20090727Vol VI Technical Hearing.pdf

ORIGINAL.BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR A
CERTIFICATE OF PUBLIC CONVENIENCE
AND NECESSITY FOR THE LANGLEY
GULCH POWER PLANT
r
) CASE
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Idaho Public Utiliies Commission
Office of the SecretaryRECEIVED
NO. IPC-E-09-03
JUL 27 2009
Bois, Idaho
BEFORE
COMMISSIONER JIM KEMPTON (Presiding)
COMMISSIONER MARSHA SMITH
COMMISSIONER MACK REDFORD
.PLACE:Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE:July 15, 2009
VOLUME VI - Pages 672 - 1155
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CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone] * [phone]
Email csb(fheritagewifi.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. Kline, 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. Olsen, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
Susan K. Acker,an, Esq.
Attorney at Law
9883 NW Nottage Drive
Portlaad, Oregon 97229
Mr. Ken Miller
5400 West Franklin
Boise, Idaho 83705
Ms. Betsy Bridge, Esq.
Attorney at Law
Idaho Conservation League
Post Office Box 844
Boise, Idaho 83701
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For Industrial Customers
of Idaho Power:
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For Idaho Irrigation
Pumpers Association:
For NIPPC:
For Snake River Alliance:
For Idaho Conservation
League:
CSB REPORTING
[phone]
APPEARANCES
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1 EXHIBITS
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3 NUMBER DESCRI PTION
4 FOR I DAHO POWER COMPANY:
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5. Global Credit Research, Credit
Opinion: Idaho Power Company,
with attachments
Premarked
7 6. EEl, White Paper, Understanding
Debt Imputation Issues Premarked
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7. Illustrative Example of Annual
Rate Increase by Al ternati ve Premarked
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11 NUMBER DESCRIPTION
12 FOR THE STAFF:
13 101. Excerpt from 2008 Integrated
Resource Plan
Premarked
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102. 2006 IRP Average Energy Load
& Generation
Premarked
16 103. Monthly Average Energy Surplus!
Defici ts w! 0 Langley
Premarked
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104. Average Energy Monthly Surplus! Premarked
18 Deficit, May 2009 Load Forecast
19 105. Average Energy Monthly Surplus! Premarked
Deficit, May 2009 Load Forecast20 Reduction
21 106. Criteria Used for Scoring Qualified Premarked
Proposals
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107. Confidential exhibit sponsoredby Rick Sterling Premarked
PAGE
PAGE
108. Confidential exhibit sponsoredby Rick Sterling Premarked
CSB REPORTING
Wilder, Idaho 83676
EXHIBITS
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1 E X H I BIT S (Continued)
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3 NUMBER DESCRIPTION
4 FOR THE STAFF: (Continued)
5 109. Confidential exhibit sponsoredby Rick Sterling Premarked
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110. Confidential exhibit sponsoredby Rick Sterling"Premarked
8 111. Confidential exhibit sponsoredby Rick Sterling Premarked
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112. Confidential exhibit sponsoredby Rick Sterling Premarked
11 113. Confidential exhibit sponsoredby Rick Sterling Premarked
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114. Confidential exhibit sponsoredby Rick Sterling Premarked
14 115. Senate Bill No. 1123 Premarked
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16 FOR THE INDUSTRIAL CUSTOMERS OF IDAHO POWER:
17 201. CV of Don C. Reading Premarked
18 202. Attachment I, Proposal Summary Premarked
19 203. Idaho Power RPF Gas Forecasts Premarked
20 204. Idaho Power Scoring Summary Premarked
21 205. Confidential exhibit sponsored
by Don Reading
Premarked
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CSB REPORTING
Wilder, Idaho 83676
EXHIBITS
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1 E X H I BIT S (Continued)
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3 NUMBER DESCRIPTION PAGE
4 FOR NORTHWEST & INDEPENDENT POWER PRODUCERS COALITION:
5 701. CV of Don C. Reading Premarked
6 702 . Competitive Bidding Guidelines Premarked
7 703. Confidential exhibit sponsored
by Don Reading
Premarked
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CSB REPORTING
Wilder, Idaho 83676
EXHIBITS
1 I N D E X.2
3 WITNESS EXAMINATION BY PAGE
4 Lori Smith Ms.Nordstrom (Direct)672(Idaho Power)Prefiled Direct Testimony 6765Prefiled Rebuttal Testimony 696
Mr.Richardson (Cross)7076Mr.Miller (Cross)715Mr.Woodbury (Cross)7167Commissioner Kempton 726
Ms.Nordstrom (Redirect)7308Commissioner Redford 731
Ms.Nordstrom (Redirect)7379Commissioner Redford 742
10 Peter Pengilly Ms.Nordstrom (Direct-Reb)745( Idaho Power)Prefiled Rebuttal Testimony 74711Ms.Nordstrom (Direct-Reb)757Mr.Richardson (Cross-Reb)76312Mr.Purdy (Cross-Reb)765
Mr.Miller (Cross-Reb)77013Ms.Bridge (Cross-Reb)773.Mr.Woodbury (Cross-Reb)77914Commissioner Smith 780
15 Don Reading Mr.Richardson (Direct)783( ICIP)Prefiled Direct Testimony 78616Mr.Woodbury (Cross)842
Mr.Kline (Cross)84817Commissioner Smith 858
Commissioner Kempton 86118Mr.Richardson (Redirect)863
19 Don Reading Ms.Ackerman (Direct)864(NIPPC)Prefiled Direct Testimony 86820Mr.Kline (Cross)906Commissioner Redford 91221Commissioner Smith 915
Ms.Ackerman (Redirect)91622
Teri Ottens Mr.Purdy (Direct)91823(CAPAI)Prefiled Direct Testimony 920Ms.Nordstrom (Cross)93924Mr.Purdy (Redirect)944.25
CSB REPORTING INDEX(208 )890-5198
1.2 I N D E X (Continued)
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4 WITNESS EXAMINATION BY PAGE
5 Anthony Yankel Mr.Olsen (Direct)945(Irrigators)Prefiled Direct Testimony 9486Mr.Kline (Cross)1010
Mr.Olsen (Redirect)10137
Rick Sterling Mr.Woodbury (Direct)10158(Staff)Prefiled Direct Testimony 1019Mr.Kline (Cross)11089Mr.Richardson (Cross)1123
Mr.Miller (Cross)113510Commissioner Redford 1136Commissioner Smith 114711Commissioner Kempton 1149
Mr.Woodbury (Redirect)115312
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CSB REPORTING INDEX(208 )890-5198
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1 BOISE, IDAHO, WEDNESDAY, JULY 15,2009, 1:15 P. M.
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4 COMMISSIONER KEMPTON: The hearing will
5 come to order. Mr. Kline.
