with
17 seasonal ownership, in 2011. The preferred portfolio in
18 the 2006 IRP refined this resource need to a 225 MW power
19 purchase facilitated from what we called a McNary to
20 Boise transmission upgrade in 2012, a 250 MW pulverized
21 coal baseload resource in 2013 and a 250 MW Regional IGCC
22 (or "clean coal") project in 2017. Since the 2006 IRP
23 was published, escalating concerns regarding climate
24 change, C02 emissions and the public's perception of.25 coal-fired resources has made coal-fired
261 BOKENKAP, DI 4
Idaho Power Company
.1 resource development an unrealistic al ternati ve. These
2 concerns coupled with the possibility of new large loads
3 locating in our service terri tory and the anticipated
4 shift of flow augmentation releases of water from the
5 federal dams on the Snake River above Brownlee Dam from
6 July and August to May and June, have prompted the
7 Company to (1) revise the 250 MW coal-fired resource to a
8 natural gas-fired baseload resource, (2) increase the
9 size of the baseload resource to approximately 300 MW,
10 and (3) accelerate the on-line date of the baseload
11 resource to 2012.
12 Q.Why did the Company decide to utilize a.13 competi ti ve request for proposals or RFP process to
14 acquire the baseload resource previously described in
15 your testimony?
16 A.The competi ti ve RFP process allows the Company
17 to access the broader power supply market to obtain the
18 best resource for our customers. It gives us access to a
19 spectrum of potential resources and resource developers.
20 Use of a formal RFP process provides customers and
21 regulatory agencies with the assurance that the resource
22 selection process was competitive, all potential
23 suppliers had an equal opportunity to participate, and
24 that the best resource alternative was selected..25
262 BOKENKAMP, DI 5
Idaho Power Company
.
.
1 Q.Did the Company engage an independent
2 third-party to review the Company's RFP and bid
3 evaluation process?
4 A.Yes. The Company retained R. W. Beck, an
5 independent consulting company offering a complete range
6 of consulting and engineering services to the utility
7 industry, to assist us with the RFP process.
8 Specifically, R. W. Beck was retained to assist with
9 preparation of the RFP, the draft power purchase and
10 tolling agreements, development of the evaluation
11 criteria and manual, and evaluation of the proposals
12 recei ved in response to the RFP, including the self-build
13 al ternati ve. Mr. Steven Stein, R. W. Beck Principal &
14 Executi ve Consultant, was R. W. Beck's proj ect manager
15 and the principal consultant involved in supporting our
16 RFP process.
17 Q.Please describe the parameters the Company set
18 for the responses to the RFP.
19 A.The parameters set for this RFP can be grouped
20 into four categories; product, quantity, proposal size,
21 and term. The product was specified as dispatchable,
22 first call, non-recallable, physically delivered firm, or
23 unit contingent energy, commencing not later than June 1,
24 2012, that is dedicated solely to Idaho Power's use. The.25 RFP indicated that the product requirements could be met
263 BOKENKAP, DI 6
Idaho Power Company
.
.
17
1 through Power Purchase Agreements ("PPA") or Tolling
2 Agreements ("TAli). The RFP also advised that the Company
3 would include in the bidding process a Company-developed
4 CCCT that would provide a benchmark resource for
5 consideration. Build-and-transfer proposals were not
6 considered in this RFP process. The quantity of
7 dispatchable firm or unit contingent energy requested was
S initially specified as between approximately 250 MW and
9 600 MW. On June 25, 200S, the quantity was revised to
10 approximately 300 MW. The minimum and maximum proposal
11 sizes were initially specified as 50 MW and approximately
12 600 MW, respectively. When the quantity was revised to
13 approximately 300 MW, the maximum proposal size also was
14 adj us ted to approximately 300 MW. Regarding term, each
15 respondent was required to submit one proposal with a
16 term of 15 years and 1 five-year renewal option.
Q.Why didn't the Company allow build-and-transfer
1S proposals?
19 A.When the Company made the decision to pursue a
20 combined cycle project, Company employees visited a
21 number of combined cycle proj ects. During these site
22 visits, Company employees observed significant design
23 differences between similar sized projects. Simply put,
24 some designs were much better than others..25
264 BOKENKAMP, DI 7
Idaho Power Company
.
.
1 If a build-and-transfer option was permitted,
2 and proj ects with significant design differences were
3 proposed, the evaluation process could become extremely
4 complicated and somewhat subj ecti ve. The Company
5 concluded that the best way to eliminate significant
6 design differences between the proposals and assure an
7 effecti ve evaluation process was to prepare and issue a
8 detailed specification with the RFP to ensure uniform
9 design criteria between proj ects.
10 Given the decision to accelerate the on-line
11 date to 2012, information obtained regarding critical
12 equipment manufacturing lead times, and the
13 aforementioned differences in proj ect design, in the
14 Company's opinion, it did not have enough time to prepare
15 a detailed design specification and release the RFP in
16 time to meet the 2012 on-line date.
17 Q.Please describe the response the Company
18 received to the RFP.
19 A.The Company received six proposals. One
20 proposal was returned unopened because the bidder did not
21 submi t a Notice of Intent to Bid as required by the RFP.
22 The five remaining valid proposals represented a total of
23 thirteen al ternati ve resources. The alternatives
24 included:.25
265 BOKENKAP, DI 8
Idaho Power Company
.1 one Power Purchase Agreement, nine TAs, two hybrid
2 proposals, and the Benchmark Resource.
3 The nine TAs offered included three different
4 technology classes; three TAs were for large frame simple
5 cycle CTs, two TAs were for advanced aeroderi vati ve
6 simple cycle CTs, and five TAs were for 1 x 1 combined
7 cycle CTs.
8 Q.Please describe the process the Company
9 followed to evaluate and rank the responses to the RFP.
10 A.The process the Company followed to evaluate
11 and rank the responses received in response to the RFP is
12 outlined in the Proposal Evaluation Manual prepared for.13 the 2012 Baseload Generation RFP. The Proposal
14 Evaluation Manual was finalized before any of the
15 proposals were received. The evaluation process can be
16 characterized as a three stage screening process.
17 In stage 1 screening, proposals were checked
18 against the minimum requirements set forth in the RFP.
19 This screening involved checking proposals for completed
20 forms, minimum quantities, minimum term, addressing
21 environmental costs, an Interconnection Feasibility Study
22 Report, and signatures.
23 At the Stage 2 screening level, a busbar
24 analysis was used to determine the cost of each proposal..25 Levelized
266 BOKENKAMP, DI 9
Idaho Power Company
.1 fixed, variable and total costs, and non-levelized total
2 costs at various capacity factors were calculated.
3 During Stage 3 screening, price and non-price
4 factors, or criteria, were scored for each proposal using
5 a weighted scoring system. The price factors received a
6 total of 60 points. Price factors were based on the net
7 present value ("NPV") of the estimated total revenue
8 requirement associated with each proposal. Each proposal
9 making it to Stage 3 screening was modeled and its impact
10 on Idaho Power's system costs was simulated using the
11 Aurora Electric Market Model. The results of the Aurora
12 analysis were used to determine the NPV of the revenue.13 requirements associated with adding that project to Idaho
14 Power's portfolio of resources. Non-price factors
15 received a total of 40 points. Non-price criteria
16 included: project development, project characteristics,
17 product characteristics, project location, environmental,
18 credit factors, and financial strength. A total of 40
19 points were distributed between these six non-price
20 cri teria. Sensi ti vi ty analyses were run for high and low
21 gas price scenarios, but these results did not impact the
22 price and non-price scores.
23 Q.How did the Company address transmission costs
24 in the RFP process?.25
267 BOKENKAP, DI 10
Idaho Power Company
.
.
.
1 A.One of the minimum requirements of the RFP was
2 that proposals relying on a new generating resource to be
3 developed in Idaho Power's service terri tory were
4 required to submit an Interconnection Feasibility Study
5 report prepared by Idaho Power's Deli very Planning group
6 with their proposal. The cost estimates provided by
7 Idaho Power's Deli very Planning group in the
8 Interconnection Feasibility Study Reports or, in one
9 case, a System Impact Study were used to set the
10 transmission costs of each proposal.
11 Q.What fuel cost assumptions were used in
12 evaluating the bids?
13 A. The same assumptions for the cost of fuel
14 delivery to the Northwest Pipeline mainline tap, in
15 $/MMBtu, were used to evaluate all proposals, including
16 the Benchmark Resource. Any costs from the main line tap
17 to the proposed resource locations were considered to be
18 proj ect specific. The natural gas price forecast used to
19 evaluate bids showed an increase from $9. 39/MMBtu in 2012
20 to $15. 55/MMBtu in 2036. This forecast is provided as
21 Exhibit NO.1.
22 Q.How was the cost of AFUDC evaluated for the
23 Benchmark Resource?
24
25
268 BOKENKAP, DI 11
Idaho Power Company
.
.
.
1 A.The benchmark proposal included an estimate of
2 AFUDC costs expected to be incurred during the
3 construction of the proj ect. The Benchmark Resource
4 team's AFUDC estimate was calculated by applying a 7
5 percent annual capitalized interest charge to the funds
6 spent on construction of the project. The estimated
7 AFUDC costs were added to the accumulated construction
8 work in progress balances each month. The total amount
9 of AFUDC included in the plant portion of the Benchmark
10 Resource evaluation was approximately $49 million. For
11 the Benchmark Resource proposal, this amount was included
12 in the capitalized cost of the proj ect, which was used to
13 calculate the estimated revenue requirement for the
14 Benchmark Resource.
15 Q.How do the total costs of the selected Langley
16 Gulch Project compare to the other bids received by the
17 Company in response to the RFP?
18 A.Exhibi t No. 2 shows the total revenue
19 requirement for each of the three short-listed CCCT
20 projects. The Benchmark Resource is Project D. Exhibit
21 No. 3 shows the 20 year net present value ("NPV") of the
22 difference in revenue requirement between the
23 short-listed three CCCT projects.
24 Q.What does Exhibit No. 3 show?
25
269 BOKENKAMP, DI 12
Idaho Power Company
.
.
1 A.Exhibit No. 3 shows that the 20-year NPV of the
2 revenue requirements for the Langley Gulch Proj ect were
3 $108 million less than the next closest combined cycle
4 proj ect on the short-list. To put the $108 million
5 difference in perspective, it is about 3.8 percent less
6 than the 20-year NPV of the revenue requirements of the
7 combined cycle proj ect finishing in second place.
8 Q.Do Exhibits Nos. 2 and 3 reflect the Company's
9 Commi tment Estimate amount?
10 A.No. The comparisons shown in these exhibits
11 are based on the final costs submitted by the
12 short-listed bidders. However, I do not believe use of
13 the Commitment Estimate in the comparison would change
14 the ranking of the bids.
15 Q.How did the non-price attributes compare among
16 the various responders to the RFP?
17 A.Although each project was unique, overall, the
18 non-price scoring for the short-listed projects was
19 actually quite close. Less than 3 points separated the
20 non-price scores for all of the short-listed projects and
21 less than 2 points separated the non-price scores of the
22 short-listed combined cycle proj ects. Out of a possible
23 40 non-price points, the scores for the short-listed
24 combined.25
270 BOKENKAP, DI 13
Idaho Power Company
.
.
.
1 cycle projects ranged from 30.1 to 28.6. In this RFP,
2 the non-price scores were not a significant
3 differentiator.
4 Q.Why did the Company ultimately select the
5 Langley Gulch Proj ect as the preferred bidder?
6 A.The Company's ultimate decision to select the
7 Langley Gulch Proj ect, based on the results of the RFP,
8 was primarily dictated by its substantially lower price.
9 The differential between the 20 year NPV of the revenue
10 requirements of the Langley Gulch and the closest Tolling
11 Agreement for a combined cycle project shows the second
12 place project was approximately $108 million more
13 expensi ve, and the NPV analysis for the Tolling Agreement
14 for the third-place combined cycle proj ect was $220
15 million more expensive than the Langley Gulch Proj ect.
16 Exhibi t No. 3 shows this differential graphically.
17 Q.Are there any unique issues associated with a
18 utili ty-owned resource?
19 A.There are certain risks and benefits associated
20 with selecting a traditional utility rate-based project.
21 By selecting the Langley Gulch Project and providing a
22 Commitment Estimate, the Company and its shareholders
23 take on project development and construction risk.
24 Customers retain the risk of fuel cost increases under
25 ei ther a tolling agreement or a utility-owned
271 BOKENKAP, DI 14
Idaho Power Company
.
.
1 resource. However, with the utility-owned resource, any
2 savings resulting from the Proj ect realizing a better
3 than expected heat rate will be shared with customers
4 through the PCA. That leaves the risk that the Company
5 may not be able to operate and maintain the Proj ect as
6 efficiently as another operator. While this is a
7 possible risk, conversely, if the Company is able to
8 operate and maintain the Proj ect for less than its
9 anticipated costs, customers will have an opportunity to
10 recei ve those savings. The potential operating risk
11 needs to be balanced against the possible operating
12 savings, plus the benefit of a projected 20 year NPV
13 reduction in revenue requirement of $108 million, plus
14 the residual value associated with the Langley Gulch
15 Proj ect at the end of 20 years. It is the Company's
16 conclusion that the above-described benefits to customers
17 outweigh the risks associated with developing and
18 operating a traditional utility rate-based proj ect.
19 Q.The Company's 2006 IRP ten year resource plan
20 recommends that a baseload resource be on-line in 2012.
21 What is the schedule for the Project's commercial
22 operation date?
23 A.Ini tially, the 2012 base load resource was
24 expected to be on-line in time to meet peak-hour loads.25 during the summer of 2012. However, given the current
272 BOKENKAMP, DI 15
Idaho Power Company
.
.
19
1 economic crisis, the Company anticipates difficulty
2 financing this proj ect wi thout receiving a Certificate of
3 Public Convenience and Necessity ("CPCN") with specific
4 ratemaking or cost-recovery assurances. The Company
5 estimates that it may take up to 6 months to obtaining a
6 CPCN containing the needed regulatory assurances.
7 Acknowledging the IPUC' s need to carefully consider the
8 Company's request, the Company has negotiated with the
9 Langley Gulch Project's EPC contractor to postpone
10 additional expenditures until a CPCN is received.
11 Unfortunately, postponing additional expenditures for 6
12 months is expected to delay the project's on-line date by
13 6 months. Assuming that a Notice to Proceed is issued on
14 September 1, 2009, the project is expected to be on-line
15 in October 2012, and in commercial operation on December
16 1, 2012.
17 Q.How is the fuel supply delivered to the
18 project?
A.Ideally, Idaho Power would like to have the
20 ability to access and deliver natural gas from both the
21 Western Canadian Sedimentary Basin (British Columbia and
22 Alberta) and the U. S. Intermountain West, or Rockies
23 region. Idaho Power has transportation rights on
24 Williams' Northwest Pipeline from Sumas, Washington, to.25 Elmore,
273 BOKENKAMP, DI 16
Idaho Power Company
.
.
15
1 Idaho. Idaho Power also has committed to acquire
2 addi tional transportation rights on Northwest Pipeline
3 from Stanfield, Oregon, to the Boise area and we are
4 investigating the acquisition of additional
5 transportation rights, after Northwest Pipeline and
6 others, from the Rockies region to the Boise area. Idaho
7 Power intends to deliver natural gas to the Proj ect site
8 via Williams' Northwest Pipeline. Northwest Pipeline
9 will be tapped and a short lateral line, approximately 1
10 mile in length, will be constructed to connect the
11 Proj ect to Northwest Pipeline.
12 Q.Were there other material considerations that
13 should be considered when reviewing the Company's bid
14 evaluation process?
A.Yes. There are two items that I would like to
16 stress. The first is imputed debt. The RFP evaluation
17 process did not assign any additional costs to the PPAs
18 or TAs to cover the costs Idaho Power would incur by
19 issuing additional equity to maintain its debt and equity
20 ratios if the rating agencies imputed additional debt on
21 Idaho Power's balance sheet as a result of entering into
22 a long-term PPA or TA.
23 The second item is treatment of the costs
24 associated with not selecting the Langley Gulch Benchmark.25 Resource. While the Company recognizes that there may be
loss of
274 BOKENKAMP, DI 1 7
Idaho Power Company
.
.
18
19
20
21
1 equipment deposits, reservation fees, cancellation
2 charges, and other penal ties or costs that Idaho Power
3 would incur if the Benchmark Resource was not selected,
4 these potential costs were not considered in the bid
5 evaluation. If a~l other things were equal, PPA or TA
6 proposals would not have had to win by more than Idaho
7 Power's cancellation costs to have been considered the
8 winner.
9 Q.Did R. W. Beck provide a written assessment of
10 the Company RFP process?
A.Yes.A copy of their assessment is attached as
Exhibit No.4.
Q.What did R.W.Beck conclude concerning the
quality of the Company's RFP process?
11
12
13
14
15 A.R. W. concluded:
16 Finally, based on our work with the Idaho Power
RFP Evaluation Team as described above, we
believe that the Idaho Power 2012 Baseload RFP
process was conducted fairly and properly and
that offers provided to Idaho Power as part of
the RFP process, including the Benchmark
Resource, were treated objectively and
consistently as set forth in Section 5.5 of the
RFP. (R. W. Beck Report, p. 3.)
17
Q.Are there other attributes of the Langley Gulch
22 Proj ect that you believe should be important to the
23 Commission's consideration?
24.25
275 BOKENKAMP, DI 18
Idaho Power Company
1 A.Yes. Although not directly evaluated in the.2 RFP process, there are several other benefits associated
3 with adding a combined cycle combustion turbine to Idaho
4 Power's generation resources. First, by using new, state
5 of the art technology, the Langley Gulch Proj ect will
6 benefi t from technological advancements resulting in
7 improved efficiency which can be passed through to
8 customers in the form of reduced operating costs and.
9 greater secondary sales revenues. Second, the improved
10 efficiency and the low variable operating costs of the
11 Langley Gulch Project will result in the unit being
12 dispatched more frequently. Having the unit on-line more
13 frequently gives Idaho Power another resource to assist.14 wi th integrating wind or other intermittent resources.
15 Third, the Langley Gulch Project is expected to have a
16 residual value, and be available to serve customers at
17 the end of 20 years. Finally, adding a combined cycle
18 proj ect to Idaho Power's portfolio provides the Company
19 with an opportunity to shift generation from coal-fired
20 resources to a natural gas-fired combined cycle resource
21 during certain times of the year, reducing the Company's
22 C02 emissions from its coal-fired resources.
23
24.25
276 BOKENKAP, DI 19
Idaho Power Company
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11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
1 Q.The Company is requesting that the Commission
2 expedi te its review of the Application. Could you
3 explain why?
4 A.An expedited review of the Company's
5 application will enable the Company to proceed with the
6 proj ect reducing the amount of time that proj ect costs
7 are subj ect to escalation. Also, an expedited approval
8 process may enable the project to be on-line for the
9 summer of 2012.
10 Q.Does that complete your testimony?
A.Yes.
277 BOKENKAP, DI 20
Idaho Power Company
.
.
1 Q.Would you please state your name, business
2 address, and present occupation?
3 A.My name is Karl Bokenkamp and my business
4 address is 1221 West Idaho Street, Boise, Idaho. I am
5 the General Manager of Power Supply Operations & Planning
6 at Idaho Power Company.
7 Q.Are you the same Karl Bokenkamp that submitted
8 direct testimony in this proceeding?
9 A.Yes I am.
10 Q.What is the purpose of your direct rebuttal
11 testimony in this proceeding?
12 A.My testimony will respond to the allegations of
13 Intervenor witnesses that Idaho Power does not need the
14 Langley Gulch proj ect in 2012. I will also address
15 certain aspects of Staff and Intervenor witness testimony
16 concerning the 2012 Baseload Request for Proposals
17 ("RFP") and the evaluation of the proposals received.
18 Q.Please summarize why Idaho Power selected the
19 Langley Gulch project as the winner of the 2012 Baseload
20 Resource RFP.
21 A.The Langley Gulch proj ect was selected for one
22 primary reason - the value it provides to Idaho Power's
23 customers.
24.25 /
278 BOKENKAP, DI REB 1
Idaho Power Company
1.Langley Gulch was the top scoring combined
2 cycle proj ect and the net present value ("NPV") of its
3 20-year revenue requirement provides considerable savings
4 to customers. Even under conservative assumptions, the
5 NPV of its 20-year revenue requirement is approximately
6 $95 million less than that of the next closest combined
7 cycle proj ect. This conservative scenario is presented
8 in Staff Exhibit No. 113 and it uses Langley Gulch's full
9 Commitment Estimate, which it may not spend, and excludes
10 Langley Gulch's terminal value. If Langley Gulch's
11 terminal value is considered, Staff Exhibit No. 114 shows
12 the NPV of its 20-year revenue requirement is.13 approximately $160 million less than that of the next
14 closest bidder.
15 The selection of a combined cycle proj ect will
16 help to provide the up and down regulation necessary to
17 integrate intermittent resources as well as provide the
18 Company with an option to reduce its C02 emissions by
19 shifting generation from its coal-fired resources to a
20 natural gas-fired resource.
21 Q.ICIP and Irrigation Pumpers Association
22 wi tnesses assert that the Company's load forecasts do not
23 accurately reflect current depressed economic conditions
24 and, as a result, they recommend that the Commission wait.25 until after the 2009 IRP has been acknowledged to see if
279 BOKENKAMP, DI REB 2
Idaho Power Company
1 Langley Gulch is actually needed in 2012. ICIP witness.2 Dr. Reading even recommends the Company completely
3 restart the RFP. Are their recommendations reasonable?
4 A.No. I think they are recommending a very risky
5 strategy. Based on the Company's current forecasts of
6 loads and resources, an additional resource such as the
7 Langley Gulch proj ect is needed in 2012. To illustrate
8 this need, I have included Exhibit No. 10.
9 Q.What does Exhibit No. 10 show?
10 A.Exhibi t No. 10 is a current average energy and
11 peak-hour load and resource balance. It shows that even
12 with Langley Gulch in service in July of 2012, a
13 significant average energy deficit exists. Exhibi t No..14 10 uses the May 2009 load forecast, the most recent
15 estimates of peak-hour contributions from the Irrigation
16 Peak Rewards, A/C Cool Credit and Commercial DSM
17 programs, updated levels of firm import capability from
18 the Pacific Northwest, and wholesale firm energy
19 purchases capable of being delivered to Idaho Power's
20 east side. As shown on Exhibit No. 10, Idaho Power is
21 still proj ecting significant peak-hour deficits during
22 July 2009 through July of 2012 of 166 MWs, 40 MWs, 132
23 MWs, and 18 MWs (assuming Langley Gulch is on-line in
24 July 2012), respectively. From an average energy.25 perspective, using the May 2009 load
280 BOKENKAMP, DI REB 3
Idaho Power Company
.
.
1 forecast, the aforementioned assumptions regarding DSM,
2 firm import capacity from the Pacific Northwest, and east
3 side purchases, Idaho Power is still proj ecting average
4 energy deficits during July 2009 through July of 2012 of
5 365 aMWs, 368 aMWs, 421 aMWs, and 285 aMWs (assuming
6 Langley Gulch is on-line for July 2012), respectively.
7 Q.In your prior response you mentioned the May
8 2009 load forecast. Was the decision to proceed with
9 Langley Gulch based on a May 2009 load forecast?
10 A.No, as noted in my direct testimony, a baseload
11 resource was identified in the preferred portfolios in
12 both the 2004 and 2006 IRPs. A natural gas-fired
13 baseload resource was included in the 2008 IRP update.
14 Clearly, load growth has declined since those forecasts
15 were made. However, Idaho Power has prepared a number of
16 updated load forecasts since the 2006 IRP and 2008 IRP
17 update were published. Recent economic conditions
18 prompted the Company to revise its load forecast in
19 December of 2008 and then again in May 2009. The
20 December 2008 revision looked at residential and
21 commercial loads. The most recent revision, performed in
22 May of 2009, updated the forecast loads for special
23 contract customers as part of preparing the next load
24 forecast, which is expected to be completed in late.25 summer 2009.
281 BOKENKAP, DI REB 4
Idaho Power Company
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1 Exhibit No .10 does not include the recently
2 acquired flexibility to reduce Hoku' s loads by 39 MW
3 between June 15, 2012, and August 15, 2012. If the
4 Company includes this flexibility, the proj ected
5 peak-hour deficit in July of 2012, without Langley Gulch,
6 is 279 MW (318 MW deficit + 39 MW reduction from Hoku) .
7 The average energy deficit in July of 2012, without
8 Langley Gulch, is 497 aMW (536 aMW deficit + 39 aMW
9 reduction from Hoku) .
10 Q.ICIP witness Mitchell and Irrigator witness
11 Yankel indicate that the Company can cover summer 2012
12 defici ts with additional wholesale purchases. Is that
13 true?
14 A.It is important to remember that to serve the
15 279 MW deficit without Langley Gulch, any imports from
16 the Pacific Northwest in excess of the projected firm
17 network transmission set-aside of 114 MW would be on
18 non-firm transmission. If Idaho Power's other
19 transmission customers use their transmission rights
20 during July of 2012, then any time Idaho Power imports
21 more than 114 MW from the Pacific Northwest, it is using
22 transmission capacity that is intended for Transmission
23 Reliability Margin ("TRM") and Capacity Benefit Margin
24 ("CBM"). Although this transmission is sold on a
25 non-firm basis, when Idaho Power uses this transmission
capacity, it is
282 BOKENKAP, DI REB 5
Idaho Power Company
.
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1 using the transmission capacity intended to (1) provide
2 reasonable assurance that the transmission system will be
3 secure under a reasonable range of uncertainty in system
4 condi tions and (2) ensure access to backup generation
5 from interconnected systems to meet generation
6 reliabili ty requirements commencing at the end of any
7 hour that a loss of generation occurs in. In other
8 words, Idaho Power is using its reserves. If the Company
9 was importing more than 114 MW from the Pacific Northwest
10 during a July 2012 peak-hour and simultaneously lost a
11 Jim Bridger unit, it would already be using some of the
12 transmission that was intended to ensure transmission
13 system reliability or to replace the lost Bridger
14 generation using market purchases.
15 As a point of reference, if we average the
16 Company's hourly imports from the Pacific Northwest
17 during the month of July 2007, on average Idaho Power's
18 imports from the Pacific Northwest for hours 7 through 22
19 averaged over 400 MW. Peak import levels exceeded 700
20 MW.
21 Q.In Mr. Yankels' testimony on behalf of the
22 Irrigators, he argues that the 115 average MWs of network
23 set-aside for firm purchases is meaningless because the
24 Company's new forecasts included planned peak energy.25 purchases from the Pacific Northwest ranging from 441 to
283 BOKENKAMP, DI REB 6
Idaho Power Company
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13
14
1 670 MWs in 2013. Is Mr. Yankel correctly interpreting
2 the transmission available to Idaho Power in the summer?
3 A.No. It appears that Mr. Yankel may not
4 understand the difference between the firm and non-firm
5 transmission capacity available to Idaho Power. In fact,
6 the discrepancy Mr. Yankel has identified further
7 reinforces the Company's need for the Langley Gulch
8 resource to be available during Idaho Power's peak-hours
9 in 2012 and 2013.
10 The FERC has established strict rules for
11 determining available transmission capacity. Under those
12 rules, Idaho Power's transmission business unit
determines the amount of firm transmission Idaho Power' s
Power Supply business unit can expect to receive to serve
15 its network loads. This is Power Supply's "network
16 set-aside. " The minimum amount of network set-aside for
17 firm purchases from the Pacific Northwest for 2012 is 114
18 MW and that is expected to occur in July. The amount of
19 set-aside Power Supply receives from the Transmission
20 business unit will vary from month to month depending on
21 the Company' s forecast need for transmission and
22 available transmission capacity.
23 The amount of network set-aside shown in
24 Exhibit No. 10 as "Firm Pacific NW Import Capability" is
25 the Company's most current estimate of its future networktransmission
284 BOKENKAMP, DI REB 7
Idaho Power Company
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1 set-asides from the Pacific Northwest. To avoid
2 confusion, an identical amount of firm Pacific Northwest
3 import capability is listed for both the Average Energy
4 and Peak-Hour load and resource balances. Any imports
5 from the Pacific Northwest in excess of the listed firm
6 Pacific Northwest import capability will be on non-firm
7 transmission. These imports will be using transmission
8 capacity intended for (1) system reliability and/or (2)
9 to replace energy from unplanned generator outages, such
10 as loss of a unit at Jim Bridger. This is the amount of
11 firm transmission that Power Supply expects to receive
12 from Idaho Power's Transmission business unit for
13 importing power purchases from the Pacific Northwest.
14 This transmission set-aside provides a firm path to
15 import energy from the Pacific Northwest. The load and
16 resource balance assumes that energy will be available to
17 purchase in the Pacific Northwest.
18 Q.If Langley Gulch is not in-service in July of
19 2012, then how much energy would the Company need to
20 acquire to maintain the load and resource balance?
21 A.The average energy load and resource balance
22 indicates that 650 aMW would be needed. During the
23 peak-hour, 432 MW is necessary.
24 Q.How do you compute those deficit amounts?
25
285 BOKENKAMP, DI REB 8
Idaho Power Company
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1 A.The 650 aMW is composed of 114 MW of imports
2 from the Pacific Northwest plus 251 MW to replace Langley
3 Gulch, which is shown as on-line in July of 2012 in
4 Exhibit No. 10, plus an additional 285 MW to cover the
5 remaining deficit shown on the average energy load and
6 resource balance. The 432 MW needed during peak-hour is
7 composed of 114 MW of imports from the Pacific Northwest
8 plus 300 MW to replace Langley Gulch plus 18 MW to cover
9 the remaining deficit shown on the peak-hour load and
10 resource balance.
11 Q.Why is the projected deficit less during the
12 peak-hour?
13 A. The peak-hour load and resource balance assumes
14 that Idaho Power's existing natural gas-fired peaking
15 facili ties are in operation and contributing 416 MW.
16 Q.Would the peaking resources contribute anything
17 to reduce the July average energy deficit?
18 A If the peaking resources are assumed to be in
19 service, then they would reduce the energy deficit.
20 However, from an economic perspective, they are typically
21 the last resources to dispatch. If the peakers were
22 operated for half of the month, they would provide
23 approximately 200 aMW of energy. This would reduce the
24
25 /
286 BOKENKAMP, DI REB 9
Idaho Power Company
.1 amount of energy needed to maintain the load and resource
2 balance from 650 aMW to approximately 450 aMW.
3 Q.Does this mean that Idaho Power will still need
4 to import large amounts of energy to meet its proj ected
5 deficits?
6 A.Yes. Without Langley Gulch, but with the
7 assumption that 200 aMW of energy is provided by the
8 peaking resources, the July 2012 needs are 450 aMW of
9 energy, and 432 MW during the peak-hour. Considering the
10 39 MW of Hoku flexibility available in July of 2012, the
11 average energy requirement is reduced from 450 aMW to 411
12 aMW and the peak-hour requirement is reduced from 432 MW
.13 to 393 MW. With a network transmission set aside of 114
14 MW for firm imports from the Pacific Northwest, that
15 leaves an additional 297 aMW to be imported to meet the
16 average energy need and 279 MW to meet the peak-hour
17 need. If energy to meet these needs is imported from the
18 Pacific Northwest, it will be imported on non-firm
19 transmission, utilizing transmission capacity typically
20 reserved for TRM and CBM discussed earlier.
21 Q.Doesn't Idaho Power typically import energy
22 from the Pacific Northwest in the summer?
23 A.Yes. The fact that Idaho Power typically
24 imports a considerable amount of purchased energy from.25 the
287 BOKENKAMP, DI REB 10
Idaho Power Company
.1 Pacific Northwest illustrates two points:(1) the
2 considerable reliance that Idaho Power is placing on the
3 availabili ty of market purchases to serve its load and
4 (2) the degree to which Idaho Power is hoping to use
5 non-firm transmission to serve its customers during
6 summer months. Neither of these points are positive.
7 Q.On pages 30 and 31 of his testimony, Mr. Yankel
8 asserts that the 115 average MW transmission limitation
9 is an artificial construct used to justify the need for
10 Langley Gulch. What is your response?
11 A. Again, I do not think Mr. Yankel understands
12 the issue. The 115 MW (114 MW for July 2012 in Exhibit
.13
14
No. 10, the current analysis) of network transmission
set-aside is the amount of firm network transmission from
15 the Pacific Northwest that Idaho Power expects to receive
16 during July. This is a very real limitation until
17 addi tional in-bound transmission capacity from the
18 Pacific Northwest is added to Idaho Power's system. This
19 does not mean that Idaho Power cannot import more than
20 114 MW in July, but it does mean if more that 114 MW is
21 imported from the Pacific Northwest during July, it will
22 be on non-firm transmission. The Company will be using
23 its reserves (TRM and/or CBM and taking the chance that
24 it will not need to use these reserves if it loses a.25 generating unit, or a fire knocks
288 BOKENKAMP, DI REB 11
Idaho Power Company
.1 out a transmission line, or if loop flow limits
2 transmission capacity from the Pacific Northwest.
3 Q.On page 33 of Mr. Yankel' s testimony, he notes
4 that the Company's Irrigation Peak Rewards program could
5 become so successful that Idaho Power will become an
6 energy limited utility rather than a peaking limited
7 utility. Is that a reasonable conclusion?
8 A. As indicated on Exhibit No. 10, on a planning
9 basis, the Company's average energy deficits already
10 exceed its peak-hour deficits for July and August. If the
11 Snake River baseflows continue to decline, Idaho Power's
12 energy position will further deteriorate. And, if as a
.13
14
result of future carbon legislation Idaho Power is
required to reduce the output of its coal-fired
15 facili ties to reduce C02 emissions, Idaho Power's energy
16 posi tion will deteriorate even more.
17 It would be great if the Irrigation Peak
18 Rewards program became very successful. But even if it
19 achieves the levels shown in Exhibit No. 10, the program
20 would not eliminate or defer the need for Langley Gulch
21 in 2012. For July 2012, Exhibit No. 10 includes 188 MW
22 of DSM and energy efficiency program contributions above
23 the amount forecast for July of 2009, bringing the total
24 DSM/energy efficiency forecast for July of 2012 to 432.25 MW. If an additional 200
289 BOKENKAMP, DI REB 12
Idaho Power Company
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1 MW of DSM from the Irrigation Peak Rewards program was
2 added, the 416 MW peak-hour contribution from the peaking
3 resources and 114 MW peak-hour contribution from Pacific
4 Northwest imports could be reduced (but not altogether
5 eliminated), leaving additional firm transmission
6 capacity and/or combustion turbine capacity available to
7 improve reliability and serve customers in the event of
8 an unplanned outage at one of Idaho Power's generation
9 facili ties, or a transmission system outage. Recent
10 transmission outages due to wildfire certainly show that
11 such outages are not hypothetical.