6 MR. KLINE: Mr. Chairman, Ms. Nordstrom.
7 COMMISSIONER KEMPTON: She will be running
8 the show?
9 MR. KLINE: Yes.
10 COMMISSIONER KEMPTON: That's good.
11 Ms. Nordstrom.
12 MS. NORDSTROM: Thank you. Idaho Power
13 calls Lori Smith as its next witness.
15 LORI SMITH,
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:
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21
DIRECT EXAMINATION
22 BY MS. NORDSTROM:
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24
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Q Good afternoon.
A Good afternoon.
Q Please state your name and spell your last
CSB REPORTING
[phone]
672 SMITH (Di)
Idaho Power Company
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1 name for the record.
2 A My name is Lori Smith and my last name is
3 spelled S-m-i-t-h.
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5 capacity?
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Q By whom are you employed and in what
A I'm employed by Idaho Power Company as the
7 vice president of corporate planning and chief risk
8 officer.
9 Q Are you the same Lori Smith that filed
10 direct testimony on March 6th and prepared Exhibits 5
11 through 7?
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A Yes.
Q Did you also file rebuttal testimony on
July 2nd, 2009 and prepared no exhibits for your
15 rebuttal?
16 A Yes, that's correct.
18 your testimony or exhibits?
Do you have any corrections or changes to
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17 Q
I have a few.
Please explain.
On page 14 of my direct testimony, on the
22 bottom of the page it says, "The proj ect is expected to
A
Q
A
23 take four years to construct...". Please replace
24 "construct" with "complete."
25 Q And that's the last line or line 13?
CSB REPORTING
[phone]
673 SMITH (Di)
Idaho Power Company
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1 A Yes, and on my direct rebuttal on page 3,
2 the table has a few numerical corrections, so I'll just
3 go down row by row. In the CWIP row --
4 COMMISSIONER SMITH: What page?
5 THE WITNESS: Oh, sorry, page 3 of my
6 direct rebuttal.
7 COMMISSIONER SMITH: Oh, I went too far,
8 sorry.
9 THE WITNESS: Okay, under the year 2005 in
10 the CWIP line, the number "149,804" should be "149,814,"
11 and then on the next row, the total capitalization line
12 for 2006, replace "2,255,190" with "1,927,761," and then
13 for the year 2005, "1,927,761" should be "1,921,038."
14 COMMISSIONER KEMPTON: What were the last
15 three again?
16 THE WITNESS: "038," and then the 2006
17 percentage would be "10.9 percent" and I apologize, I
18 didn't recalculate the 7.8 percent an9 I didn't bring a
19 calculator with me, so I'LL have to get that to you, and
20 then in the middle of page 3, same page on line 11, "one
21 large generation project" should be "one large
22 construction project."
23 . Q BY MS. NORDSTROM: Do you have any other
24 corrections?
25 A No, I do not.
CSB REPORTING
[phone]
674 SMITH (Di)
Idaho Power Company
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1 Q If I were to ask you the questions set out
2 in your pre filed testimony today, would your answers be
3 the same?
4 A Yes.
5 MS. NORDSTROM: I would move that the
6 prefiled direct and rebuttal testimony of Lori Smith be
7 spread upon the record as if read and Exhibits 5 through
8 7 be marked for identification.
9 COMMISSIONER KEMPTON: Without obj ection,
10 it is so ordered.
11 (The following prefiled direct and
12 rebuttal testimony of Ms. Lori Smith is spread upon the
13 record. )
CSB REPORTING
[phone]
675 SMITH (Di)
Idaho Power Company
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1 Q.Would you please state your name, business
2 address, and present occupation?
3 A.My name is Lori Smith and my business address
4 is 1221 West Idaho Street, Boise, Idaho. I am employed
5 by Idaho Power Company (" Idaho Power" or "Company") as
6 Vice President of Corporate Planning and Chief Risk
7 Officer.
8 Q.What is your educational background?
9 A.I graduated in 1983 from Boise State
10 University, Boise, Idaho, receiving a Bachelor of
11 Business Administration degree in Information Sciences.
12 In 1999, I was awarded the designation of Chartered
13 Financial Analyst. In 2008, I completed a two-part
14 course in Decision Analysis and Decision Quality in
15 Organizations at the Stanford Center for Professional
16 Development. I have also attended numerous seminars and
17 conferences related to utility accounting, corporate
18 finance, and risk related topics.
19 Q.Would you please outline your business
20 experience?
21 A.From 1983 to 1986, I was employed by Idaho
22 Power Company and assigned to the Materials Management
23 Department. From 1986 to 1994, I served as a Financial
24 Accountant and later as a Budget Accountant. I was
25 promoted to Business Analyst in 1994. In 1996, I was
676 SMITH, DI 1
Idaho Power Company
1 promoted to Strategic Analysis Team Leader. In 2000, I.2 assumed the position of Director of Strategic Analysis.
3 In 2003, I was named Director of Strategic Analysis and
4 Risk Management. In 2004, I was promoted to the position
5 of Vice President of Finance and Chief Risk Officer. In
6 2008, I assumed my current position as Vice President of
7 Corporate Planning and Chief Risk Officer.
8 Q.What are your duties as Vice President of
9 Corporate Planning and Chief Risk Officer?
10 A.My responsibilities include the oversight of
11 corporate development, strategic planning, and risk
12 management processes for Idaho Power Company. Corporate
13 development includes acquisitions, divestitures, and.14 joint-ventures. Strategic planning includes development
15 of analyses, strategies, and operating plans. Risk
16 management includes acti vi ties related to managing
l7 market, credit, and operational risk exposure from an
18 enterprise perspective.
19 I am tasked with ensuring the best use of Idaho
20 Power's resources by defining and planning the Company's
21 strategic and long-range goals. I am also responsible
22 for the analysis of the financial impacts of regulatory
23 strategy to ensure successful implementation and provide
24 meaningful insight into strategic alignment. I direct
25 the development of operational forecasts and analysis.
677 SMITH, DI 2
Idaho Power Company
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1 both long- and short-term. In addition, I am the
2 corporate board representative for Ida-West Energy and
3 IDACORP Financial Services. I have subsidiary leadership
4 responsibilities that include setting goals and defining
5 investment criteria and performance requirements. I
6 direct the acti vi ties related to the organi zation ' s
7 market risk and credit exposure to protect against
8 adverse movements in net power supply costs. Finally, I
9 am responsible for designing, developing, and
10 implementing an Enterprise Risk Management process for
11 IDACORP, Inc., and Idaho Power Company.
12 Q.What is the purpose of your testimony in this
13 proceeding?
14 A.I describe how Idaho Power's need for capital
15 to fund infrastructure and maintenance investments over
16 the next three years exceeds the cash flow it receives
17 from operations. It will be very difficult for Idaho
18 Power to finance the Langley Gulch power plant with debt
19 or equity given the current conditions in the capital
20 markets, the restructuring of which has resulted in
21 limited availability of credit and devalued stock prices.
22 Gi ven these adverse economic conditions, I believe the
23 proposed recovery of CWIP in rate base annually or the
24 regulatory ratemaking assurances described in Mr. Ric
25 Gale's testimony
678 SMITH, DI 3
Idaho Power Company
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1 will minimize Idaho Power's need to access the capital
2 markets and!or make the Company more attractive to
3 lenders if it does.
4 IDAHO POWER'S NEED FOR ADDITIONAL CAPITAL
5 Q.What is Idaho Power's current ability to fund
6 plant investments required to meet its customers' energy
7 needs over the next three years?
8 A.Idaho Power has been diligent in its efforts to
9 continue to meet the energy needs of its customers. This
10 has been demonstrated in the Company's Integrated
11 Resource Plan ("IRP"), the most recent of which was filed
12 in 2006 and updated in June 2008. The IRP has identified
13 the need for a baseload resource to come on-line in 2012.
14 As Mr. Karl Bokenkamp describes in his testimony, the 330
15 MW Langley Gulch power plant project ("Project")
16 identified through the competitive bidding process will
17 meet the growing customer demand for electricity in 2012.
18 However, the expenditures associated with this Proj ect
19 combined with the continued needs to upgrade existing
20 facilities, expand environmental controls, and maintain
21 an aging infrastructure, require the Company to expend a
22 significant amount of capital in order to meet these
23 needs.
24 These capital requirements come at a time when
25 the Company's balance sheet has been weakened due to the
679 SMITH, DI 4
Idaho Power Company
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1 impacts of drought conditions in six of the last seven
2 years and much higher historical capital expenditures
3 since 2006 to meet the demands of customer growth. The
4 cost of the new infrastructure, to be built concurrently
5 with current maintenance capital expenditures,
6 substantially exceeds Idaho Power's cash flow from
7 operations.
8 Q.What is cash flow from operations?
9 A.A simple measure of cash flow from operations
10 is seen in the average of depreciation expense plus net
11 operating income, a proxy for cash flow from operations.
12 During the time period 2006 through 2008, Idaho Power
13 Company generated on average approximately $190 million
14 of cash flow from operations. The average of
15 construction expenditures during this time was $250
16 million. The shortage of internally generated cash flows
17 versus Idaho Power's infrastructure investments, on
18 average, from 2006-2008 is $60 million per year. The
19 additional construction expenditures above cash flow from
20 operations must be acquired from the capital markets in a
21 balanced combination of long-term debt financing and
22 issuances of common stock.
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Q.What is the impact of inadequate cash flows?
A.Inadequate cash flows cause credit rating
agencies to be concerned. The credit rating community
uses
680 SMITH, 01 5
Idaho Power Company
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1 cash flow and other financial ratios with more subj ecti ve
2 evaluations, such as perceived regulatory support, to
3 assess the financial health and prospects for a utility.
4 If changes in such measures exceed a rating agency's
5 thresholds, such changes can affect bond ratings. Bond
6 ratings, in turn, directly affect both the cost and the
7 availability of debt, which are both important components
8 in determining the utility cost of capital.
9 Q.How much capital does the Company expect to
10 invest in its system over the next three years?
11 A.As reported on February 26, 2009, in IDACORP's
12 and Idaho Power's FORM 10-K, the Company expects to spend
13 between $220 and $230 million in 2009 and average from
14 $278 million to $295 million between 2010 and 2011
15 excluding the investment in the 2012 Langley Gulch
16 Proj ect. The expected investment requirements to
17 reliably maintain and operate the system impose
18 additional pressure on cash flow coverage ratios during
19 the next three years absent a significant increase in
20 operating cash flows.
21 Q.What is the impact of this shortage of cash
22 flow from operations?
23 A.The shortage must be financed with funds raised
24 in the capital markets. The Company must acquire
25 long-term debt and have the ability to issue common stock
681 SMITH, 01 6
Idaho Power Company
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1 in order to make the required investments related to
2 providing reliable service. Gi ven the current state of
3 the capital markets, Idaho Power has limited ability to
4 access the capital it needs to finance construction of
5 the Langley Gulch Proj ect and cannot predict when the
6 market may return to "normal."
7 CURNT STATE OF THE CAPITAL MATS
8 Q.What is the current state of the capital
9 markets?
A.The current credit crisis in the capital
11 markets can be characterized by significant credit
12 contraction as a result of the fundamental restructuring
13 of the financial sector. This restructuring is evidenced
14 by fewer banks, increased regulatory requirements for
15 capi tal adequacy, and significant new requirements to
16 de-leverage bank balance sheets from their historical
17 leverage multiples of up to 30 times. Since Labor Day
18 2008, there have been unprecedented market events from
19 the credit contraction, including the U. S. Treasury's
20 efforts to stabilize the U. S. banking industry by
21 providing $350 billion through the Troubled Asset Relief
22 Program ("TARP"). The U. S. Treasury's critical
23 objectives are to stabilize the financial markets and
24 reduce systemic risk, support the housing market by
25 avoiding preventable foreclosures and
682 SMITH, DI 7
Idaho Power Company
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1 facili tate mortgage finance, and to protect taxpayers.
2 To this end, the U. S. Treasury has thus far allocated a
3 total of $700 billion in the Emergency Economic
4 Stabilization Act, including the TARP funding.
5 Idaho Power has long-term banking
6 relationships, a high percentage of which are with banks
7 that have received TARP funding from the U. S. Treasury.
8 These relationships are in good working order; however,
9 it is unknown whether the market will be receptive to the
10 Company's financing needs when Idaho Power is ready to
11 access the capital markets. This access to capital
12 markets cannot be predicted at this time. The collapse
13 of the credit markets reduced the number of banks
14 providing liquidity as a result of bank failures,
15 government interventions, and Mega mergers. The result
16 is increased volatility, increased de-leveraging, and
17 de-risking by the U. S. banking industry.
18 Q.Why is access to the capital markets so
19 important to this proceeding?
A.Idaho Power cannot internally fund the required
21 investment in plant, including the Langley Gulch Project,
22 necessary to reliably serve customers from its existing
23 operations. The impact of this crisis significantly
24 increases the value of an investment grade credit rating
25 as the lending capacity of the financial
683 SMITH, DI 8
Idaho Power Company
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1 industry contracts and the selection criteria for
2 borrowing companies is more stringent. It is critical
3 that our continued efforts to maintain Idaho Power's
4 corporate credit rating of BBB with S&P and Baal with
5 Moody's are successful.
6 Q.Why is Idaho Power' s ability to maintain its
7 credi t rating paramount in this uncertain credit
8 environment?