12 Q.In a footnote on the bottom of page 6 of Mr.
13 Yankel's testimony, he notes that his testimony addresses
14 Langley Gulch as an energy resource rather than a peaking
15 resource. Is that a valid assumption to make?
16 A. Yes, I think Mr. Yankel' s assumption is
17 reasonable. While Langley Gulch is expected to operate
18 as an energy resource, following load and providing
19 additional up and down regulation capability to assist
20 with integration of intermittent resources such as wind
21 generation, the project is definitely needed during
22 summer peak-load hours.
23 Q.In his testimony, Mr. Yankel states that the
24 2008 updated IRP and the 2006 IRP are essentially.25
290 BOKENKAMP, DI REB 13
Idaho Power Company
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1 "worthless. II (Page 9, line 14.) Are those the only load
2 forecasts the Company has considered in deciding to
3 continue to pursue Langley Gulch in light of changed
4 economic conditions?
5 A.As noted previously in my testimony, the load
6 forecast used to prepare the 2006 IRP and the August 2007
7 load forecast are not the only load forecasts Idaho Power
8 has considered in light of the changed economic
9 condi tions. As shown in Exhibit No. 10, a load and
10 resource balance using the May 2009 load forecast, the
11 need for an additional resource in 2012 is apparent. If
12 future load forecasts indicate reduced loads in 2012,
13 then the Company will be well positioned to reduce its
14 historic reliance on energy imported from the Pacific
15 Northwest using non-firm transmission. By adding the
16 resource in 2012, the Company is also better positioned
17 to (1) integrate intermittent generation resources, such
18 as wind generation, and (2) respond to carbon legislation
19 with an option to reduce its C02 emissions by shifting
20 coal-fired generation to natural gas-fired resources.
21 Q.At page 28 of Mr. Yankel' s testimony, he states
22 that the Company's 2009 IRP as well as its December 2008
23 and May 2009 updated forecasts indicate that Langley
24
25 /
291 BOKENKAMP, DI REB 14
Idaho Power Company
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19
20
21
22
23
24.25
1 Gulch will operate at a capacity factor of 91 percent.
2 Is this statement correct?
3 A.No. In his testimony, Mr. Yankel adds a
4 footnote that states that the source for the 91 percent
5 capacity factor is Idaho Power's response to Staff's
6 First Production Request in Case No. IPC-E-09-03. The
7 Company's response to Staff's First Production Request,
8 Request No. 37, states that the capacity factor for the
9 Langley Gulch proj ect is estimated using AURORA output
10 based upon 2009 IRP assumptions. The average capacity
11 factor supplied in the response to Staff Request No. 37
12 is shown below in an abbreviated form to only include the
13 annual average. As shown below, none of the capacity
14 factors are close to the 91 percent amount described by
15 Mr. Yankel.
16
17 Year
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
Capaci ty Factor
33%
50%
52%
53%
54%
54%
56%
55%
64%
64%
62%
62%
61%
65%
63%
63%
18
292 BOKENKAP, DI REB 15
Idaho Power Company
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1 Year
2028
2029
2030
2031
2032
Capaci ty Factor
64%
64%
65%
75%
74%
2
3
4
5 Q.On page 29 of his testimony, Mr. Yankel
6 testifies that the Company's 2009 IRP shows Langley Gulch
7 operating at 251 aMW in each month. Is Mr. Yankel
S confusing availability of the plant with actual operation
9 of the plant when he states that the plant is producing
10 251 aMW in each month of the Company analyses?
11 A.Yes. Mr. Yankel' s interpretation of the data
12 provided by the Company is incorrect. The 251 aMW is not
13 the expected generation; instead it is the amount of
14 energy the Company expects to have available from the
15 plant for planning purposes.
16 Q.Are there other errors in Mr. Yankel' s
17 testimony?
18 A.Yes. In discovery, the Irrigator's requested
19 that the Company re-run its 200S rate case test year
20 model to assume that Langley Gulch was available in 200S.
21 Mr. Yankel used that model run to support his assumption
22 that Langley Gulch, which was not a needed resource in
23 200S, was used either to displace higher cost purchases
24 or for surplus sales, provided that market prices.25
293 BOKENKAMP, DI REB 16
Idaho Power Company
.1 exceeded the variable operating cost of Langley Gulch.
2 This is the source of his testimony that 88 percent of
3 the Langley Gulch proj ect will be used for surplus sales.
4 Q.Is Mr. Yankel' s comparison of the Company's
5 2009 IRP analysis to the scenario he asked the Company to
6 create, that is, the Company's 2008 test year rate case
7 results adjusted to include Langley Gulch 4 years prior
8 to its need, a reasonable comparison?
9 A.No. The Company has planned for Langley Gulch
10 to be available in 2012. Inserting Langley Gulch into a
11 scenario where 2008 loads and resources are used creates
12 a scenario that is not a realistic representation of when
.13 Langley Gulch is needed; therefore, the results are not
14
15
reflective of what would be expected in 2012 or 2013.
Q.On the bottom of page 52 of his testimony,
16 Staff witness Rick Sterling testifies that a simple cycle
17 combustion turbine ("SCCT") was actually the price score
18 winner in the bid evaluation process. He goes on to
19 opine that the reason the SCCT proposal scored well, but
20 was not ultimately selected, was because of the SCCT' s
21 low capacity factor. Has Mr. Sterling correctly stated
22 the reasons why the SCCT, even though it was the price
23 score winner, was not selected?
.24
25 /
294 BOKENKAMP, DI REB 17
Idaho Power Company
1 A.He correctly identified one of the main reasons.2 for the SCCT' s higher price score. A simple cycle
3 combustion turbine scored well because of its low
4 capaci ty factor. Another factor contributing to the
5 SCCT' s favorable scoring is the lower capital cost of a
6 SCCT when compared to a combined cycle combustion turbine
7 ("CCCT"). The combination of the two, low capital cost
8 and the low capacity factor, resulted in a high scoring
9 proposal when evaluated with the AURORA and the revenue
10 requirements models. The AURORA analysis used to develop
11 the price scoring utilized 50th percentile water and load
12 conditions with a 90th percentile peak-hour load. Under.13 these conditions, the SCCT operated at a relatively low
14 capaci ty factor contributing to its favorable scoring.
15 Considering both the fixed and variable costs of owning
16 and operating a project with all other considerations
17 being equal, a SCCT will be preferred over a CCCT at
18 lower capacity factors and a CCCT will be preferred at
19 higher capacity factors.
20 Mr. Sterling also correctly identified the
21 reason why the SCCT was not selected. Given the
22 Company's need for a generating resource that (1) is
23 capable of operating in a baseload manner to
24 cost-effectively supply energy deficits, (2) provides the.25 Company with an option to meet future C02 regulations by
shifting generation from coal-
295 BOKENKAP, DI REB 18
Idaho Power Company
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1 fired to natural gas-fired resources, thereby reducing
2 C02 emissions by approximately 0.6 tons/MWh for each MWh
3 shifted, and (3) is expected to be on-line and capable of
4 providing up and down regulation to help integrate
5 intermi ttent renewable resources, SCCT resources were
6 dropped from consideration in the final stages of the RFP
7 process.
8 Q.On page 77, Mr. Sterling discusses his Exhibit
9 No. 113, which shows how the bids in the 2012 RFP would
10 have been evaluated if the Commitment Estimate would have
11 been used to score the Benchmark Resource bid. He
12 concludes that if the Commitment Estimate would have been
13 used as the price of the Benchmark Resource, the
14 Benchmark Resource would not have been declared the
15 winner. Is his conclusion correct?
16 A.No. Although on Staff Exhibit No. 113 IIIIIII
17 I shows a higher total price score and total score than
18 the Benchmark Resource, relying only on the point score
19 shown in Exhibit No. 113 is misleading and would have led
20 to a costly mistake if I I / I I I I / / had been selected.
21 Q.Why do you say reliance only on the point score
22 shown in Exhibit No. 113 would be a mistake?
23 A.If you look at the top paragraph of Staff
24 Exhibit No. 113, it shows the 20-year NPV of the revenue
25
296 BOKENKAMP, DI REB 19
Idaho Power Company
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1 requirement for the Benchmark Resource using the
2 Commi tment Estimate as its cost. It compares that cost
3 to the 20-year NPV of the revenue requirement for / / / / / /
4 / . The Benchmark Resource is still $ 95 million less
5 expensi ve for customers than the best al ternati ve bid
6 over the 20-year evaluation period.
7 Q.What else does Exhibit No. 113 show with
8 respect to the comparison between the two bids.
9 A.First, as noted in the text of Exhibit No. 113,
10 the terminal value of the Benchmark Resource was not
11 reflected in the scoring shown on Exhibit No. 113. The
12 terminal value is a measure of the remaining economic
13 value of an asset after some number of years, in this
14 instance 20 years was used. At the end of a 20-year
15 Power Purchase Agreement ("PPA") or Tolling Agreement
1 6 ("TA"), the Developer retains the generation asset.
1 7 Idaho Power might have an opportunity to enter into
18 another PPA or TA, or purchase the asset. However, with
19 a utility-owned facility, such as the Benchmark Resource,
20 the utility retains the economic value of the physical
21 asset - a power plant. The RFP Team' s evaluation used
22 the book value of the asset to estimate its terminal
23 value. However, if the asset were sold at the end of the
24 evaluation period, the
25
297 BOKENKAMP, DI REB 20
Idaho Power Company
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1 actual market or economic value of the asset could be
2 higher than the book value.
3 Second, the cost to the Company's customers for
4 imputed debt was not reflected in the results shown on
5 Exhibi t No. 113. For further discussion on imputed debt
6 costs, see Staff witness Carlock's testimony at pages 7
7 and 8 and Idaho Power witness Smith's testimony at pages
8 11 and 12.
9 Q.How did the Company's RFP team address the
10 values you discussed in your prior answer in scoring the
11 bids?
12 A.The Company's RFP Team calculated two sets of
13 price scoring for the short-listed proposals. The first
14 set included the as-bid costs without terminal value or
15 any assessment of imputed debt. The second analysis
16 included the terminal value, which is a standard method
17 of capturing end-effects from unequal proj ect lives. The
18 resul ts of the second analysis are shown in Staff Exhibit
19 No. 114. As you can see from Exhibit No. 114, even when
20 you only include the terminal value, the Benchmark
21 Resource will cost customers nearly $160 million less
22 than the closest competing bid.
23 Q.On page 77 of his testimony, Mr. Sterling
24 describes why he thinks the Company chose Langley Gulch
25
298 BOKENKAP, DI REB 21
Idaho Power Company
.
.
1 even though his Exhibit No. 113 shows that ///////// had
2 the highest point score. Has Mr. Sterling correctly
3 described the Company's rationale for selecting Langley
4 Gulch?
5 A.With one exception, yes.
6 Q.What is that exception?
7 A.I believe Mr. Sterling should have given more
8 recogni tion to the $ 95 million NPV difference in cost to
9 customers between / / / / / / / / / and the Benchmark Resource.
10 Q.In his rebuttal testimony, Company witness
11 Porter describes an agreement to provide an incentive to
12 the Company's EPC contractor to complete the Langley
13 Gulch project in the summer of 2012. / / / / / / / / / // / /
14 / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / / // / // / / / /
15 / / / / / / / / Will this payment adversely affect the cost
1 6 effectiveness of the Langley Gulch proj ect?
17 A.No.
18 Q.Are there other considerations the Commission
19 should consider in assessing the Company's decision to
20 select the Langley Gulch proj ect.
21 A.There are several other reasons why the Langley
22 Gulch proj ect provides superior value to Idaho Power's
23 customers. Not only is it the lowest cost proposal by at
24 least a $95 million NPV difference in revenue.25
299 BOKENKAMP, DI REB 22
Idaho Power Company
.
.
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1 requirements, there are additional benefits associated
2 wi th Idaho Power owning the Langley Gulch proj ect. One
3 is flexibility in operations and maintenance. As the
4 owner and operator of the facility, Idaho Power will have
5 a high degree of flexibility in scheduling plant
6 operations and maintenance without contractual
7 obligations associated with a PPA or a TA. In addition
8 to the operational flexibility, Idaho Power would also
9 have the ability to use personnel at other Company-owned
10 facilities if Langley Gulch was off-line for an extended
11 amount of time due to market conditions, such as during
12 spring runoff.
13 Another advantage associated with owning the
14 generation facility is the ability for the Company to
15 install cost-effective efficiency upgrades to the
16 facili ty as they become available. Since Langley Gulch
17 will be a Company-owned facility, the benefits of any
18 efficiency improvements will flow through to customers.
19 If a developer owned the facility and a fixed heat rate
20 tolling agreement was in place, the benefits of
21 efficiency improvements would be retained by the
22 developer.
23 Finally, developing the Langley Gulch proj ect
24 provides the Company with an option to add additional
25 generation facilities at the site at some point in thefuture.
300 BOKENKAP, DI REB 23
Idaho Power Company
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1 Q.On page 63 on lines 10-1£ Mr. Sterling
2 discusses sub-synchronous resonance ("SSR"). What is
3 SSR?
4 A.SSR is an electrical condition that can cause
5 severe damage to a turbine generator' s main rotating
6 shaft.It is caused by the interaction between the
7 electrical resonance of the transmission system and the
8 mechanical resonance of the turbine generator shaft.
9 Q.Wi th that background, is there anything in Mr.
10 Sterling' s discussion of SSR that should be clarified?
11 A. Yes, there are a few details that should be
12 clarified. First, the / / / / / / / / / / amount cited by Mr.
13 Sterling included on line 47 of the Commitment Estimate
14 is intended to cover both the study to see if SSR is an
15 issue and, if it is, the cost of implementing mitigation
16 measures if necessary and station communication costs.
17 The mitigation measures may include a generator tripping
18 scheme to trip the generator if sub-synchronous resonance
19 is detected, or a protection scheme to bypass the series
20 capaci tors at Ontario under certain system conditions.
21 Q.On pages 7 and 8 of his testimony on behalf of
22 the ICIP, Dr. Reading argues that the Company' s decision
23 to change the forecast of natural gas prices may have
24 eliminated some potentially lower cost facilities from
25 bidding.Is this criticism reasonable?
301 BOKENKAMP, DI REB 24
Idaho Power Company
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1 A.If bidders with lower cost facilities were
2 interested in the RFP, it seems to me they would have a
3 strong incentive to bid into the process anyway. The
4 same gas price forecast was used to evaluate all
5 proposals so, in that regard, gas price was a neutral
6 factor. Also, bidders were not precluded from bidding
7 mul tiple technologies, as some bidders did.
8 Q.On pages 9 and 10 of his ICIP testimony, Dr.
9 Reading comments on the way the evaluation team reached
10 consensus on the non-price attributes of the bids and the
11 importance of the non-price attributes in the evaluation.
12 Could you please respond to his criticism?
13 A. That part of Dr. Reading's testimony addressing
14 the importance of non-price scoring is a hypothetical
15 construct that is not very meaningful. Admittedly,
16 non-price scoring is somewhat subjective. As noted in my
17 direct testimony, with less than 2 points separating the
18 non-price scores of the short-listed combined cycle
19 projects, the non-price scores really were not a
20 significant differentiator.
21 Q.On page 16 of his ICIP testimony, Dr. Reading
22 quotes from a letter from TransCanada in which
23 TransCanada explains /////////////////////////
24 / / jIll / jIll / III/III / / ////////////////////////////////////
25 /////////////
302 BOKENKAMP, DI REB 25
Idaho Power Company
1 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.2 I I I I I I I I I I I I I I I I II I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I II I
3 I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I
4 I I I I I I I I I I I I I I I I I I I Do you believe these criticisms by
5 TransCanada are legitimate?
6 A.No. Regarding the first point, the Company's
7 document Response to Questions Raised a t the May 8, 2008
S Pre-Bid Meeting that was posted on Idaho Power's website,
9 discussed the projected deficit in 2012 and noted this
10 defici t was the principal reason that Idaho Power decided
11 to include a self-build baseload generation resource as
12 one of the al ternati ves to be evaluated in the RFP. With
.13 the need for an additional resource in 2012, and no f~rm
14 assurance at that point that any bids would be received,
15 the Company needed to secure equipment to ensure that a
16 resource could be developed and on-line by 2012.
17 TransCanada' s letter confirms the correctness of the
lS Company's decision to secure equipment.
19 This question of equipment transfer was further
20 addressed in response to question No. 3 of the 2012
21 Baseload RFP Questions & Answers document that was posted
22 on Idaho Power's website. The Company indicated that it
23 was not offering the Benchmark Resource equipment to
24 other bidders to maintain its flexibility to select.25 multiple
303 BOKENKAMP, DI REB 26
Idaho Power Company
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1 proposals if agreements with potential new large load
2 customers were finalized during the term of the RFP. The
3 2012 Baseload RFP stated that Idaho Power anticipated
4 acquiring between approximately 250 MW and 600 MW of
5 dispatchable energy. The range in the quantity of
6 dispatchable energy to be acquired was related to the
7 uncertainly associated with potential new large loads
8 locating in Idaho Power's service terri tory. Addendum 1
9 to the 2012 Baseload RFP, dated June 25, 200S, revised
10 the quantity to approximately 300 MW. Subsequently, by
11 not offering the equipment to other developers before the
12 conclusion of the RFP process, Idaho Power retained the
13 option to use this equipment to build a second plant if
14 new large loads materialized.
15 Q.Did Idaho Power have the contractual right to
16 commi t to transfer the equipment?
17 A.No. Mr. Porter addresses the contract issues
18 associated with equipment assignment in his rebuttal
19 testimony.
Q.What about TransCanada' s stated concern that
21 / / / / / / / I / / / / / / / I / / / / / / / / / / / / / I / / / 1/////////////////////
22 /1/////1/
23 A./ / / / / / / / / / / / I 1//1/ I I / / / / / / / / / / / / I / / / / / / / / I I /
24 / / / I / / / I / / / I / I / I I I / I / / / / / I / I / / I / I I I / / / / / / / / / / /
25 111//111/////1
304 BOKENKAMP, DI REB 27
Idaho Power Company
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1 That is simply false. All bidders participating in this
2 RFP had a chance to win. The fact that the Benchmark
3 Resource was ultimately selected was because it had the
4 lowest evaluated cost of the proposals considered in the
5 final evaluation, and because of the value it provides to
6 customers. The costs that the Company incurred to
7 reserve and purchase equipment did not benefit the
8 Benchmark Resource and they did not penalize any of the
9 other proposals. The reservation charges can be compared
10 to an insurance policy premium - in this case, it was the
11 premium the Company incurred to ensure it could have a
12 resource on-line in 2012.
13 Q.On page 19 starting on line 11 of his ICIP
14 testimony, Dr. Reading opines that it would not be a
15 prudent business practice for a potential bidder to
16 purchase equipment prior to knowing whether or not it
17 would be successful. If he is correct, how were the two
18 other short-listed bidders, 111111111111111111111 able to
19 bid into the RFP?
20 A.I suppose the answer to that question depends
21 on the bidder, their financial capability, and their view
22 of the future.If a bidder is serious about developing
23 projects and they believe equipment prices are low, they
24 might consider purchasing equipment (or reserving
25
305 BOKENKAMP, DI REB 28
Idaho Power Company
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1 a slot in the manufacturing queue) to ensure equipment
2 availabili ty for future development opportunities to be a
3 prudent business decision. 1111111111/1111111111 both
4 made the short-list and both already owned equipment they
5 were bidding into the process. Additionally, developers
6 may have existing relationships with manufacturers,
7 providing them access to equipment.
8 Q.If Dr. Reading is correct that independent
9 developers are unlikely to secure equipment prior to
10 winning a bid, doesn't that support the Company's
11 argument that Idaho Power had to move forward and reserve
12 equipment?
13 A.Yes. But more importantly, Dr. Reading's
14 testimony illuminates the principal difference between
15 regulated utilities and generation proj ect developers.
16 Idaho Power is legally obligated to serve loads so it
17 must act prudently to ensure resources are available even
18 if that means taking some financial risk. Developers do
19 not have that obligation to serve so they can wait to see
20 if their proposal is selected before committing to
21 purchase equipment.
22 Q.On the bottom of page 19, Dr. Reading opines
23 that if the other bidders had known that the proj ect
24 could be delayed six months, the extended deadline may
25 have changed the results of the prices of the biddingprocess.
306 BOKENKAMP, DI REB 29
Idaho Power Company
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1 Did the Company do anything to address that issue when it
2 extended the on-line date?
3 A.Yes. The Company contacted all of the
4 short-listed bidders to determine the price impact on
5 their proposal if the proj ect was delayed six months from
6 June 2012 to December 2012. Both of the bidders
7 responded that delaying the proj ect for six months would
8 not change their pricing.
9 Q.Dr. Reading recommends that the Commission deny
10 the Company's CPCN, complete the 2009 IRP process,
11 develop new rules for conducting RFPs and redo the
12 bidding process. If the Commission accepted Dr.
13 Reading's recommendation, how would that affect the
14 Company's ability to serve future loads?
15 A.I am very concerned that if the Commission
16 accepts the Industrial Customers' recommendation, it
17 could have serious adverse consequences for both the
18 Company and its customers. The ICIP proposal will build
19 substantial delays into a process of acquiring a new
20 baseload resource, which will in turn compromise the
21 Company's ability to provide necessary capacity and
22 energy during 2012 and beyond. If any unanticipated
23 events, such as transmission outages, or generator
24 outages, occur during the period of shortage, load
25 curtailments are certainly possible.
307 BOKENKAP, DI REB 30
Idaho Power Company
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1 Q.Why do you say that acceptance of Dr. Reading's
2 recommendation would build delay into the resource
3 acquisition process.
4 A.Dr. Reading, in his testimony on behalf of
5 NIPPC, frequently refers to the Oregon Competitive
6 Bidding Guidelines and indicates that the Oregon
7 Guidelines ensure the bidding process is fair for all
8 parties. Although Dr. Reading recommends that the Idaho
9 Commission establish its own guidelines that apply to
10 future resource acquisitions, his testimony implies that
11 the Oregon Competitive Bidding Guidelines provide a good
12 model for the Commission to follow if it determines that
13 Competitive Bidding Guidelines are needed in Idaho. I
14 participated in the Oregon Competi ti ve Bidding Guideline
15 development process in Oregon (Docket No. UM 1182). This
16 process was initiated with a filing on December 3, 2004,
17 and concluded with an Order on August 8, 2006, taking
18 over a year and a half to complete. Once the Guidelines
19 are in place, they substantially lengthen the amount of
20 time it takes to conduct an RFP. As Mr. Gale noted in
21 his rebuttal testimony, when PacifiCorp conducted an RFP
22 for a 2012 baseload resource under the Oregon Guidelines,
23 after two and a half years it withdrew the RFP prior to
24 completion of the case.
25
308 BOKENKAP, DI REB 31
Idaho Power Company
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1 Based on the Langley Gulch schedule, nearly
2 three years for design and construction will be required
3 after the winner is selected. In my judgment, if the
4 Commission adopts the ICIP' s recommendation and we start
5 the process allover again with new bidding guidelines,
6 there will be a considerable delay in the process of
7 acquiring this resource. If it takes a year to develop
8 the guidelines, two years to complete the RFP process and
9 approximately three years .for project design and
10 construction, a resource like Langley Gulch would not be
11 on-line and available to serve customer loads before
12 mid-2015.
13 Q. Would that be a problem for the Company and its
14 customers?
15 A.Yes. Idaho Power's load resource balance in
16 2012 is already tenuous. Waiting three to four years to
17 add a baseload resource will increase those risks
18 substantially. In addi tion, it will compromise the
19 Company's ability to integrate wind and other
20 intermittent resources if they continue to develop at the
21 pace Idaho Power expects to see.
22 Q.Does that complete your testimony?
23 A.Yes.
24
25
309 BOKENKAMP, DI REB 32
Idaho Power Company
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20
21
22
23
24
25
1 (The following proceedings were had in
2 open hearing.)
3 MR. KLINE: Before we go into Mr.
4 Bokenkamp' s direct testimony, I do have one thing that I
5 think if we can talk about it now, it may save some time
6 on cross-examination with the Chair's indulgence.
7 COMMISSIONER KEMPTON: Mr. Kline.
8
9 DIRECT EXAMINATION
10
11 BY MR. KLINE: (Continued)
12 Q Mr. Bokenkamp, you were present in the
13 Hearing Room this morning when the Exhibit 209 was
14 introduced by the ICIP?
15 A Yes.
16 Q And since that exhibit was provided to
17 Idaho Power and to the other parties,have you had an
opportuni ty to review that exhibit?
A Yes,I have.
Q And after your review,do you have any
opinion as to the accuracy of certain portions of that
exhibit?
18
A Yes, I do.
Q Could you please explain for the
Commission those sections that need to be adjusted?
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Idaho Power Company
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1 A Yes. It looks like that what happened on
2 the top line of that, the May 2009 or May '09 line of the
3 forecast, the first one that says January of 2,000 the
4 first January number of 2,098, that those numbers were,
5 it was my understanding they were, taken off of my
6 Exhibit 10 and it appears that they were taken from an
7 incorrect line, so that was really actually the load
S forecast that was from the August, September of 2008 time
9 period. The line below that on Exhibit 10 that says May
10 2009 load forecast is the May 2009 forecast.
11 Q You mean that line is correct? I'm sorry.
12 A On Exhibit 10, that was the May 2009 load
13 forecast. The line above that, the very first load
14 forecast line, was a load forecast from the August,
15 September of 2008 time frame. That's why it matches the
16 August '08 line, the second line on Exhibit 209.
17
18
19
20
Q So it's simply incorrect?
A Yes.
Q All right.
COMMISSIONER KEMPTON: Mr. Kline, when you
21 say it's simply incorrect, are you talking about the May
22 '09 line with the January 2,098 first entry all the way
23 across?
24
25
THE WITNESS: Yes.
COMMISSIONER KEMPTON: And in the May '09,
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Idaho Power Company
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20
21
22
1 are we talking now about the 2012 95 percent megawatt
2 peak or are we back down on 70 so that we're matching
3 70 's and 70' s?
4 THE WITNESS: I just checked the first
5 two. I didn't go through all four of them, but the first
6 two looked like it was a consistent error.
7 COMMISSIONER KEMPTON: But my
8 understanding, then, is the second one on the 95 percent
9 megawatt peak that the May '09 line is correct?
10 THE WITNESS: No, that would be incorrect
11 as well.
12 COMMISSIONER KEMPTON: Okay, same reason?
13 THE WITNESS: Same reason.
14 COMMISSIONER SMITH: Mr. Chairman?
15 COMMISSIONER KEMPTON: Commissioner Smith.
16 COMMISSIONER SMITH: Could you just walk
17 me through Exhibit 10 and this number and show me where
18 your correct number is so I can figure that out?
MR. RICHARDSON: Madam Chair?
COMMISSIONER SMITH: Mr. Richardson.
MR. RICHARDSON: Mr. Chairman.
23 Mr. Richardson.
COMMISSIONER KEMPTON: Yes,
24
25
MR. RICHARDSON: This might be beneficial
for the record. Ms. Mitchell over the lunch hour
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312 BOKENKAP ( Di )
Idaho Power Company
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1 corrected Exhibit 209 with the actual correct line from
2 Mr. Bokenkamp' s Exhibit 10 and I have a corrected Exhibit
3 209 with the accurate numbers on them and I'LL be happy
4 to introduce this when I'm cross-examining Mr. Bokenkamp
5 and we'll have the actual numbers here.
6 COMMISSIONER SMITH: Okay, thank you.
7 COMMISSIONER KEMPTON: All right.
S Q BY MR. KLINE: All right?
9 A There was one other problem on Exhibit
10 209. It's my understanding that under the 2013 forecast,
11 70 percent average megawatt, so that would be the third
12 group down, the line on August '07, that line is actually
13 correct, and if you look at the first group of numbers
14 under the 2012 forecast, 70 percent average megawatt
15 under August '07, so it would be the third line of
16 numbers down in that group, they appear to be identical
17 and those numbers are incorrect.
18 COMMISSIONER KEMPTON: Are they incorrect
19 in both the 2013 forecast and the 2012 forecast?
20 THE WITNESS: It's my understanding that
21 the 2013 line is correct and the 2012 forecast line is
22 incorrect.
23
24
25
COMMISSIONER KEMPTON: Okay.
MR. KLINE: I was hopeful that that would
improve things on cross-examination. I hope that turns
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1 out to be correct. Wi th that, Mr. Bokenkamp is available
2 for cross-examination.
3 COMMISSIONER KEMPTON: Mr. Richardson,
4 cross?
5 MR. RICHARDSON: Thank you, Mr. Chairman.
6 On Exhibit 209, we're going to make those corrections
7 that Mr. Bokenkamp just referred to so we will have a
8 completely accurate Exhibit 209. It will take a couple
9 of minutes for Ms. Mitchell to get that done.
10 COMMISSIONER KEMPTON: Okay, proceed.
11
12 CROSS-EXAMINATION
13
14 BY MR. RICHARDSON:
15 Q Good afternoon, Mr. Bokenkamp.
16 A Good afternoon.
Q Are you familiar with Mr. Gale's direct
18 testimony?
19
20
A Yes.
Q And do you recall where he stated at page
21 12, he was asked a question, "Can Idaho Power assure this
22 Commission that if the Commission authorizes either of
23 the alternatives requested, that the Company has the
24 ability to finance the project?"
25 And Mr. Gale responded, "No, it cannot.
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314 BOKENKAMP (X)
Idaho Power Company
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1 Providing the regulatory assurances would give Idaho
2 Power a better chance to obtain financing, but in today' s
3 environment, we simply do not know if it can be done. II
4 He goes on, liThe Company will be reviewing its financing
5 al ternati ves for the proj ect throughout this spring and,
6 if necessary, may supplement or amend this request based
7 on its findings. ii Do you recall generally Mr. Gale
8 testifying to that effect?
9 A I do generally recall that. Can you refer
10 me to the page in the testimony again?
11 Q I believe it's at page 12 of his direct
12 testimony, page 12, beginning on line 11.
13 A Thank you.
14 Q And then do you also recall Ms. Smith's
15 direct testimony where generally she discusses the
16 current financial markets and the potential problems the
17 Company may have in financing Langley Gulch?
18
19
A Generally.
Q And do you recall responding to a
20 discovery by the Industrial Customers, Response No.6,
21 where you were asked how the Company's potential
22 financial problems factored into the scoring of PA' s,
23 that's PA' sand TA' s, which would be power purchase
24 agreements or tolling agreements, relative to a
25 self-build proj ect and in your response you said, "No,
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315 BOKENKAP (X)
Idaho Power Company
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1 the RFP team did not assign a dollar amount to either
2 cash flow or imputed debt that would impact the Company's
3 financial ratings. The RFP worked under the assumption
4 that Idaho Power was capable of financing the proj ect and
5 meeting the associated cash flow requirements." Do you
6 recall that response?
7 A Yes, I do.
8 Q Do you think it is reasonable not to
9 consider the financial implications for Idaho Power's
10 self-build option when scoring PA' sand TA' s?
11 A Well, we did consider Idaho Power's
12 abili ty to do that and we considered that the Company
13 would be able to finance the proj ect. That was the
14 assumption we worked under.
15 Q So you didn't discount or reduce the
16 points for the self-build option to account for any
17 financing uncertainties?
18 A No.
Q Okay, let's turn to your Exhibit No. 10
20 and let's look specifically at page 2 of Exhibit No. 10.
21 Now, does this Exhibit 10, page 2, show a deficit of
22 average energy for July and August of 2012 of 285 and 123
23 average megawatts, respectively?
24
25
COMMISSIONER KEMPTON: Mr. Richardson,
could you tell us which line that's on?
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316 BOKENKAMP (X)
Idaho Power Company
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18
19
1 MR. RICHARDSON: It would be the very
2 bottom line under July and August of 2012.
3 THE WITNESS: I'm sorry, I've got too many
4 exhibi ts here. Just a minute. I'm turning to the __
5 which line was it again?
6 Q BY MR. RICHARDSON: Okay, we're looking at
7 Exhibit 10, page 2, the very bottom line which I'm asking
8 for August and July of 2012 and I'm asking you if
9 those -- that shows there's a deficit of 285 average
10 megawatts in July and 123 average megawatts in August.
11 A Yes, it does. One other point I was just
12 thinking on your prior question, while we didn i t subtract
13 any points specifically on that, there is it could
14 have factored into a non-price point at some point on
15 there in the analysis.
16 Q It could have?
A Yes.
Q I'm not sure what you mean by that.
A Well, one of the criteria towards the end
20 was, I forget the exact term, but I think it was
21 financing or financial capability or creditworthiness,
22 essentially that, so it could have factored into those
23 points.
24
25
Q So are you telling me that the self-build
option was discounted for uncertainties surrounding
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Idaho Power Company
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1 financing in the scoring?
2 A No. I just said that it could have
3 factored into points in that area.
4 Q And how would we know that, either yes or
5 no?
6 A I don't know how you would.
7 Q Okay, well, thank you for that
8 clarification. Now, back to Exhibit 10, page 2, July and
9 August of 2012.
10 A Okay.
11 Q Am I accurate when I represented that this
12 shows a deficit of 285 average megawatts in August -- in
13 July and 123 average megawatts in August?
14 A Yes.
15 Q And what is the average energy
16 contribution from the Company's gas peakers reflected on
17 this page?
18 A Zero.
Q And for the record, that would be the last
20 line of the first above the yellow line, correct -- the
21 second to the last line above the yellow line? We see
22 the line called "Gas Peakers" and we look across all the
23 months and we see a zero number?
24
25
A Yes, that would be the line.
Q And that indicates there's no contribution
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1 to energy from your peakers?
2 A That's correct.
3 Q Okay. Now, let's turn to page 6 of
4 Exhibi t 10. Now, what is the peak hour contribution from
5 the Company's peakers on this page 6?
6 A It shows 416 megawatts.
7 MR. KLINE: Are you referring to 2012
8 again?
9 MR. RICHARDSON: Well, all across the
10 entire time frame I think it would be 416 megawatts of
11 the gas peakers.
12 Q BY MR. RICHARDSON: And that's their
13 contribution to meet your demand, correct, your peak?
14 A That's correct.
15 Q Peakers when they run, they contribute
16 energy to the system, do they not?
A Yes, they do.
Q And if the peaking resources are assumed
19 to be in service, and I think we've established that they
20 are in fact assumed to be in service, yet there is no
21 recognition of their energy contribution on page 2 of
22 your Exhibit 10; correct?
23
24
25
A That's correct.
Q But we have established that they
contribute to energy; correct?
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319 BOKENKAMP (X)
Idaho Power Company
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1 A Yes. The average energy load balance is
2 looked at on a 70th percentile water and load condition
3 and the peakers would typically be later to dispatch and
4 so at least in that analysis we haven't considered them
5 as on-line and running to provide average energy. I did
6 address that in my testimony and adjusted some numbers
7 based on the assumption, if you made the assumption, that
8 they did run for approximately half the day.