9 A.Maintaining our current credit rating minimizes
10 the interest rate spread between different rating grades
11 (investment grade versus below investment grade) and
12 allows the Company to access long-term maturities of
13 debt. The alternative would be to finance long-lived
14 assets with short-term duration bonds that subj ect our
15 customers to interest rate risk in the form of durations
16 for bonds that do not match the life of the asset.
17 For investment grade issuers, like Idaho Power, the
18 credi t spreads (i. e., the yield spread, or difference in
19 yield between different securities due to different
20 credi t quality) for issuers were at an all time low in
21 2005. This relatively inexpensive liquidity and ability
22 to access long-term capital changed in October 2008 to a
23 capital market with short supply , with liquidity being
24 non-existent or very hard to obtain. The cost of funding
25 across the
684 SMITH, DI 9
Idaho Power Company
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1 capital structure increased for short-term and long-term
2 debt and the reduction in stock market values decreased
3 the overall ability to raise capital. Some companies
4 that currently have a credit rating below investment
5 grade have experienced complete exclusion from the market
6 place from October 30 through December 9, the longest
7 period without new issuance in 17 years. Additionally,
8 issuers are reluctant to launch a transaction without a
9 high degree of certainty around its success because of
10 the negative publicity associated with failed
11 transactions. The increase in credit spreads as a result
12 of the rapid deterioration in the U. S. banking industry
13 and corporate credit markets brought a historic wholesale
14 widening of credit spreads and a slowdown in supply of
15 credi t to high-grade issuers. The market access to BBB
16 issuers, like Idaho Power, has improved but access still
17 remains credit specific, volatile, and unpredictable.
18 The Company's access to credit at reasonable
19 costs, desired maturity of issue, and reasonable
20 financing terms is greatly dependent on the investment
21 grade rating currently in place.
22 Q.How do maj or credit rating agencies determine
23 Idaho Power's credit profile?
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25
685 SMITH, 01 10
Idaho Power Company
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1 A.The credit rating agencies begin their
2 assessment using a variety of financial ratios. The
3 calculation of these ratios varies between credit rating
4 agencies. In addition, the credit rating agencies
5 evaluate certain qualitative factors, including the
6 regulatory environment, management capability, and past
7 operational and financial performance. Please see
8 Exhibi t No. 5 for the most recent Moody's and S&P
9 publications on Idaho Power Company.
Q.In the event the Commission selected a
11 different alternative to the Project, do credit rating
12 agencies view credit risk for purchase power agreements
13 or tolling agreements differently than a plant built by a.14
15
utili ty?
A.No. When a company decides to buy generation
16 thru a long-term purchase power agreement or a tolling
17 arrangement there is a risk transfer from the seller of
18 the energy to the buyer of the energy and its customers
19 and shareholders in the form of imputed debt. Imputed
20 debt is a measure of financial risk shifted to a utility
21 when it enters into a purchase power agreement (" PPA" ) or
22 tolling agreement ("TA"). The imputed debt measurement
23 is calculated by S&P, for example, and included in the
24 analysis of financial ratios used to measure the.25
686 SMITH, DIll
Idaho Power Company
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1 utili ty' s creditworthiness. Because debt, actual or
2 imputed, is attributed to the utility that acquires power
3 through the construction of a new plant, PPA or TA,
4 regulatory support is needed to mitigate the impact on
5 the utility's financial ratios. The mitigation can take
6 the following forms:
7 1.Full and automatic regulatory support
8 which can reduce the financial risk imposed on a utility
9 from imputed debt by decreasing or eliminating the
10 uncertainty regarding full recovery of the costs of the
11 PPA.
12 2.Compensate the utility for the increased
13 financial risk by
14 a.Increasing the amount of equity in
15 the rate base, and!or
16 b.Increasing the allowed return on
17 equi ty, and! or
18 c.Restoring financial ratios to pre-PPA
19 or TA level with an adder to the PPA payment.
20 To further explain the ramifications of imputed
21 debt on utilities, I have included a white paper written
22 by the Brattle Group for the Edison Electric Institute
23 and regulatory staff called "Understanding Debt
24 Imputation Issues" as Exhibit No.6.
25
687 SMITH, 01 12
Idaho Power Company
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1 Q.What are the risks of issuing common stock
2 during times when the market value of the stock is below
3 its book value, as Idaho Power's stock currently is?
4 A.The Company's stock has deteriorated in value
5 by 25.4 percent from December 2008 to March 5, 2009. The
6 Company has not seen a decline of this magnitude since
7 late 2000 in which IDACORP' s telecommunications and
8 energy marketing affiliates helped drive down IDACORP' s
9 stock price. Evidenced below is a chart of IDACORP' s
10 trading history since the end of 2000. The market value
11 of IDACORP' s stock is trading below book value at a time
12 when the Company needs to raise capital to finance the
13 construction of the Project. A corporation's book value
14 is used in fundamental financial analysis to help
15 determine whether the market value of corporate shares is
16 above or below the book value of corporate shares.
17 Issuing new equity below book value will cause dilution
18 of existing shareholders and invites shareholder
19 lawsuits.
20
21
22
23
24
25
688 SMITH, DI 13
Idaho Power Company
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15
16
1
2 illDA IDACORP Market Price vs. Book Value
........ ..... .. ........... ...December.31T2'OOO.--MafChSï..20Q9.........$50.00
3 \
\$45.00
4
5
$40.00 I\ I \
.......\~. ..J
,
,
,
6 $35.00
., \I \
.................................... ................................... ...................._........_._..._................................_.7....._....................,........................."j't. ........................................ .............~ ,., \
..............._....__......_........-...."_.....,,..............l......._....-........................................ ................... \I \ ~ ~ v \._,\ I v.,............l....~.....'i
7 $30.00
8 $25.00
.................._....,........
\9 $20.00
10 $15.00
11 $10.00
12 c~ c"" c"" ~ ~~ rS rS rS r¡~~ ~\ ~ ç) ~~ ~ ~ ~ fi~ ro~ ro:y
SS cro cro ~ ~ ctb ctb~~~rS~rS~~'\~~\~C)\~...."'~~~~~~v "" ""13
14 Ml.XEI' .~l"'ll
Q.Mr. Gale i s testimony describes the Company IS
ratemaking request in the form of two alternatives:
( 1 )
17 recovery of a portion of Construction Work in Progress
18 ("CWi P") the Company incurs as it constructs the Proj ect
19 to be included in current rates on an annual basis or (2)
20 explicit findings on how the Commission intends to treat
21 the Company i s Langley Gulch investment for ratemaking
22 purposes at the time it is placed in service. How would
23 the financial community view each of these alternatives?
24
25
A.The Proj ect is expected to take four years to
complete and require significant funding from the
689 SMITH, Dr 14
Idaho Power Company
.