9 Q So if the Company is short of energy in
10 July and August, it could run its 416 megawatts of
11 peakers to meet its energy, couldn't it?
12 A That's correct, you could.
13 Q And in your testimony, you address the
14 economics of running the peakers and you state simply
15 that "from an economic perspective, they are typically
16 the last resource to dispatch"; correct?
17 A I believe that's what my testimony said.
is It sounds accurate.
Q And this is because from an economic
20 perspective, the peakers are the most expensive to
21 dispatch on the Company's system; correct?
22 A Correct. They're more expens i ve than the
23 other units, than most of the baseload units.
24
25
Q Now, I'm going to ask a question that my
economist told me to ask you, but isn't it true that once
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Idaho Power Company
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1 a plant is in rate base and the ratepayers are already
2 paying the capital costs for the plant regardless of
3 whether it's running, then the capital costs should be
4 disregarded when deciding whether or not to dispatch that
5 plant?
6 A That's correct.
7 Q So the plant is essentially free from a
8 capi tal standpoint, it's only the running costs that
9 should be evaluated?
10 A Yes, and the associated maintenance with
11 running.
12 Q Okay, that's a given, and you address the
13 impact, like you alluded to a moment ago, of running the
14 peakers for half of the month and I think you concluded
15 that without Langley, that would reduce the deficit to
16 just 297 average megawatts; correct?
17 A I'd need to refer to my testimony on that.
18 Do you have a page reference on that?
Q Actually, I'm looking for one right now.
20 Page 9 of your rebuttal testimony.
21
22
A Could you repeat the question, please?
Q Actually, it's page 10. Yes, I'd be happy
23 to. You address the impact of running the peakers for
24 half the month and concluded that without Langley, that
25 would reduce the deficit to just 297 average megawatts
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321 BOKENKAP (X)
Idaho Power Company
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1 and that would be at line 15 of page 10.
2 A Yes, 297 average megawatts to meet the
3 average energy need.
4 Q And that's only using the peakers for half
5 the month; correct?
6 A Approximately, yes.
7 Q And so does it really make sense to you to
8 be asking this Commission to hit the panic button, if you
9 will, and construct Langley Gulch on a fast track while
10 the peakers are sitting idle, especially with historic
11 low gas prices?
12 A Well, we think there are a number of
13 reasons that it makes sense to add the resource.
14 Certainly, we could run the peakers. I mean, that's a
15 possibili ty. It's not our most cost-effective option.
16 Q And if you did not build Langley and you
17 ran the peakers for half the month, it reduces your
18 defici t to 297 average megawatts, but you would still be
19 operating with a deficit, though, correct, with 297;
20 correct?
21
22
A Correct.
Q If you ran the peakers for the full month,
23 what would that number be?
24
25
A It would be around 100.
Q So if I run 416 megawatts of peakers for
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322 BOKENKAP (X)
Idaho Power Company
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1 the full month, do I not get 416 average megawatts of
2 energy?
3 A Yes, you would.
4 Q Now, compare that to 297 average megawatt
5 deficit with the deficit the Company is running for July
6 of 2011 on your Exhibit 10.
7 A Okay.
8 Q And what's the deficit the Company is
9 expected to run in average megawatts in July of 2011?
10 A 421 megawatts.
11 Q Now, compare that number with your 297
12 megawatt without Langley to July of '13, what is the
13 deficit the Company is running in July of 2013?
14 A Negati ve 264 with Langley in service.
15 Q And that's with Langley in service;
16 correct?
17 A Correct.
Q So you have a smaller deficit in 2012 than
19 you do in 2011 without Langley and smaller than you do in
20 2013 with Langley. 2012 doesn't really in my mind stand
21 out as being all that different in terms of the deficit
22 the Company is expecting and is apparently able to cover
23 without Langley in 2011 and with Langley in 2013. Can
24 you explain that apparent anomaly to me?
25 A I'm not sure that I totally followed it.
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323 BOKENKAMP (X)
Idaho Power Company
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1 Q Well, without Langley in 2012, you
2 essentially have a 297 megawatt deficit. In 2011, you're
3 anticipating an over 400 megawatt deficit, but we're not
4 doing anything to cover that deficit and apparently, the
5 Company can handle it and manage it. I'm wondering why
6 it can't manage and handle 297 in 2012 when it can handle
7 over 400 in 2011.
8 A I understand your question now. To meet
9 that deficit in 2011, there would be a significant amount
10 of energy imported on non-firm transmission.
11 Q And why isn't that possible in 2012?
12 A It is possible. We don't -- well , it
13 might be possible, depending on the transmission, on the
14 firmness of it. That's one of the risks is that we have
15 relied on a significant amount of non-firm transmission
16 and there's risk associated with that. In effect, we are
17 leaning on our TRM and CBM margins that are held, so any
18 time we're importing from the Pacific Northwest energy
19 that exceeds our firm network set-asides, we're in effect
20 using our reserves.
21 Q That's true for both 2011 and 2012, isn't
22 it?
23
24
25
A Yes.
Q And so what's changed and what's magic
about 2012 that you have to have this fast track process
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324 BOKENKAMP (X)
Idaho Power Company
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1 when you're already handling deficits of greater
2 magnitude than we have in 2012 in 2011 and 2013? What's
3 different about 2012, what's unique?
4 A Well, I don't know that there's a lot
5 different about 2012. It's another year in the future,
6 so there's another chance for changes in loads to occur,
7 and the fact of the matter, I think there's a question as
S far as prudency to continue to rely on non-firm
9 transmission.
10 Q But you're asking this Commission to allow
11 you to do just that for 2011, 2013, and you've done that
12 historically and you haven't been subj ect to a prudency
13 disallowance by this Commission. In fact, aren't all of
14 your extraordinary power supply costs flowed through the
15 PCA?
16 MR. KLINE: Is there just one question or
17 two there? I think there were two questions.
19 repeat it?
THE WITNESS: Could you go ahead and
20 Q BY MR. RICHARDSON: It was a good
21 question, too. Both of them were good. Your
22 extraordinary power supply costs are flowed through the
23 PCA, are they not?
24
25
A I'm not posi ti ve on that, but I think our
costs typically flow through the PCA, yes.
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325 BOKENKAMP (X)
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1 Q Right, and you haven't been subject to a
2 disallowance by this Commission of your off-system
3 purchases to meet your deficits because you haven't built
4 enough plant, have you?
5 A I don't think so, but I'm probably not the
6 witness for that question.
7 Q Well, you raised the specter of a prudency
8 disallowance just a few moments ago, what were you
9 referring to?
10 A I was referring to the idea of whether it
11 was prudent to continue to plan on meeting our loads by
12 use of non-firm transmission.
13 Q Isn't that exactly what you're doing right
14 now with your Langley Gulch proposal in 2011 and 2013 and
15 beyond?
16 A I'm not sure where the 2013 comes into it,
17 but we are defini tely given this load balance, we will be
18 relying on non-firm transmission in 2011.
19 Q And you have a deficit in 2013 with
20 Langley on line of 364 megawatts, so you are still
21 relying on non-firm transmission. Langley Gulch isn't
22 changing that.
23
24
25
A That's true, we're still relying on it.
Q And you think that's a prudent thing to
do?
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1 A No.
2 Q But that's what you're proposing that this
3 Commission accept. Looking at your Exhibit 10, in fact,
4 in 2014 you've got 400 megawatts of deficit that you'll
5 be meeting with non-firm transmission. Aren't you asking
6 the Commission to accept your proposal to build Langley
7 and operate with 400 megawatts of deficit in 2014 met
8 with non-firm transmission?
9 A Well, the request wasn't necessarily about
10 2014. It was simply about adding the resource in 2012.
11 There's other things that can happen between now and
12 2014. We have recently moved the B-H line, which was
13 originally scheduled earlier, out to June of 2015.
14 Q Now, the intervenors in this case have
15 asked for a relatively short time of time-out for moving
16 this process forward and it was suggested that the lights
17 might go out because you're relying on non-firm
18 transmission and I think we've demonstrated here that you
19 already rely on non-firm transmission. It's sort of a
20 business as usual for Idaho Power. You don't think the
21 lights would go out in 2012, do you, if the Commission
22 delays this process for six months?
23 A There's no way to say. I mean, it just
24 depends on what happens on the system.
25 Q And that's true both with and without
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1 Langley, isn't it?
2 A That's true.
3 MR. RI CHARDSON : Mr. Cha i rman, ma y I
4 approach the witness?
5 COMMISSIONER KEMPTON: For what purpose?
6 MR. RICHARDSON: To correct Exhibit 209.
7 COMMISSIONER KEMPTON: Yeah.
8 (Mr. Richardson approached the witness.)
9 MR. RICHARDSON: To avoid confusion, I'm
10 going to be ask that this be marked as Exhibit 210.
11 (Industrial Customers of Idaho Power
12 Exhibi t No. 210 was marked for identification.)
13 Q BY MR. RI CHARDSON : Mr. Bo ken kamp, I hope
14 we got it right this time and if you would take a moment
15 to take a look at this Exhibit No. 210 to confirm that we
16 did get it right and we were scrambling so we didn't get
17 it printed, but what we did is replaced the August '07
18 line in the 2012 70th percent box, first box, with the
19 handwritten numbers underneath it.
20
21
A Okay, I've reviewed the numbers.
Q Mr. Bokenkamp, you have in front of you
22 Exhibit 210 which is a correction of Exhibit 209. Does
23 it accurately reflect a summary of the various load
24 forecasts that have been discussed in this docket?
25 A The only ones I checked, I checked the May
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328 BOKENKAMP (X)
Idaho Power Company
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1 of' 09 ones and those all appear to match my Exhibit 10
2 and I don't have any way to verify the handwritten
3 numbers.
4 Q Well, if we'd accept them, subj ect to
5 check, I'd just like to ask you whether or not the May of
6 '09 forecast load is actually higher than the August '06
7 forecast load for July of 2012.
8 A Which forecast are you looking at?
9 Q The May '09 compared to the August '06 for
10 July of 2012.
11 A For the average energy or peak?
12 Q Average energy.
13 A May of '09 shows 2,577 and August of '06
14 shows 2,529,so the May of ' 09 is higher.
MR.RICHARDSON:And we visited earlier
about whether or not we expect load to grow or not,so I
won't go into that and I guess 1'll just leave it at
that,Mr.Chairman.That concludes my questions.
15
16
17
18
19 COMMISSIONER KEMPTON: Thank you,
20 Mr. Richardson. The Chair can't let it pass, however,
21 that attempting to jam something into the hearing before
22 it's been vetted by the respective parties is not a good
23 idea.
24
25
MR. RICHARDSON: Noted, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Olsen? I'm
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329 BOKENKAMP (X)
Idaho Power Company
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1 sorry, Mrs. Ackerman.
2 MS. ACKERMAN: Thank you, Mr. Chairman.
3
4 CROSS-EXAMINATION
5
6 BY MS. ACKERMAN:
7 Q This is a quick question. Mr. Bokenkamp,
S going to page 6 of your testimony, you refer to the fact
9 that the Company had engaged R. W. Beck as an independent
10 consulting company to do some monitoring of the RFP
11 process. I had asked this question earlier of Mr. Gale
12 and he referred the question to you and the question is
13 how much did the Company spend to engage R. W. Beck to
14 perform the services that they performed with respect to
15 the Langley Gulch RFP?
16 A From August of '08 through May '09, our
17 records indicate we have spent approximately $ 120,000.
is Q That's August of '08 through August of
19 '09?
20 A April of 'OS through May of '09. Our
21 current limit on the contract is $150,000.
22
23
MS. ACKERMAN: Okay, thank you.
COMMISSIONER KEMPTON: Now, Mr. Olsen and
24 pardon me, Mrs. Ackerman, for jumping over the top of you
25 there.
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1 MR. OLSEN: Thank you, Mr. Chairman.
2
3 CROSS-EXAMINATION
4
5 BY MR. OLSEN:
6 Q I'd just like to, I guess, summarize a few
7 of the points because Mr. Richardson had talked a lot
8 about them, but if I understand it correctly, your
9 testimony here is that with respect to Exhibit 10, he had
10 pointed out, and I'll just use this for reference, we're
11 looking at page 2 on Exhibit 10, that you had a zero
12 amount for the gas peaker line and that's consistent
13 throughout average energy, is that correct, in, I think,
14 pages 2 through 6 -- 2 through 4 -- pardon, 1 through
15 5 -- 1 through 4?
16 A We show zero contribution for average
17 energy from the peakers on pages 1 through 4.
Q Okay, in the forecasting process which
19 your Exhibit 10 is a part of, has that always been the
20 policy of Idaho Power to show a zero contribution of the
21 peakers?
22 A I believe that that's typically how we've
23 done that, yes, we've shown zero. We've talked about
24 actually showing some average energy there, but I think
25 typically, we~ ve showed zero for that for planning
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Idaho Power Company
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1 purposes.
2 MR. OLSEN: Okay. Mr. Chairman, could I
3 approach the witness?
4 COMMISSIONER KEMPTON: For what purpose?
5 MR. OLSEN: To present an exhibit.
6 COMMISSIONER KEMPTON: You may.
7 (Mr. Olsen approached the witness.)
S MR. OLSEN: Mr. Bokenkamp, I'm handing you
9 what's been marked as Exhibit 403 for Idaho Irrigation
10 Pumpers which consists of Idaho Power's Response to
11 Commission Staff's First Production Request to Idaho
12 Power.
13 COMMISSIONER REDFORD: What's the number
14 again?
15 MR. OLSEN: Exhibi t 403.
16 COMMISSIONER KEMPTON: And without
17 objection, Exhibit 403 will be allowed.
18 (Idaho Irrigation Pumpers Association
19 Exhibit No. 403 was marked for identification.)
20 Q BY MR. OLSEN: And if I could direct you
21 to the first page of the attachment to the data response,
22 we have the peak hour 90th percentile and then the
23 average energy 70th percentile and if you can turn to
24 that second page, the average energy, and down on the
25 first group of numbers we have a line there for gas
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1 peakers on average energy, and what does that show there
2 throughout that forecast period?
3 A It shows 353 for 2008 and then 383 and
4 383.
5 Q Okay. Now if you'd turn to the next page
6 there, there are some notes that accompany this worksheet
7 and it had some numbers here and I think this was before
8 there was a new CT put in, so we just had Danskin and
9 Bennett Mountain and I can't recall the other, but you
10 can see in the middle of there they have the monthly
11 energy capacity factor. It shows a 92 percent for
12 Danskin and Bennett Mountain.
13 A Yes.
14 Q Okay, and so subj ect to check, I would
15 represent to you that the 383 just represents the total
16 of those two peakers, at least at that point in time,
17 times the 92 percent to get the 383 is how I followed
18 that through for that capacity factor. Now, my
19 understanding is this data request was a Company-provided
20 response and I think it's right around the middle of 2008
21 that this was updated or whatnot and it appeared to be at
22 least the policy looking at these critical dates of July
23 of each of these years that you would use the gas peakers
24 and that the assumption for that on the last page of this
25 Exhibit 403 said for energy, if we have an energy deficit
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333 BOKENKAMP (X)
Idaho Power Company
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1 during a given month, we will run the peakers, and it's
2 the same with the market price and if we can get it,
3 we'll get that first, so what has changed from this
4 forecast to the one in your Exhibit 10 to not include the
5 gas peakers as a potential resource?
6 A It looks like the peakers were in the
7 exhibit that you passed out and my recall was incorrect
8 on that, so it looks like we did at least in this
9 analysis have them in for energy.
10 Q So one of the critical issues I think
11 before the Commission is that if we delay this process, I
12 think that you, and I won't quote the exact point, you
13 say that's a risky proposition for the Commission to do,
14 but we can clearly see that you have other al ternati ves
15 available to you, so I don't want to belabor the point,
16 but really, is it that risky with now Evander Andrews, I
17 think, that's also on-line where you'd have a capacity
18 factor of 92 percent of 416 megawatts to meet potential
19 deficits in average energy as well?
20 A We would be able to operate those at some
21 reasonable capacity factor, 92 percent, probably not
22 unreasonable.
23 Q Okay. Now, you had previously discussed
24 with Mr. Richardson in order to meet the deficits that
25 are projected in your Exhibit 10 for 2011 and 2013 that
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1 we have to import additional energy from the Pacific
2 Northwest, but you discount the amount that you can bring
3 in because it's not on a firm basis; is that a fair
4 representation of your testimony?
5 A Could you repeat that? I didn't hear the
6 first part.
7 Q I apologize. What is your problem with
8 relying on non-firm energy being imported to meet energy
9 demands on the Idaho Power sy~tem?
10 A Well, I guess it's the same as any other
11 time we rely on non-firm transmission, it's subject to be
12 cut.
13 Q Okay; so let's look at this same Exhibit
14 403 and let's turn over to the peak amount and let's look
15 at just above the gas peakers we have existing imports
16 and let's look at 2012. You have in there 257 megawatts,
17 but in your Exhibit 10 you have for 2012, let's turn to
18 that, that's on page 2, a limitation of the 114
19 megawatts. Why are those two numbers different?
20 A Could you refer me to the place on Exhibit
21 403 that you're referring to?
22 Q Yes, so on the peak hour load generation,
23 90th percentile, so just above gas peakers it says
24 "Existing Imports" which I think is the equivalent of
25 your firm Pacific Northwest capability.
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1 A I've got it. I found the spot.
2 Q Okay, and so we have that number there 257
3 versus the 114 which you have in your recently provided
4 Exhibi t 10.
5 A On the 114 you're referring to 2012?
6 Q That's correct, on page 2.
7 A Yes, the numbers are different and we have
8 recently discovered that there was an error in the
9 calculation of the network set-aside or at least on a
10 planning basis the network set-aside that we would have
11 for imports from the Pacific Northwest. It was based on
12 an incorrect amount, an over-allocation of capacity
13 benefit margin on the Northwest Idaho path.
14 Q So that explains the difference between
15 the two, you assumed that you had more firm capacity in
16 Exhibit 403 as opposed to now?
17 A That's correct.
Q When did you find out that this was
19 miscalculated?
20
21
A Just recently.
Q So that wasn't a change in policy for the
22 Company, but just an oversight that came to your
23 attention?
24
25
A Well, it actually came about as a result
of this case and going through all these numbers, we were
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19
20
21
1 looking at the difference between what we saw for near
2 term set-asides and what we saw for a longer term
3 set-aside and they didn't match and a member of our
4 transmission group took a look at it and reran the
5 numbers and found that error and so now the numbers that
6 we see for July in future years are closer to what we're
7 seeing for a set-aside that we receive in the near
8 term.
9 MR. OLSEN: Okay. I have no further
10 questions, Commissioner.
11 COMMISSIONER KEMPTON: Thank you,
12 Mr. Olsen. Mr. Purdy.
13 MR. PURDY: I'LL pass. Thank you.
14 COMMISSIONER KEMPTON: Mr. Miller.
15 MR. MILLER: I have no questions.
16 COMMISSIONER KEMPTON: Ms. Bridge.
17 MS. BRIDGE: I just have a few questions.
18
CROSS-EXAINATION
22 BY MS. BRIDGE:
23 Q To start out with I'LL repeat my question
24 for Mr. Gale, will the shareholder resolution urging a
25 greenhouse gas reduction strategy be part of the 2009
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1 IRP?
2 A I believe it will.
3 Q Will Langley Gulch be part of that
4 strategy?
5 A Actually, I think it will. I mean, as far
6 as anything that comes out of the shareholder resolution
7 that we adopt or change in approach as a Company, I think
8 that will be reflected and/or at least discussed as part
9 of the 2009 IRP.
10 Q Thank you. On page 14 of your rebuttal
11 testimony in line 16, you state the Company is also
12 better positioned to integrate intermittent generation
13 resources, such as wind generation. Could you speak for
just a moment about what the best way to integrate wind
15 into Idaho Power's system is?
16 A Well, I'm not sure that I know of anyone
17 best way. In general, the hydro system is very capable
18 of doing that because of its quick responsiveness;
19 however, that carries certain implications on how we
20 operate that system to enable us to have the ability to
21 move up or down as necessary within an hour to address
22 changes in the wind, so to the extent we have other
23 resources that are on-line and that are dispatchable and,
24 say, subj ect to operate on automatic generation control
25 to respond to those changes, that type of resource is
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338 BOKENKAP (X)
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1 what will help us integrate wind.
2 Q And what about trading variability with
3 wind resources with other utili ties or with wind you have
4 wi thin Idaho Power's resources?
5 A To the extent that we have wind generation
6 that tends to offset each other where some proj ects are
7 picking up while others are backing down, that would
8 certainly lessen the challenge of integrating it, the
9 di versi ty might, but still, there's a chance that they
10 could all be on or all be off in a fairly short order so
11 we'll need some type of resource to be able to respond to
12 that.
13 Q And then I just have one more question and
14 I apologize in advance it's a bit broad, but outside of
15 the carbon adder, in Idaho Power's resource planning is
16 there any other -- does the Company account for public
17 policy that will result in a reduction in energy demand
18 or more distributed power? For example, the climate bill
19 that was recently passed in the House, it mandates energy
20 saving standards for buildings, appliances, industry, so
21 for example, when the economy does pick back up,
22 buildings are going to be built much more efficiently,
23 existing buildings are being retrofit. You know, we i re
24 going to see more solar panels on homes. I know it would
25 be pretty impossible to quantify, but is there any way to
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1 take that into account in Idaho Power's resource
2 planning?
3 A I suppose there is, I mean, to the extent
4 that you have to make some assumptions and my guess is it
5 would be reflected in a load forecast, especially if it
6 was standards in buildings that would apply to the future
7 that would impact loads kind of from a forecast
S standpoint.
9 MS. BRIDGE: Thank you, Mr. Bokenkamp. No
10 further questions.
11 COMMISSIONER KEMPTON: Thank you, Ms.
12 Bridge. Mr. Woodbury.
13 MR. WOODBURY: Thank you, Mr. Chairman.
14
15 CROSS-EXAMINATION
1 7 BY MR. WOODBURY:
18 Q Mr. Bokenkamp, one of your primary duties
19 is preparation of integrated resource plans?
20 A One of the primary areas that I'm
21 responsible for, yes.
22 Q And you participated in the 2006 plan and
23 the 200S update?
24
25
A I participated in the 2006 plan and
somewhat in the 2008 update, yes.
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21
22
23
24
25
1 Q What kind of a filing was the 200S update,
2 do you know? You talk about the Company normally updates
3 its load resources in August of every year, that wasn't
4 that type of a filing, was it?
5 A No, I don't think so. I mean, the filing
6 was as a result, I think as Mr. Gale had mentioned, there
7 was an effort to synch the integrated resource plans up
8 between the three Idaho utili ties.
9 Q Okay, but that wasn't your IRP filing
10 because we had moved that to June of 2009; correct?
11 A That's correct.
12 Q Okay, in your rebuttal on page 3 you state
13 that the Company's current forecasts of loads and
14 resources indicate an additional resource such as Langley
15 Gulch is needed in 2012. You're referring to your May
16 2009 load forecast?
17 A Yes, that's the one that was used for
18 Exhibit 10.
19 Q And in the year 2012, you actually feel
that the need is in June of 2012 and that is when you
would like to bring the resource on;is that correct?
A Yes,that's when we would like to see
it.
Q Idaho --on,I think,page 4,lines 4
through 6,you state that the Company is still proj ecting
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Idaho Power Company
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1 average energy deficits during July of 2009 through 2012
2 of 365, 368, 421 and 285 average megawatts. How is the
3 Company able to satisfy the deficits in 2009 through
2011 ?
A We'll have to be importing on non-firm.
Q Okay,and if the Company can satisfy those
deficits in those years,why isn't it able to satisfy
them in 2012 in the same manner?
4
5
6
7
8
9 A I can't say that we couldn't satisfy it in
10 2012, but again, we'd be relying on non-firm transmission
11 to a certain extent anyway.
12 Q The 285 average megawatt figure for 2012,
13 that was a figure with Langley on-line?
14 A Yes.
15 Okay, and in those most recentQ in those
16 energy deficit numbers, are you factoring out the
17 Boardman-Hemingway? Have you already factored that out
18 to 2015, that it won't be on-line in 2012?
19 A Yes.
Q Okay. I was reading through your
21 testimony, looking at page 8, this is in your rebuttal,
22 line 18, you compute the amount of energy needed in July
23 2012 to maintain load-resource balance without Langley
24 and you have peak hour 432 and an average energy deficit
25 of 650 and then on page 5, line 1, you compute the
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1 average energy deficit in July 2012 without Langley and.
2 you have peak hour of 279 and average energy deficit of
3 497. Shouldn't those numbers be the same? I think I'm
4 probably reading them wrong. It seems like it's the same
5 number that you say you're calculating.
6 A I think there's a little difference there.
7 One of them I believe in the numbers that I start with
S on page 8 are merely looking at not just the deficit but
9 the amount of energy, so it's the amount of energy that
10 we're going to need and it would include, if you note in
11 line 1 on page 9, I do go ahead and mention part of that
12 650 is the 114 of imports from the Pacific Northwest.
13 Q Okay; so the amount of energy needed is
14 not equal to the average energy deficit?
15 A Well, in the prior example, the 114 from
16 the Pacific Northwest was just assumed to be there and
17 then the deficit was after that, so the deficit would be
is what was left over after that 114 was used.
19 Q Okay, you indicate in your rebuttal on
20 page 19 that the Benchmark -- well, let me ask you this
21 question first: Are the evaluation criteria that the
22 Company used, are those confidential?
23 A The criteria -- the evaluation manual we
24 considered confidential. Some of the criteria, I think
25 we actually communicated that in the RFP largely.
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Q All right, the evaluation criteria stated
that an overall score for the bidders would be compared
3 based on equal weighting of five-, eight- and 20-year
4 scores; is that correct?
5 A I believe that's correct in the evaluation
8 for all of the bidders?
And did you compute those, that weighting
6 manual.
7 Q
I believe we did.
Huh?
I believe we did for the bidders that made
12 it to that point in the evaluation.
9 A
But you state that the Company had the
14 best 20-year NPV, did you also have the best average
A
Q
A
Q
I don't know that we calculated the best
Did the evaluation manual say that the
19 terminal value would be considered in scoring?
10 Q
No, it didn't.
No?
23 considered either.
No, but it didn't say it wouldn't be
24
25
11 A
Wasn't the evaluation manual to be
considered all inclusive as far as the factors that would
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13 Q
20
21
22
15 weighted NPV?
16 A
17 weighted NPV.
18 Q
344 BOKENKAP (X)
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1 be weighed and considered by the team?
2 A Well, I would say generally, yes.
3 Q So you're saying that it's not totally
4 transparent as far as what factors would be considered by
5 the team?
6 A I guess you could say that. I mean, to
7 the extent you would consider that as part of a price
8 evaluation, it can be reduced to price.
9 Q Do you expect any -- you're in the process
10 of completing and preparing the 2009 IRP, do you expect
11 any change in the preferred supply side resource type or
12 timing to come out in that?
13 A It wouldn't surprise me if we have some
14 change in timing as a result of the 2009 IRP.
15 Q And can you describe generally the lead
16 time required for the resource of Langley? I read
17 somewhere that it's three years from time of selection.
18 A I had that in my testimony.
19 Q And is that a good number still?
A Well, I guess we were looking at selecting
21 a winner in early 2009, March, I mean, it's when we filed
22 our application, and we were looking for it to be
23 on-line, if everything originally would have stayed with
24 that plan, would have been June of 2012 and then
25 start-up, so it's about three years.
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1 Q Okay. Referring to your Exhibit No.4,
2 and that was the letter from R. W. Beck indicating the
3 nature of services that they provide, on page 2 -- you've
4 reviewed this letter?
5 A I have.
6 Q And does the 17 points that they detail
7 there generally reflect the services provided or do you
S feel that there were additional services that weren't
9 included?
10 A When I reviewed it, I thought it was a
11 reasonable representation of what they did.
12 Q And the team consisted of how many
13 individuals at R. W. Beck?
14 A I believe there were eight plus myself and
15 then two other people --
16 Q This is the evaluation team you're talking
17 about. I was talking about the R. W. Beck team.
A Oh, I'm sorry. There were a handful of
19 folks. I mean, on our contract I think we've listed
20 maybe five or six in addition to Steve, maybe more like
21 four, somewhere in that range.
22 Q Did Idaho Power accept build and
23 transfer well could you define build and transfer
24 because I think we've had some definitional problems
25 here? I tried to equate it with a turnkey type of
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1 facility.
2 A I think your equating it to turnkey is
3 fairly reasonable. I would interpret it as a developer
4 developing a project through a certain point, getting the
5 project up on-line, probably meeting or ensuring that
6 certain performance guarantees have been met and
7 performance tests, and then at some point, predetermined
8 point, the proj ect transfers to the ultimate -- to the
9 utili ty in this instance.
10 Q Were you involved in the Company's RFP' s
11 for Danskin and Bennett Mountain?
12 A I was involved in Danskin.
13 Q Dans kin 1? Dans kin 2 and 3?
14 A I'm sorry, I was involved in Bennett
15 Mountain. I was involved in the work on Danskin 2 and 3
16 and I had very little involvement in Danskin 1.
17 Q And did Idaho Power solicit build and
18 transfer proposals for those facilities?
19 A For Danskin 2 and 3 I wouldn't have
20 considered that a build and transfer. We just got a
21 contractor to build the proj ect. Anyway, I'm not really
22 sure, I guess, how I would characterize that one.
23 Bennett Mountain, I would characterize that as a build
24 and transfer.
25 Q Do you anticipate that the Company will
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1 solici t build and transfer proposals in future RFP' s?
2 A It might. It would probably depend on the
3 resource.
4 Q Do you know in the, I guess, Company's
5 prior RFP' s for build and transfer, did the Company
6 prepare detailed specifications to ensure uniform design
7 criteria between projects?
8 A For the Bennett Mountain one we did not
9 prepare detailed design criteria.
10 Q You did not. Was it because you didn't
11 have enough lead time to do that?
12 A No, it was a -- I would say primarily
13 because it was a simple cycle proj ect.
14 Q Are the transmission costs considered in
15 the bid evaluation for the Benchmark proposal the same
16 costs the Company has included in its application or is
17 the Company requesting some additional, I guess, system
18 betterment for those two transmission projects?
19 A I'm not posi ti ve of the exact difference
20 in those numbers or if there is one. There may be a
21 little bit more in the commitment estimate. I'm just not
22 sure.
23 Q Would Mr. Porter be a better person to
24 ask?
25 A I think so.
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Idaho Power Company
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1 Q Okay, good. On page 15 of your testimony,
2 you speak about difficulty of financing the proj ect and
3 without -- you say given the current economic crisis, the
4 Company anticipates difficulty without receiving a
5 certificate and the ratemaking treatment that's
6 requested. Would Ms. Smith be the better person to talk
7 to about the current financial situation and the
S Company's ability to finance?
9 A Yes, she would.
10 Q On page 17 and 18 of your testimony, you
11 state the treatment of costs associated with not
12 selecting the Benchmark resource and you identify those
13 as equipment deposits, reservation fees, cancellation
14 charges and other penal ties or costs and you state that
15 they were not considered in the bid evaluation. Were
16 those costs unknown to the evaluators?
17 A Could you give me a page reference and
lS line on that?
19 Q Yeah, I think it's your direct testimony,
20 page 17 and 18. Do you see it at the bottom of 17?
21 A I see it now. I don't know that -- I
22 imagine some of the people may have known those numbers.
23 The point, I guess, was that the cancellation costs were
24 not a hurdle, if you will, for any other bidders, so that
25 a bidder would have had to have scored by more than the
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19
20
21
22
23
24
25
1 amount -- actually would have had to have, say, won by
2 more than the amount of the cancellation costs. That was
3 not an issue.
4 Q In your rebuttal testimony on pages 25 and
5 26, you speak of an exhibit, I believe, offered as
6 Exhibit 205. It's one of Dr. Reading's exhibits and it
7 was, I believe, a letter from a bidder and it was
8 offering criticisms of the process, I think. This person
9 withdrew and you discount the criticisms as not being
10 legitimate, but wouldn't you agree that they felt that
11 they provided a letter to the Company voicing those as
12 being that they were legitimate in that bidder's mind?
13 A Yes, I agree with that.
14 MR. WOODBURY: Thank you, Mr. Bokenkamp.
15 Mr. Chairman, Staff has no further questions.
16 COMMISSIONER KEMPTON: Thank you,
17 Mr. Woodbury. Commissioner Redford.
18
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Idaho Power Company
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1 EXAMINATION
2
3 BY COMMISSIONER REDFORD:
4 Q Mr. Bokenkamp, on the bench -- you were a
5 leader of the Benchmark team?
6 A That's correct. No, I'm sorry, I was the
7 leader of the RFP team.
8 Q Excuse me?
9 A I was the leader of the RFP evaluation
10 team. Mr. Porter was the leader of the Benchmark
11 resource.
12 Q Fine. Did you have anything to do with
13 establishing the bidder criteria manual, the evaluation
14 manual?
15 A Yes.
16 Q And it's my understanding from one of the
17 previous witnesses that those criteria or the evaluation
18 cri teria were only partially given to the bidders.
19
20
A Generally, I'd say that's correct.
Q So there were other items that you had in
21 your back pocket that they didn't know about?
22 A Well, I don't know that I'd say that there
23 were other items in our back pocket. They didn't -- in
24 the RFP, we communicated that it would be, the evaluation
25 would be, based on price and non-price and that it would
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351 BOKENKAMP (Com)
Idaho Power Company
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1 be 60 points on price, 40 points on non-price and we
2 provided a number of categories that would comprise the
3 non-price points, areas that we would be looking at as
4 well as the distribution of the non-price points for each
5 of those areas.
6 Q When you were evaluating the bids, did you
7 mark Benchmark down because of the financing
8 uncertainty?
9 A I don't recall whether personally I did or
Well, there is uncertainty and a category
12 that talks about financial strength?
10 not.
11 Q
Yes.
So you don't recall what you did with the
15 Benchmark on financial strength?
13 A
14 Q
16 A
17 one, no.
18 Q
I don't recall exactly how I scored that
Okay. Did you also tell the bidders that
19 you were going to evaluate their bids on the basis of net
20 present value?
21 A I don't recall precisely whether the RFP
22 manual said net present value or not. We definitely said
23 price.
24
25
Q
the criteria
Well, you used net present value as one of
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352 BOKENKAMP (Com)
Idaho Power Company
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1 A Yes.
2 Q -- did you not?
3 A That's correct.
4 Q So on page 2 you talk about the net
5 present value of its 20-year revenue requirement is
6 approximately $95 million less than the next closest
7 combined cycle proj ect .
s A Yes.