.
.
1 capi tal markets-in terms of both debt and equity at a
2 time of substantial uncertainty related to accessing the
3 capi tal markets. CWIP, including AFUDC, in rate base
4 during construction will provide cash flow to construct
5 the Proj ect. This new cash flow will reduce the
6 Company's need to access the capital market at a time of
7 great volatility and unpredictable access.
8 It is my belief that financing the construction
9 of the Proj ect without regulatory assurance of .rate
10 recovery or CWIP in rate base will endanger Idaho Power's
11 abili ty to maintain its current credit ratings. CWIP in
12 rate base would be a substantial benefit from a credit
13 perspective because cash would be collected currently
14 versus the assurance of cash collected in the future.
15 Q.If the Commission approves AFUDC and CWIP in
16 rate base, how does Idaho Power envision these accounts
17 would operate?
18 A.AFUDC is the capitalization costs associated
19 with the construction of an asset, whereas CWIP is the
20 accumulation of all costs associated with the
21 construction of an asset plus the cost of financing the
22 construction expenditures. AFUDC provides for the
23 financial carrying costs of an asset while it is being
24 constructed and is recorded in Account 107. During
25 construction, AFUDC is a
690 SMITH, 01 15
Idaho Power Company
.
.
.
1 non-cash entry to Account 107 that represents the costs
2 of debt financing and an equity return as proscribed in
3 the FERC formula (CFR 18, Part 101, Subchapter C,
4 Electric Plant Instruction 3 (A) (17), as amended by a
5 FERC letter dated December 30, 1981). The AFUDC plus the
6 accumulation of all other costs associated with
7 construction is then closed to plant Account 101 as an
8 asset upon completion of the proj ect.
9 Once included in rate base, AFUDC is typically
10 recovered over the life of the asset through depreciation
11 expense and a return on investment earned. The asset and
12 AFUDC generate cash flow for the Company when included in
13 rate base in a revenue requirement proceeding.
14 Q.What benefit would the ratemaking assurances
15 and CWIP recovery mechanisms provide to Idaho Power
16 customers?
17 A.Wi th CWIP, customers will help fund
18 construction of the Langley Gulch power plant as it is
19 built, thus avoiding financing costs that would otherwise
20 be depreciated over several decades. As with buying
21 furni ture or a vehicle, paying for a power plant up front
22 wi th cash is significantly less expensive than financing
23 it through debt or equity.
24
25
691 SMITH, DI 16
Idaho Power Company
.
.
.
1 CWIP in rate base reduces the rate shock
2 experienced by our customers by smoothing the rate
3 increases over the construction period versus a one-time
4 large increase at the end of the construction period. I
5 will describe for illustrative purposes an example that
6 estimates the customer impact of three recovery
7 alternatives.
8 In Exhibit No. 7 I have compared two of the
9 al ternati ve rate recovery examples to a traditional plant
10 closing to a plant filing of the Langley Gulch power
11 plant, with ratemaking assurances described in Mr. Gale's
12 testimony resulting in a rate increase of 7.9 percent
13 over current rates in early 2013. The first comparison
14 example, "AFUDC: Pay Currently," is similar to Hells
15 Canyon Relicensing AFUDC granted in Order No. 30722. If
16 customers pay currently for AFUDC from 2010 to 2013, the
17 cumulative increase at the end of construction period
18 would be 6.9 percent, comprised of a 1.9 percent, 1.9
19 percent, 1.1 percent, and 2.0 percent increase for the
20 years 2010, 2011, 2012, and 2013, respectively. The key
21 difference between this method and the "CWIP Rate Base"
22 method is that a regulatory liability is established to
23 collect and amortize the collection over the life of the
24 plant.
25 In the second example, "CWIP in Rate Base,"
692 SMITH, 01 17
Idaho Power Company
1 customers paying for all CWIP expenditures including.2 AFUDC
3
4 /
5
6 /
7
8 /
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
693 SMITH, DI 17a
Idaho Power Company
.
.
.
1 would experience an estimated increase of 7.0 percent.
2 The CWIP in Rate Base example is comprised of a 1.9
3 percent, 2.0 percent, 1.4 percent, and 1.8 percent rate
4 increase in the years 2010, 2011, 2012, and 2013,
5 respecti vely. These examples demonstrate how the rate
6 increases will be softened and will allow customers time
7 to adj ust to the increasing rates versus a one-time rate
8 increase that is preliminarily estimated to be 7.9
9 percent over current rates beginning in 2013.
10 Q.Will the inclusion of CWIP in rate base or
11 ratemaking assurances guarantee access to the debt and
12 equity capital markets?
13 A.Answering this question with any specific level
14 of certainty is made more difficult in the current
15 climate of unprecedented bank failures, the speed of the
16 economic downturn, continued capital market uncertainty
17 the contraction of available financing capacity which has
18 shrunk the once liquid and deep capital markets that
19 Idaho Power has been able to access in the past.
20 However, I believe the granting CWIP for all or a portion
21 of the Company costs for construction of Langley Gulch
22 and ratemaking assurances as described by Mr. Gale in his
23 testimony are the kinds of regulatory support mechanisms
24 that will help to differentiate Idaho Power from other
25
694 SMITH, 01 18
Idaho Power Company
1 capital-seeking companies when the construction and.2 permanent financing of the Proj ect is required.
3 Q.Does this conclude your direct testimony in
4 this case?
5 A.Yes, it does.
6
7
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
695 SMITH, 01 19
Idaho Power Company
.
.
.
1 Q.Would you please state your name, business
2 address, and present occupation?
3 A.My name is Lori Smith and my business address
4 is 1221 West Idaho Street, Boise, Idaho. I am employed
5 by Idaho Power Company ("Idaho Power" or "Company") as
6 Vice President of Corporate Planning and Chief Risk
7 Officer.
8 Q.Are you the same Lori Smith that submitted
9 direct testimony in this proceeding?
10 A.Yes, I am.
11 Q.What is the purpose of your direct rebuttal
12 testimony in this proceeding?
13 A.My testimony responds to testimony by
14 Industrial Customers of Idaho Power ("ICIP") witness
15 Cynthia Mitchell and the Idaho Public Utilities
16 Commission ("IPUC") Staff witnesses Patricia Harms and
1 7 Rick Sterling.
18 Q.Ms. Mitchell asserts on pages 34 and 35 of her
19 testimony that CWIP is inappropriate for investments in
20 new generation.
21 CWIP in rate base is a beneficial financing
22 tool for constructing new generation or any multi-year
23 large project that is available to the Commission to
24 support the cash flow health of the utility. CWIP
25 augments the recovery of financing costs and/or all costs
associated with multi-year
696 SMITH, DI REB 1
Idaho Power Company
.
.
.
1 construction proj ects with current recovery of some or
2 all of the investments as the plant is constructed.