9 Q How on earth could any contractor have
10 calculated a bid based upon that standard?
11 A Well, I suppose it would have been
12 difficul t for a bidder to calculate a bid based on that.
13 That was our own internal assessment as to what the
14 impact would be on the net present value of our revenue
15 requirements over 20 years.
16 Q Didn't you also consider that by owning
17 the plant instead of a 20-year purchase price power
is agreement or a TA that in fact you calculated at the end
19 another 15 years that the plant would have for which you
20 would receive power?
21 A We just simply calculated a terminal value
22 of the asset at the end of a 20-year period.
23 Q And the fact that you would have the power
24 if you owned it for another 15 years in the life of the
25 plant, that had nothing to do with your evaluation?
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1 A Other than the fact that we calculated the
2 terminal value of it and then we included that in some of
3 the evaluation numbers. We didn't run an analysis to
4 look at the impact on net power supply cost for the next
5 15 years or so as a result of having that plant.
6 Q Well, I think you did from the standpoint
7 that you talked about instead of 95 million, you've
8 talked about 120 million at the end of the 15-year extra
9 life of the plant.
10 A Yes, the difference between those was one
11 of them was the evaluation of the revenue requirements
12 without considering the terminal value of the plant, so
13 we just assigned no value to it at the end of 20 years,
14 and the other one assigned a terminal value to the
15 proj ect at the end of 20 years.
16 Q How could a bidder respond to the
17 determination that you were going to use net present
18 value of the plant at the end of the 20 years? How could
19 they possibly bid that? First of all, they didn't know
20 about it, and secondly, if they did know about it, how
21 would they have bid that?
22
23
A I'm not sure how to respond.
Q Okay. You've also stated on page 2,
24 starting at line 14, you say, liThe selection of a
25 combined cycle proj ect will help to provide the up and
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20
1 down regulation necessary to integrate intermittent
2 resources as well as provide the Company with an option
3 to reduce its C02 emissions", so as I read this, it seems
4 to me that you're going to back down on your power
5 requirements from the coal-fired plants and replace it
6 with base load from the Langley project; is that what you
7 meant?
8 A Yes. Yes, by having that resource, it
9 would give us the ability to reduce our generation from
10 the coal-fired plants and to the extent it was replaced
11 by generation from a combined cycle plant, there would be
12 a net reduction in C02 emissions for the Company.
13 Q Did you tell the bidders about that?
14 A I don't think so.
15 Q Okay. I'd like to talk about the turbine
16 procurement from Siemens. When did you procure that
17 turbine?
18 A If I might, Mr. Porter would be the better
19 witness for those questions.
Q Now, you've talked about build and
21 transfer and you say at the end of the project after
22 commissioning, the developer would turn the plant over to
23 you and you would have ownership.
24
25
A Correct.
Q Do you make progress payments?
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1 A In Bennett Mountain, as I recall, we did
2 make progress payments, scheduled progress payments we
3 made throughout the proj ect development.
4 Q Doesn't the equipment and materials when
5 they come on the proj ect site become the owner's
6 property?
7 A In that instance I believe that they
8 were -- well, I'm not sure on that.
9 Q Okay; so you're financing it by progress
10 payments, but you're still talking about that it's the
11 contractor's property until they turn the plant over to
12 you in final commissioning?
13 A That's generally my understanding.
14 Q Okay. Oh, did the bids by the contractors
15 include design engineering; is that correct?
16 A The bids by the contractors would have
17 been inclusive of building and commissioning the entire
18 project.
19 Q So they would have done the design, site
20 preparation and all the other things that go with the
21 plant?
22
23
A Yes.
Q When you evaluated the bids on, for
24 instance, price, you started out with a $95 million
25 saving; is that what you did for the net present value?
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356 BOKENKAMP (Com)
Idaho Power Company
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1 A We evaluated the impact on the revenue
2 requirements for the Company and then looked at the
3 difference between the competing proj ects and actually,
4 earlier on we had a larger difference that we had
5 calculated.
6 Q So as far as the Company's bid was
7 concerned, the Company really wasn't or Benchmark really
8 wasn't competing against other bidders because you had
9 different rules for Idaho Power or Benchmark?
10 A Well , it was competing against other
11 bidders and I mean, we compared them side by side.
12 Q Except for net present value or for
13 procurement.
14 A The procurement for anyone who bid a
15 tolling agreement would have been reflected in their
16 price and the only difference, really, as I see it is the
17 terminal value piece of it, because at the end of the
18 contract for a tolling agreement, the bidder is left
19 owning that asset and we have to find something else to
20 replace the power; whereas, with the Benchmark at the end
21 of the 20-year period we have, the utility would have, a
22 power plant.
23 Q Don't you think the RFP would have
24 suggested that at the end of the 20 years that you have
25 an option to either purchase the plant or you would have
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357 BOKENKAMP (Com)
Idaho Power Company
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1 had an opportunity to bid for it on a power purchase
2 agreement or a tolling agreement?
3 A To renew the contract?
4 Q Yes.
5 A And that is certainly an option.
6 Q But you didn't tell the contractors
7 that?
8 A We actually encouraged them to bid at
9 least one five-year renewal term, that was required, so
10 it was 15 years, plus one five-year renewal term and we
11 encouraged them to propose other alternatives.
12 Q But you're really talking about 15 years,
13 aren't you?
14 A We talked about 15, plus a mandatory
15 five-year renewal term, one five-year renewal term, and
16 they could have bid any number of renewal terms or
17 offered to sell us the asset.
18 Q On page 21 you talk about at line 12 the
19 Company's RFP team calculated two sets of price scoring
20 for the short-listed proposals. The first set included
21 the as-bid costs without terminal value or any assessment
22 of imputed debt. Did you tell -- in your RFP, did you
23 tell the bidders that they would have to include imputed
24 debt as well?.25 A I don't believe we talked about imputed
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18
1 debt. We may have, but I don't recall. I don't think we
2 did, though.
3 Q On page 22, and I don't know whether I'm
4 getting into any confidential information, does the
5 redacted portion, is that the confidentiality as opposed
6 to non-redacted?
7 COMMISSIONER KEMPTON: It's shaded.
8 COMMISSIONER REDFORD: Shaded, okay.
9 Q BY COMMISSIONER REDFORD: Well, on line 7
10 you say I believe Mr. Sterling should have given more
11 recognition to the $95 million NPV difference in cost.
12 Did Mr. Sterling know about that?
13 A Yes, it was on the exhibits that we
14 produced through discovery.
15 Q Should I be asking Mr. Porter about the
16 EPC contract and contractor?
A Yes.
Q Okay. On page 23, starting at line 1, you
19 state that there are additional benefits associated with
20 Idaho Power owning the Langley Gulch proj ect. One is
21 flexibility in operations and maintenance. As the owner
22 and operator of the facility, Idaho Power will have a
23 high degree of flexibility in scheduling plant operations
24 and maintenance without contractual obligations
25 associated with a PPA or TA. Doesn't that language kind
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Idaho Power Company
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20
1 of give you the idea that no bidder can achieve that
2 without knowing it? I mean, he gets the benefit of the
3 upgrades and the flexibility and so on, doesn't he?
4 A If you're referring to, say, an upgrade,
5 if it was a fixed heat rate tolling contract and if the
6 bidder would elect to go ahead and make capital
7 investments in the plant to improve the heat rate, I
8 think those benefits would flow to the bidder and --
9 Q So excuse me, go ahead.
10 A and as far as the flexibility in
11 operations, simply with a tolling agreement there would
12 be some amount of contractual requirements regarding
13 notification, scheduling and so on and with it being our
14 own project, you'd have a little more flexibility
15 there.
16 Q So you knew that when you went into the
17 bidding process; correct?
18 A Correct.
Q And the bidder didn't know that?
A Well, i would think the bidder would be
21 aware that there would be certain contractual
22 requirements that they would -- obligations and rights
23 they would have under a tolling agreement and that if we
24 operated the project, we wouldn't necessarily be
25 operating under that agreement. We would just be
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1 operating our own proj ect.
2 Q Well, based upon all the things that
3 you've stated in your testimony, why did you do -- why
4 did you put out an RFP for bidding for a purchase power
5 agreement or a tolling agreement? It sounds like you had
6 no intention to award the contract to anybody but
7 Benchmar k.
8 A Well, we would have awarded it to -- I
9 mean, it wasn't a preconceived answer on there.
10 Q Okay, what criteria would you have awarded
11 the contract to other than Benchmark?
12 A Well, I think if we would have had a
13 significant difference in the NPV of the revenue
14 requirements and if we would have been able to assure
15 ourself that the imputed debt that may have been imputed
16 as a result of taking on that tolling agreement or power
17 purchase agreement, that that wouldn't have offset the
18 difference, then that's how we would have went. We
19 decided that we weren't going to consider imputed debt
20 unless the bids were very close.
21 Q But all that criteria the bidders did not
22 know; right?
23 A I don't believe the bidders knew about
24 imputed debt.
25 Q And NPV?
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1 A I don't know that we specifically
2 mentioned that in the RFP, but we did mention that we
3 would look at price and when we were looking at a 20-year
4 or 15-year plus a five-year extension on a power purchase
5 contract, it seems to me that that would be a reasonable
6 way to evaluate that is the NPV of the costs of that
7 proj ect over the period of evaluation.
8 Q Well, how is that fair to the bidders who
9 didn't know about it?
10 A I think the bidders would have -- I guess
11 it's my guess that the bidders would have assumed that
12 there would have been some evaluation over time that
13 would have looked at the cost of their proposal and
14 compared that to what the utility's costs were.
15 Q Well, if they should have assumed it, why
16 didn't you just put it in the RFP?
17 A We could have.
18 Q You also talk on page 24, and I realize
19 that this is a yellow page, but I think that you talk
20 about SSR which is a condition that can cause severe
21 damage to a turbine generator's main rotating shaft.
22 What did that play into the bidding process?
23 A It was just a factor that came up in the
24 transmission cost analysis.
25 Q Okay, did you tell the bidders they would
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1 have to take into consideration this SSR?
2 A The evaluation was done by the delivery
3 group. When they did their interconnection feasibility
4 study, they identified the SSR problems in those which
5 were a requirement that the bidders do to submit their
6 bid.
7 Q It was included in the RFP?
8 A The idea that they had to go through and
9 do a generator or an interconnection feasibility study
10 was a requirement of the RFP.
11 Q But it didn't specifically talk about
12 SSR?
13 A No, it didn't.
14 Q Okay. How much was the -- again, I'm
15 referring to page 25, how many points were given for
16 financial capability? I think you say it's two points.
17 Oh, no, how many points were given for financial
18 responsibili ty?
19 A I believe I have a copy of the evaluation
20 manual with me. If I may, I'd like to refer to it.
21 Q Well, I would suggest, and if you prefer
22 to check, that it was two points.
23 A Okay. I think it was either three or
24 five.
25 Q Okay. Well, and you don't know whether or
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1 not you evaluated the Benchmark group on the basis of
2 financing capability?
3 A I've pulled out the evaluation manual and
4 the criteria was credit factors and financial strength
5 and that was five points.
6 Q Five points?
7 A Yes.
8 Q How much did you give to Benchmark, how
9 many points?
10 A I don't recall offhand. We'd have to
11 check that.
12 Q If you were uncertain about the ability to
13 obtain credit, wouldn't you mark down the Benchmark group
14 because it was an uncertainty?
15 A As I recall, I mean, at the time we did
16 that, there was uncertainty on everybody, really, from a
17 financial standpoint and I don't remember the exact
18 scores, but it didn't seem to me like -- well, I just
19 don't recall what the exact scores were on that.
20 Q On page 25 at line 17, you said that there
21 was only two points separating the non-price scores of
22 the short-listed combined cycle projects, the non-price
23 scores were not a significant differentiator. If you
24 hadn't scored Benchmark as creditworthy and the
25 financing, it would have meant that one of the bidders
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1 would have received five points.
2 A Actually, there wasn't a requirement that
3 anyone receive all points in any of those categories, so,
4 again, I don't recall the exact number, but out of that
5 40 points, I think most I mean, the numbers were
6 around 30, as I recall, so I don't know that anyone got
7 all the points on that one. In fact, subj ect to check, I
S mean, I think everybody was down some on the credit
9 score.
10 Q Okay. Well, we're going to get the
11 evaluation manual tomorrow. I believe you said I should
12 ask Mr. Porter about this, but your direct testimony on
13 page 26 starting at line 19 kind of allays that idea.
14 You say the question of equipment transfer was further
15 addressed in response to question No. 3 of the 2012
16 base load RFP questions and answers document that was
17 posted on Idaho Power's website. The Company indicated
is that it was not offering the Benchmark resource equipment
19 to the other bidders to maintain its flexibility to
20 select multiple proposals if agreements with potential
21 new large load customers were finalized, so in fact you
22 did have something to do with the procurement of the
23 turbines?
24 A No. It was simply the decision that the
25 Company -- I think what we're referring to there is that
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1 the Company had decided that it was not going to make
2 that equipment available to other bidders and in fact, as
3 outlined in Mr. Porter's testimony, we didn't have the
4 right to assign it at that point in time.
5 Q I think you're incorrect because that
6 language in the procurement contract says that there will
7 be no transfer of equipment unless Siemens approves it
8 and that approval will not be unreasonably withheld, so
9 in fact, you made the decision that you weren't going to
10 transfer that equipment regardless?
11 A I'm not sure of the timing of when those
12 agreements were actually signed, but it was my
13 understanding at the time we didn't have the right to
14 unilaterally transfer that equipment. I could be
15 wrong.
16 Q Well, we'll ask Mr. Porter about that, but
17 it seems like that's another gotcha for bidders. What
18 would they have had to do if you weren't going to
19 transfer that property, would they have then had to make
20 a commitment to Siemens to the tune of 8 or $9 million to
21 get in the queue for the turbines?
22 A No, sir. The bidders were free to make
23 their independent arrangements with turbine suppliers.
24 In fact, two of the bidders that made the short list
25 already had equipment that they owned that they bid into
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1 the process, so they brought their equipment to the RFP
2 or at least portions of their equipment.
3 Q Also something I find very remarkable, on
4 page 27 and the lead-in is kind of what if you had
5 selected one of the other contractors, what would you do
6 with the turbine, you said on line 10, subsequently, by
7 not offering the equipment to other developers before the
8 conclusion of the RFP process, Idaho Power retained the
9 option to use this equipment to build a second plant if
10 new large loads materialized. I find that statement
11 overwhelming. You were going to buy a turbine and I
12 don't know what the cost of the turbine is, but you had
13 to pay 8 or $9 million to get the commitment, so you were
14 just going to let the turbine sit around and you weren't
15 going to use it unless you decided to build another
16 plant?
A When we entered the RFP process, we had no
18 guarantee that anyone was going to show up with a bid or
19 that anyone who showed up with a bid would be even
20 marginally creditworthy. I mean, we just didn't know.
21 At the time it was from a planning standpoint, it was a
22 difficul t time. We were negotiating with numerous large
23 loads and that's why the RFP was originally issued for, I
24 think we said, 250 to 600 megawatts or we listed a range
25 and it was because of the uncertainty with specifically
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1 one very large load that we thought was going to locate
2 in our service terri tory and so we just simply did not
3 know what was going to happen.
4 As we continued to negotiate with that
5 bidder, it became apparent because we had to provide --
6 sorry, with that load, as we negotiated with that load,
7 we had to give the bidders some guidance on what we were
8 actually looking for and in June, we clarified the RFP to
9 approximately 300 megawatts and the idea of us having
10 that other equipment if that load would have
11 materialized, then we would have had an option to serve
12 that load.
13 Q But you haven't answered my question when
14 I asked you would you just let that turbine sit around
15 gathering dust until the loads were of such a magnitude
16 that you wanted to build another combined cycle plant.
A No, sir, I don't think we would have done
is that.
19 Q Well, it's what you said. You said, tell
20 me if I'm wrong, subsequently, by not offering the
21 equipment to other developers before the conclusion of
22 the RFP process, Idaho Power retained the option to use
23 this equipment to build a second plant if new large loads
24 materialized.
25 A Yes, that's correct. By having the rights
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1 to that equipment, we would have had the option to use
2 that equipment to construct a second plant had the large
3 loads materialized. Had they not materialized, we would
4 have been free to sell that equipment or transfer it to
5 others subj ect to whatever agreements we had in place
6 with Siemens.
7 Q But you wouldn't offer that or extend that
8 offer to the bidders?
9 A Well, at the time we didn't know what was
10 going to happen with the large loads, nor did we know who
11 was going to show up.
12 Q I believe Mr. Woodbury questioned you
13 about one of the bidder's letters and based upon what
14 we've talked about today, it seems fairly credible that
15 that bidder when he stated that it seems to imply that
16 the outcome of the RFP was predetermined, you've said
17 that is simply false, would you expand on that?
18 A Certainly. As I noted earlier, the bid
19 was -- I mean, the process was not predetermined and if
20 someone that brought equipment to the project, for
21 example, that had one that would have -- well, anyone
22 that would have offered a tolling agreement that brought
23 significant value to the customers, if it would have beat
24 the self-build proposal, that's what we would have
25 selected.
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1 Q When you were going out for procurement,
2 why didn't you offer a turnkey operation which would be
3 EPCM, engineering, procurement, contract and
4 management?
5 A Mr. Porter has addressed this in his
6 testimony and if it would be all right, I would refer
7 that question to Mr. Porter.
8 Q But you were the evaluator, he wasn't.
9 A And I did address that. I mean, our
10 concern was that without a detailed specification for the
11 project, it would introduce a fair degree of subjectivity
12 into the evaluation because of the numerous design
13 differences that could exist between the different
14 proj ects bid into the RFP.
15 Q But you know you're going to have to have
16 a turbine regardless; right?
17 A Assuming it was a combustion turbine
18 plant, yes.
19 Q How much did you pay for the turbine over
20 and above or are you obligated to pay to receive the
21 turbine?
22 A I'm not sure. I think that question would
23 probably be better for Mr. Porter.
24
25
Q Well, was it in the magnitude of
millions?
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1 A In terms of what we are paying for a
2 contract price for it or for the -- certainly, it was in
3 the millions.
4 Q And you suggest that bidders had those
5 kinds of pieces of equipment just laying around?
6 A Yes, two bidders did. In fact, one bidder
7 had multiple.
8 Q There was some question about the Oregon
9 guidelines and you have filed with the Oregon Commission
10 to waive the procurement or waive the Oregon regulations
11 on procuring bids and have you heard anything from the
12 Oregon Commission?
13 A Are you referring to the Langley Gulch
14 project?
15 Q Yes.
16 A I think Ric addressed that in his
17 testimony and as I recall, we pulled our motion for a
18 waiver, so that will be addressed in the next rate case,
19 whenever the proj ect would come up.
20
21
22
Q In the Oregon rate case?
A Yes.
Q Okay. You seem to base or you seem to
23 criticize the Oregon procedure on the basis that it just
24 takes too long and you say if it takes a year to develop
25 the guidelines, two years to complete the RFP process and
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371 BOKENKAP (Com)
Idaho Power Company
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1 approximately three years for the project design and
2 construction, a resource like Langley Gulch would not be
3 on-line and available to serve customer loads before
4 mid-2015 and you somehow seem to blame that on the Oregon
5 Commission.
6 A It wasn't necessarily my intent to blame
7 that on the Oregon Commission. It was just simply -- in
8 fact, I shortened the numbers from what it took in the
9 Oregon process just as an estimate to give an example.
10 In Ric's testimony, I believe he mentioned that
11 PacifiCorp had dropped their request after two-and-a-half
12 years and so I guess really the bottom line there is that
13 the guidelines added time to the RFP process. That's
14 simply the point.
15 Q Is there anything else that was hidden
16 from the bidders that you haven't, we haven't covered by
17 my questions, other criteria that you didn't tell? Isn't
is it a fact that it's the policy of Idaho Power to own and
19 operate its own facilities?
20 A I don't think that would be the policy of
21 the Company. I mean, we own a number of resources, but
22 we just did a 20-year PPA on a wind contract, for a wind
23 project, for the Elkhorn project, we don't own that
24 proj ect. We have a number of PURPA contracts that supply
25 us that we don't own. We're in the process of looking to
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372 BOKENKAP (Com)
Idaho Power Company
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20
1 acquire geothermal resources which would be under a power
2 purchase agreement as well.
3 Q Those are PURPA proj ects, aren't they?
4 A They could be. We do have one geothermal
5 that's under a PURPA contract. We were actually
6 looking to acquire additional geothermal outside
7 actually, I'm sorry, the U. S. Geothermal one actually
8 started under a PURPA contract, but it's outside of PURPA
9 now, and we were actually negotiating with another
10 supplier, actually, a couple of other potential
11 geothermal suppliers, that would provide energy to us
12 outside of the PURPA arena.
13 COMMISSIONER REDFORD: Well, I don't have
14 any further questions. Thank you very much.
15 COMMISSIONER KEMPTON: Commissioner
16 Smith.
17 COMMISSIONER SMITH: No questions.
is
19 EXAMINATION
21 BY COMMISSIONER KEMPTON:
22 Mr. Bokenkamp, on page 16 of your direct
23 testimony, line 13, there's this sequencing schedule
24 again that bothers me in just trying to understand what's.25 really going on. This one -- first of all, would you
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373 BOKENKAMP (Com)
Idaho Power Company
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1 tell me what the difference is between being on-line,
2 being operational and going commercial, those three
3 terms?
4 A Certainly. On-line would just simply be
5 that the proj ect actually has connected to the grid and
6 is generating electricity or is in the process of -- is
7 doing that, so it would be on-line as opposed to
8 off-line. On-line would be connected and generating.
9 Off-line would not be and --
10 Q Commercial?
11 A -- commercial operation would be at the
12 point when the Company just declares the proj ect to be
13 commercial. It may involve a certain period of shake-out
14 to work through many start-up issues with the proj ect.
15 Essentially, it's reliable at that point.
16 Q Is that commensurate with being used and
17 useful?
18 A Yes, I think that would be appropriate.
19 Q Assuming that a notice to proceed is
20 issued on September 1st, 2009, this is the timing that
21 the Company expects the PUC to be able to reach a
22 decision and I guess we should go up to line 4 first, the
23 Company estimates that it may take up to six months to
24 obtain a CPCN containing the needed regulatory.25 assurances, and then dropping down to 13, assuming that a
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374 BOKENKAMP (Com)
Idaho Power Company
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1 notice to proceed is issued on September 1st, 2009, the
2 project is expected to be on-line in October 2012, and in
3 commercial operation on December 1st. What goes on in
4 the process of being hooked up and on-line and actually
5 going into commercial operation, recognizing that there
6 is some testing you would normally expect, but it seems
7 that's quite a long period of time to go from on-line to
8 commercial?
9 A In a lot of instances I think what would
10 happen there would depend on the problems encountered
11 during the start-up. If everything went smooth, I don't
12 think there would be anything to prevent it from being
13 put into commercial sooner.
14 Q The same thing could be said of the
15 Commission's decision in six months, it kind of depends
16 on if anything goes wrong, and so, again, what I'm doing
17 is looking for slack in the scheduling process where
18 there might be room for some slack in trying to get to
19 this collection of data in the September time frame,
20 August/September time frame, and maybe some initial
21 information on sales and load by October, sometime in
22 there. I'm fishing and I don't have specifics, but it's
23 just bothersome that we're running into this in a
24 constrained fashion where we're pressed on both sides, so
25 Mr. Bokenkamp, again, in moving natural gas in preference
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375 BOKENKAMP (Com)
Idaho Power Company
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1 to coal, in other words, if Langley Gulch comes on, you
2 could actually assume some portion of coal from the
3 different coal plants you have, Jim Bridger, Valmy,
4 whatever, but again, how do you actually do that?
5 Redispatch was mentioned as one possibility. How would
6 you define redispatch working in that case?
7 A I think there's probably two ways that
8 this could happen. One is that as a result of future
9 carbon regulations, if there winds up in effect being a
10 price put on C02 emissions, we would factor that into our
11 dispatch calculations which would in effect raise the
12 cost of running a coal-fired plant if for each ton of C02
13 that we emitted we were obligated to pay a certain amount
14 of money for that ton, so it would just be considered a
15 variable cost that would factor into the operation of the
16 proj ect . The
17 Q Excuse me, but how does that help in
18 how does Langley Gulch affect you doing that? Yes, I
19 mean, I think everybody would expect you would raise the
20 cost associated with whatever carbon criteria is assessed
21 against the Company.
22 A So assuming Langley Gulch was on-line and
23 depending on what the gas prices were and the carbon tax,
24 it may dispatch ahead of the coal-fired units. That
25 could happen, so that would be one way that it would
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376 BOKENKAP (Com)
Idaho Power Company
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20
1 reduce emissions from the coal-fired projects if it
2 simply dispatched ahead of it. The other example would
3 be if the coal-fired generation was just simply reduced
4 during times that we made surplus sales. That's one way
5 that you could reduce the C02 emissions as well. That
6 wouldn't necessarily be dependent upon having Langley
7 Gulch if it were simply surplus sales, but if it was to
8 serve load, we would have to replace it with something
9 else.
10 Q So in any of this when you talk about
11 replacing, you're not talking about reducing the
12 commitment that you have in any contractual relationships
13 wi th any of the coal producing plants; is that correct?
14 A No, it would just simply be a different
15 utilization of the asset as long as it was permitted
16 under our agreement with the proj ect. I mean, we would
17 have, you know, certain agreements in there. We would
18 have to factor that into our coal obligations to the
19 extent we were going to run them less.
Q But if you're front-ending the Langley
21 Gulch or any of the natural gas producing plants, you're
22 front-ending that, you're still producing, you're still
23 having to accept the same amount of power delivered from
24 the coal resource; is that correct?
25 A No, we don't necessarily need to accept
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377 BOKENKAMP (Com)
Idaho Power Company
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1 the power from the coal resource. We can dispatch our
2 share down or we could in fact just, you know, reduce our
3 take from the proj ect whenever we want or we could back
4 out.
5 Q And so that would mean one of two things:
6 Ei ther the plant would have to trim back or the other
7 users of the plant would have to accept additional
8 generation from the plant; isn't that correct? How can
9 you back down your part if you don't shift it
10 someplace?
11 A No, that's correct, it would shift, I
12 mean, or the plant would back down.
13 Q And as you trim the plant -- so both of
14 those affect your other partners in the plant? If you
15 back down, you're trimming the boilers down and so you're
16 operating less efficiently which increases the cost of
17 the power produced; correct or incorrect?
18 A Typically at lower loads the plants would
19 typically be less efficient.
20 Q Or otherwise, those same partners, whoever
21 is contracted to take that power, would assume more and
22 thereby, you would presume that they wouldn't be too
23 anxious to do that if there are penal ties associated
24 additional carbon emission.
25 A Yeah, they wouldn't be obligated to take
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378 BOKENKAMP (Com)
Idaho Power Company
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1 our share. Under one of the contracts, we do have
2 provisions that allow one party to use the other party's
3 share of the plant.
4 Q So isn't it fair to say that you would
5 have contractual problems or at least you would have
6 contractual issues, whether they would be problems or
7 not, you would have contractual issues associated with
8 backing out of the carbon producing plants, the coal
9 plants?
10 A Well, we might, but I mean, we back out of
11 the plants during runoff times frequently anyway, so I
12 mean, that's something that we do.
13 COMMISSIONER KEMPTON: Okay. Let's see, I
14 have no further questions and redirect.
15 MR. KLINE: I do have a few.
16
17 REDIRECT EXAMINATION
18
19 BY MR. KLINE:
20 Q In his cross-examination of you,
21 Mr. Bokenkamp, Mr. Richardson talked about the Company's
22 use of non-firm transmission to serve load, particularly
23 during the peak summer times, summer hours. He used the
24 term kind of manage and handle, how the Company could
manage and handle its loads by using non-firm
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379 BOKENKAMP (Di)
Idaho Power Company
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.
1 transmission. What's so bad about that?
2 A Well, that transmission could get cut, so
3 we don't necessarily we can't really guarantee that we
4 can continue to deliver to our customers and in fact, if
5 it's across the -- if it's from the Pacific Northwest and
6 we're taking non-firm transmission and as long as the
7 other users that have been allocated transmission are
8 using their share, then the non-firm that we would be
9 using would be part of the transmission reliability
10 margin or the capacity benefit margin which would be held
11 to -- well, held in case we experienced problems on the
12 transmission system, such as loop flow or other outages
13 or an outage at a Bridger project, so we would in fact
14 already be using the transmission that was reserved for
15 some of those other events.
16 Q So if you are using your transmission
17 reserves under that scenario you just described, you're
18 into your reserves, you're using your reserves to carry
19 load and something bad happens, fire goes through and
20 knocks out a transmission line, a plant kicks off and
21 you're into those reserves, what happens?
22
23
24.25
A Load would be at risk.
Q What does that mean?
A It means load could be shed.
Q So in order to bring your reserves back up
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380 BOKENKAMP (Di)
Idaho Power Company
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1 to where they're supposed to be, you could be required to
2 shed load, customer load?
3 A I suppose we might.
4 Q And again, Mr. Richardson talked about the
5 fact that you'd have these very large deficits in 2011
6 and a large deficit in '12 and a large deficit in '13 and
7 the Company has always operated like that. As the
8 manager of planning, do you have a high degree of comfort
9 with continuing to operate with those kinds of very large
10 deficits?
11 A No, it would be much better if we didn't
12 have to rely on non-firm transmission that much.
13 Q You also -- Mr. Richardson also asked you
14 what was magic about 2012, i mean, again, because you've
15 got deficits in '11, you've got deficits in '12, you've
16 got deficits in '13, is 2012 magic because that's the
17 first time you can get a resource built?
18 A Well, I think that is the, that's the
19 reason, yeah. That's what magic is about it. I don't
20 know that we'll get a combined cycle built any sooner
21 than that.
22 Q Well, without Langley going on-line in
23 2012 and having it available then and in the future, is
24 the Company better off or worse with Langley being
25 there?
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381 BOKENKAMP (Di )
Idaho Power Company
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1 A Well, the Company is definitely better
2 wi th Langley being there.
3 Q And better how?
4 A Well, better from several ways. One, it's
5 positioned to help integrate any other intermittent wind
6 resources that would happen. We're better positioned
7 from having resources located internal to the system and
8 better positioned from not having to rely on transmission
9 as much to import the energy, and furthermore, having the
10 resource, we wouldn't be subj ect to really having to rely
11 on market purchases that would come from an area that,
12 well, that in effect we would be relying on the market
13 being able to provide the energy. In this case, we'd
14 have the resource we could run.
15 Q Would you be better situated to avoid
16 curtailments and load shedding?
17 A Yes.
18 Q Just one leading question.
19 COMMISSIONER KEMPTON: Mr. Kline, while
20 you look that up, can I ask one question?
21
22
MR. KLINE: Of course.
COMMISSIONER KEMPTON: Do you mind if I do
23 that, recognizing I could anyway, but just so I don't
24 gets things messed up here. Mr. Bokenkamp, are there
25 any -- in the long-term planning and as you move forward
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382 BOKENKAMP ( Di)
Idaho Power Company
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1 when you talk about non-firm transmission, are there
2 addi tional penal ties associated with reliability
3 standards if in fact you take the additional risk of
4 using non-firm transmission?
5 THE WITNESS: I don't know of any specific
6 reliabili ty standards that would penalize us on that.
7 COMMISSIONER KEMPTON: That was it.
8 MR. KLINE: Okay.
9 Q BY MR. KLINE: Commissioner -- oh, before
10 I go there, there was also a fair amount of discussion in
11 the cross-examination about the ability of the Company to
12 operate its peaking units essentially as baseload units
13 for periods of time. Are there any issues associated
14 with air permits or air quality if you do that?
15 A There are permit conditions and I would
16 there are, at least on the smaller units, I know there
17 used to be some limitations on ours. I think they're
18 permitted as minor sources, so there would be some limit
19 on overall emissions.
20 Q Commissioner Redford asked you a number of
21 questions about bid evaluations that were done in this
22 case and particularly, the use of net present value as an
23 evaluation tool. Is net present value a unique way to
24 compare two revenue streams?.25 A No.
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383 BOKENKAMP (Di )
Idaho Power Company
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1 Q Has the Company ever used net present
2 value evaluations when it was doing RFP' s in the past?
3 A I believe we have.
4 Q Would the use of net present value to
5 compare two bids in your opinion have any effect on bid
6 prices that you received or the bids that were submitted?
7 Let me say it again. If the customers -- if the
S potential bidders knew you were going to use net present
9 value, would that change their bids?
10 A I don't think so.
11 Q All that really is, and correct me if I'm
12 wrong, is that you are taking this bid and this bid and
13 then you're running it through the revenue requirement
14 model and coming up with which is the cheapest of the two
15 resources?
16 A Yes.
17 Q Did Idaho Power utilize the terminal value
is to determine the winning RFP in this case?
19 A No, it actually would have won without the
20 terminal value.
21 Q By how much?
22 A It seems like it was around 30 million.
23 Q Sorry, I've got a lot of notes here, I
24 apologize. Mr. Richardson in his cross-examination.25 talked about the evaluation of the various resources
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384 BOKENKAP (Di )
Idaho Power Company
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1 taking into consideration their financial risk. Do you
2 recall that cross-examination?
3 A Not exactly.
4 Q Okay. There was -- in his
5 cross-examination, he asked if you discounted the
6 Benchmark resource due to possible financial risk. Do
7 you remember that?
8 A Vaguely.
9 Q Well, let me ask you this: Did you
10 discount power purchases or tolling agreements for their
11 financial risk?
12 A Yes. I mean, the financial risk of all of
13 the proposals were considered.
14 Q Considered equally?
15 A Yeah. Well, I mean, they were considered
16 equally. They may have received different scores, but
17 yeah, they were all considered.
18 Q And you didn't treat the Benchmark
19 resource gently and the others more harshly because they
20 were TA' s or PPA' s?
21 A No.
22 MR. KLINE: That's all I have.
23 COMMISSIONER KEMPTON: If there's no
24 obj ection, the witness may step down.
25 (The witness left the stand.)
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Idaho Power Company
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24
25
1 COMMISSIONER KEMPTON: I didn't hear any
2 obj ections. For tomorrow can anybody -- is there anybody
3 that cannot make a 9: 00 0' clock? I think we may still be
4 scheduled for 9: 30. I don't remember how that went
5 across our scheduling sheet in our office, but is 9: 00
6 0' clock satisfactory? If there is no obj ection --
7 COMMISSIONER REDFORD: As long as we have
8 donuts.
9 COMMISSIONER KEMPTON: Okay, having heard
10 no obj ection, we'll set 9: 00 0' clock for the beginning of
11 tomorrow's hearing and with that, this hearing is in
12 recess.
13 (The Hearing recessed at 5:40 p.m.)
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386 COLLOQUY