3 Although use of CWIP has been historically limited, the
4 current financing environment, the Company's current
5 below-book value stock price, and the uncertainty of the
6 market of providing financing for a large proj ect warrant
7 the consideration of extraordinary Commission support.
8 CWIP is precisely the sort of ratemaking support Idaho
9 Power needs in the current credit market because it
10 reduces financing risk, regulatory risk, and capital
11 market risk associated with long-lead time, large
12 construction proj ects.
13 Q.Ms. Mitchell refers to a ratio that measures
14 the stress on financial ratios related to construction
15 programs in her testimony on pages 36 and 37. Do you
16 agree with her assumptions that Idaho Power's ratio has
17 been in the 8-10 percent range over the last several
18 years and that a 20 percent ratio is acceptable for
19 avoiding financial difficulty?
20 A.Partly. Idaho Power's CWIP to Capitalization
21 ratio is a financial ratio defined as Construction Work
22 in Progress, a line item on its asset side of the balance
23 sheet divided by Total Capitalization (the sum of Long
24 Term Debt and Common Stock - line items on
25
697 SMITH, DI REB 2
Idaho Power Company
.
.
.
1 the liability side of the balance sheet). Included below
2 is the 5 year history for this ratio for Idaho Power.
3 2008
207,662
2007
257,590
2006
210,094
2005
149,814
2004
151,652CWIP
4
Total
5 Capitalization 2,368,569 2,255,190 1,927,761 1,921,038 1,842,616
6 CWIP to TotalCap Ratio 8 . 9 % 11 . 4 % 10 . 9 % 7 . 8 % 8 . 2 %
7
8 While Ms. Mitchell indicates Idaho Power's
9 capi talization ratio has been in the range of 8-10
10 percent over the last several years, the ratio has
11 actually been as high as 11.4 percent. Additionally, she
12 indicates that adding one large generation proj ect could
13 take this ratio as high as 20 percent for only a brief
14 time. I am unaware of what Ms. Mitchell bases her
15 estimate of a 20 percent CWIP capitalization ratio on,
16 but I do know that Idaho Power has more than one large
17 construction proj ect to be funded in the near term
18 horizon, including the Boardman to Hemingway 500 kV
19 transmission line, the Hemingway Substation, plus the
20 normal care and feeding of an aging thermal fleet and
21 distribution system. Ms. Mitchell's conclusion that this
22 ratio could linger as high as 20 percent without
23 consequences is risky because the ratio would be an
24 indication of the deteriorating operating cash flow
25 heal th of the Company. Rating agencies may view
698 SMITH, 01 REB 3
Idaho Power Company
.
.
.
1 IDACORP and Idaho Power as a greater credit risk and
2 downgrade the Company's ratings.
3 Q.What is the operating cash flow result of this
4 ratio getting too high?
5 A. The increase in the AFUDC component of net
6 income, while construction is in progress, will be
7 detrimental to the cash flow coverage ratio because AFUDC
8 is a non-cash item (except for those instances where the
9 Commission allows for CWIP in rate base or the collection
10 of AFUDC currently in cash while construction is
11 underway) .Wi thout the cash flow associated with these
12 expenditures in the form of CWIP in rate base or AFUDC
13 collection currently, the credit metric that measures
14 funds from operations, a key rating agency metric for
15 determining a company's ability to pay its bondholders,
16 will, all things being equal, decline.
17 Q.Would the recommended regulatory assurances Mr.
18 Gale outlines in his direct testimony help support the
19 financial impact of financing a large proj ect like
20 Langley Gulch?
21 A.Yes. The regulatory assurances Mr. Gale
22 outlines will serve to reduce the regulatory risk of how
23 the expenditures for the Langley Gulch Proj ect will be
24 handled in the future, specifically upon completion of
25 the
699 SMITH, 01 REB 4
Idaho Power Company
1 proj ect. These assurances will help Idaho Power to.2 obtain the lowest possible cost for the financing package
3 of Langley Gulch; the traditional balanced approach of
4 issuing both long-term debt and common equity for these
5 expendi tures is the Company's preference in this case.
6 Absent this support and more certain capital markets, the
7 Company may have to obtain less traditional types of
8 financing that are typically more expensive.
9 Q.Do these assurances satisfy credit rating
10 agency requirements to maintain Idaho Power's current
11 credit ratings?
12 A.As I stated in my direct testimony, there are a.13 number of factors that are involved in rating
14 recommendations like past operational and financial
15 performance (quantitative factors) as well as regulatory
16 environment and management capability (quali tati ve
17 factors). Of the al ternati ves outlined by Mr. Gale in
18 his supplemental testimony filed on April 28, 2009, pages
19 3 through 5, CWIP would provide the regulatory support of
20 current cash flow in the form of collection of
21 construction expenditures during the construction of the
22 plant in the form of AFUDC or CWIP. The other
23 alternative, which Mr. Gale requested given the current
24 economic environment in southern Idaho, is the regulatory.25 assurance provisions
700 SMITH, DI REB 5
Idaho Power Company
.
.
20
21
22 /
.
1 available to the Commission under Senate Bill 1123. I
2 believe both al ternati ves provide for a reduction in
3 regulatory risk; however, I cannot predict the outcome of
4 credi t rating agency decisions related to Idaho Power's
5 credi t ratings.
6 Q.Do you agree with Staff witness Harms'
7 testimony on pages 19-20 that the decision to include
8 CWIP in rate base under the amended section of Idaho Code
9 61-502A be based solely on the three unique circumstances
10 cited by the Commission in Order No. 30722?
11 A.No.
12 Q.Please describe the amended section of the Code
13 and the Company's request for extraordinary rate
14 assurances with this filing.
15 A.The amended section previously read:
16 Except upon its finding of an extreme
emergency, the ( Public Utilities J Commission is
hereby prohibited in any order issued after theeffecti ve date of this act, from setting rates
for any utility that grants a return on
construction work in progress . . . or
property held for future use and which is not
currently used and useful in providing utilityservice.
17
18
19
23
24 /
25
701 SMITH, 01 REB 6
Idaho Power Company
.1 However, in 2006 this section was amended to read:
2 Except upon its explicit finding that the
public interest will be served thereby, the
Commission is hereby prohibited in any orderissued after the effective date of this act,
from setting rates for any utility that grantsa return on construction work in progress . .
or property held for future use and which is
not currently used and useful in providing
utili ty service.
3
4
5
6
7 The capital market meltdown in late 2008
8 coupled with the RFP selection of the Benchmark Resource,
9 which was $95 million less expensive than the next
10 closest bid, creates a compelling argument for the
11 Commission to use CWIP in rate base to support all or
.
.
12 some portion of the successful base load resource.
13 The financing of Langley Gulch will be a
14 significant challenge for many reasons, including the
15 size of the resource, the current uncertain market for
16 long-term debt, and the current trading level of
17 IDACORP' s common stock. All considerations for
18 regulatory assurances by the Commission related to this
19 lowest cost RFP resource will be helpful to Idaho Power
20 in the financing challenge it faces in the current
21 environment.
22 In Mr. Sterling's direct testimony on pages 59Q.
23 and 60 he states "by choosing the Benchmark Proposal,
24 Idaho Power will face some risks that it would have
25 avoided
702 SMITH, 01 REB 7
Idaho Power Company
.
.
.
1 with a tolling agreement." What risks would Idaho Power
2 assume if a tolling agreement was chosen?
3 A.Mr. Sterling is correct in summarizing the
4 construction and operational risk that the Company would
5 have in owning the Langley Gulch project. These risks
6 are risks that the Company currently manages in its
7 operation and construction of many of its assets. The
8 Langley Gulch proj ect will simply be on a larger scale.
9 Q.Do you agree that a tolling agreement would
10 have been risk-free for the Company?
11 A.No. Mr. Sterling outlines the risks that could
12 have been avoided, but does not list the risks that would
13 be assumed if a tolling arrangement bid had been
14 selected. Plant ownership carries a range of operational
15 risks like Mr. Sterling describes, but a tolling
16 agreement carries a significant risk in the 20-year
17 counterparty credit exposure. Credit risk manifests
18 itself in the ability for the counterparty to perform
19 under the terms of the contract. Both plant ownership
20 and a tolling arrangement will expose the Company to
21 liquidity risk in the management of fuel supply for the
22 plant.
23 Q.Ms. Harms recommends in her direct testimony on
24 page 3, lines 8-15, that a new depreciation study be
25 conducted around the time that the Langley Gulch proj ect
703 SMITH, DI REB 8
Idaho Power Company
.
10
1 be completed and placed into service. Do you agree with
2 Ms. Harms?
3 A.Yes, I do.
4 Q.Ms. Harms recommends in her direct testimony on
5 page 11, lines 7-17 "that the Company create and retain
6 documentation associated with the Langley Gulch Proj ect
7 that would allow the Company to comply with component
8 depreciation when IFRS are adopted." Do you agree with
9 Ms. Harms?
A.I agree with Ms. Harms that the Securities and
11 Exchange Commission ("SEC") is evaluating the convergence
12 of U. S. Generally Accepted Accounting Principles - ("D. S.
.13 GAAP") and the International Financial Reporting
14 Standards ("IFRS"). I also agree that this migration
15 from GAAP to IFRS will be a significant change in
16 accounting practice.
17 However, I do not agree that the SEC is eager
18 to impose such a significant change on business that will
19 be required with this conversion. Under the previous
20 administration, the roadmap that Ms. Harms refers to was
21 published in 2008 and established very aggressive
22 implementation deadlines by 2014. This was proposed
23 before the capital market crisis and the recession.
24 Because of the uncertainty related to the timing of the.25 implementation
704 SMITH, DI REB 9
Idaho Power Company
.
.
.
1 of the migration of GAAP to IFRS, I would not recommend
2 that Idaho Power be required to create additional
3 documentation related to the Langley Gulch project that
4 is different than currently required for established FERC
5 and state accounting requirements. IFRS accounting for
6 depreciation requires componentization of significant
7 pieces of large assets be separately capitalized and
8 depreciated . Utility depreciation identifies units of
9 property that are tracked, depreciated, and retired by
10 vintage year. The implementation of IFRS on IPC related
11 to depreciation expense is not expected to be large
12 because of the detailed depreciation requirements
13 currently in place. However the system changes required
14 for this migration will be large and would be an
15 administrative burden to request that this be implemented
16 for the Langley Gulch project.
17 Q.Is Idaho Power actively engaged in the progress
18 of the migration of U. S. GAAP to IFRS?
19 A.Yes. Idaho Power is closely monitoring these
20 activities by participating in industry task force
21 groups, attending external auditor training, evaluating
22 the impacts on our fixed asset accounting systems, and is
23 closely following all related activities and guidance on
24 this potential requirement.
25
705 SMITH, DI REB 10
Idaho Power Company
1 Q.Does this conclude your testimony?.2 A.Yes,it does.
3
4
5
6
7
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
706 SMITH, DI REB 11
Idaho Power Company
.
11
.
.
1 (The following proceedings were had in
2 open hearing.)
3 MS. NORDSTROM: I'll make this witness
4 available for cross-examination.
5 COMMISSIONER KEMPTON: Mr. Richardson
6 MR. RICHARDSON: Thank you, Mr. Chairman.
7
8 CROSS-EXAMINATION
9
10 BY MR. RI CHARDSON :
Q Good afternoon, Ms. Smith.
12 A Good afternoon.
13 Q Would you agree with Ms. Mitchell in her
14 direct testimony where she testified to the effect that
15 CWIP in rates causes an intergenerational subsidy?
16 A I believe Mr. Gale addressed that
17 intergenerational issue in his rebuttal.
18 Q So would you agree with Ms. Mitchell or
19 not?
20 A I can paraphrase what Mr. Gale said is
21 that he didn't agree with her because there are many
22 different intergenerational components, for example, DSM
23 programs that are implemented today that will carry
24 through a multiple year usage of that program, for
25 example.
CSB REPORTING
[phone]
707 SMITH (X)
Idaho Power Company
.
.
.
1 Q And is that your opinion as well?
2 A Yes, it is.
3 Q Turning to Page 16 of your direct
4 testimony, at the bottom of the page, your answer at the
5 bottom of that page, you state that with CWIP in rates,
6 customers help fund the Langley Gulch plant as it is
7 built, and then you go on to say at the end of that, the
8 next sentence, that you conclude that paying for a power
9 plant upfront is significantly less expensive. Do you
10 see that?
11 A Yes.
12 Q Would you turn to your Exhibit No. 7 in
13 your direct testimony? And does this exhibit show the
14 difference in cost to the ratepayers of CWIP in rates
15 versus traditional ratemaking?
16 A Yes.
17 Q And what is that final column at the very
18 far right at the top of the page, depending on how you're
19 holding the page, suggest? What is that final telling
20 us?
21 A I'm sorry, Mr. Richardson, I couldn't hear
22 you.
23 Q There's a column entitled "Final" on
24 Exhibit No.7.
25 A Yes.
CSB REPORTING
[phone]
708 SMITH (X)
Idaho Power Company
.1 And my question to you is what is thatQ
2 showing? What does that represent?
3 It represents that if we had traditionalA
4 ratemaking without CWIP or AFUDC, it's an estimate, an
5 example estimate, of the closure of the Langley Gulch
6 plant and what the rate increase would be in that year.
7 And the column 6.9 percent, that i s not aQ
8 6.9 percent rate increase in the final year, that's an
9 accumulation of the smaller increases in the prior
10 four?
11
12
A Yes.
Q And that's the same with the 7 percent
13 column?.14
.
A The 6.9 versus the 7. 9?
15 No, there's a column labeled 7 percent.Q
16 Yes, for the CWI P in rate base.A
17 And that's an accumulation of the rateQ
18 increases over the prior four years and what it would
19 have been?
20 A Yes.
21 And so is it your view that the differenceQ
22 between 7 percent and 7.9 percent is a significant
23 savings to the ratepayer?
24 Yes, I do think that's a fairlyA
25 significant amount of money on over $750 million of
CSB REPORTING
[phone]
709 SMITH (X)
Idaho Power Company
.
.
.
1 revenue requirement.
2 Q Turning to the top of page 1 7 of your
3 direct testimony, at the very, very top of that page you
4 say that CWIP in rate base reduces the rate shock. Do
5 you see that?
6 A Yes.
And so going back to your Exhibit 7, is it
8 your testimony that a 7.9 percent rate increase is
7 Q
9 equi valent to rate shock?
10 A I think it is a significant amount of
11 money to place on customers in one year, yes.
12 Q So that is rate shock in your view?
It's pretty substantial.
Do you know what the rate increase the
15 industrial customers of Idaho Power suffered this year?
13 A
By class I do not. I know in general the
17 rate increase was a little over 4 percent for all
14 Q
Would you accept, subj ect to check, that
20 the industrial customers' rates on Idaho Power's system
16 A
21 this year went up 25 percent?
22
23
18 customers.
19 Q
A
Q
24 shock?
25 A
Subj ect to check.
Would you say that was tantamount to rate
I would think that would be a large
CSB REPORTING
[phone]
710 SMITH (X)
Idaho Power Company
.
.
.
1 increase, yes.
2 Q And so the Company would support
3 mechanisms in that instance to help their customers avoid
4 rate shock that would ameliorate such rate increases
5 perhaps by spreading them over several years similar to
6 what you do with your CWIP?
7 A Well, you're really getting into rate
8 design and that's really probably, again, Mr. Gale would
9 probably be the best witness to answer that question.
10 Q Well, actually, I'm exploring with you
11 what your understanding of rate shock and what the
12 Company's appropriate response to rate shock should be.
13 A So could you repeat the question?
14 Q Is an appropriate response to rate shock
15 like a 7.9 percent rate increase to find a mechanism to
16 spread that increase over several years which I think is
17 what you've done here with the rate shock treatment for
18 Langley Gulch?
19 A So are you saying that we have a rate
20 increase that we -- you come up with a rate increase and
21 that you spread that over future years or are you saying
22 that -- what I'm saying in this exhibit is that as we
23 construct this proj ect if the CPCN is approved, smaller
24 increments of rate increases for the ultimate cost of the
25 plant would reduce rate shock.
CSB REPORTING
[phone]
711 SMITH (X)
Idaho Power Company
.
.
.
1 Q And are you arguing or is it your
2 testimony that the Company should -- the Commission
3 should grant CWIP and regulatory preapproval for
4 ratemaking treatment purposes for Langley Gulch?
5 A I believe my testimony says that these are
6 all valid tools for the Commission to consider in the
7 extraordinary times that we are from a capital market
8 standpoint, so I believe that from a financial
9 perspecti ve, the current cash flow collection related to
10 CWIP or AFUDC is very important to the Company and it is
11 a tool that the Commission has.
12 On pages 11 and 12 is that direct orQ
13 rebuttal of your direct testimony, beginning on line
14 10 on page 11, you're asked the question in the event the
15 Commission selected a different al ternati ve to the
16 project, do credit rating agencies view credit risk for
17 purchase power agreements or tolling agreements
18 differently than a plant built by a utility and your
19 answer is no, when a company decides to buy generation
20 through a long-term purchase power agreement or a tolling
21 arrangement, there is a risk transfer and then you go
22 into talk about imputed debt that rating agencies apply
23 when they examine the books of the Company. I was
24 wondering, have you read Dr. Reading's testimony as it
25 relates to imputed debt?
CSB REPORTING
[phone]
712 SMITH (X)
Idaho Power Company
.
.
.
1 A Yes, I have read his testimony.
2 Q And you don't address his testimony in
3 your rebuttal, so I was wondering, do you disagree with
4 his discussion on imputed debt?
5 A I guess it's been awhile since I read it.
6 Do you have a specific area that you'd like to me to
7 consider?
8 Q Yes, I do, actually. If you would look at
9 pages 28 to 31 of Dr. Reading's testimony.
10 A And I don't have Dr. Reading's testimony
11 up here.
12 MR. KLINE: This is Dr. Reading's
13 testimony for who?
14 DR. READING: ICIP.
15 MR. RICHARDSON: The Industrial Customers
16 of Idaho Power.
17 (Mr. Kline approached the witness.)
18 THE WITNESS: Which page?
19 Q BY MR. RICHARDSON: That would be in the
20 testimony that wasn't redacted because there's a bit of a
21 pagination difference between the two that we're fixing,
22 but the question begins on the bottom of 28, Ms. Smith's
23 testimony discusses the impact on the Company's financial
24 si tuation, do you see that?
25 A Yes.
CSB REPORTING
[phone]
713 SMITH (X)
Idaho Power Company
.
.
.
1 Q And I was wondering if you could tell us
whether or not you generally agree or disagree with
Dr.Reading's analysis of how credit rating agencies view
power purchase agreements or tolling arrangements.
A What I know about how imputed debt is
2
3
4
5
6 handled by credit rating agencies is that they take a
7 look at the regulatory mechanisms that the Company has in
8 place and they consider some portion of the exposure, so,
9 for example, in the PCA mechanism, the Company has a
10 solid and robust recovery mechanism there, so, you know,
11 the imputed debt is a smaller ratio than 100 percent.
12 Q So you would agree with the statement to
13 the effect that the PCA, the power cost adjustment,
14 mechanism is a significant factor in ensuring cost
15 recovery for a PA or a TA for Idaho Power?
16 A Yes, but it's not 100 percent.
17 Q Correct, but it is a mitigating factor for
18 imputed debt for rating agencies, is it not?
19 Yes, they state that regulatory mechanismsA
20 depending on how they're designed and how timely they are
21 are beneficial to reduce that amount of imputed debt.
22 MR. RICHARDSON: Thank you, Ms. Smith.
23 That's all I have, Mr. Chairman.
24 COMMISSIONER KEMPTON: Ms. Ackerman.
25 MS. ACKERMAN: None, Mr. Chairman.
CSB REPORTING
[phone]
714 SMITH (X)
Idaho Power Company
.
.
1
2
3
4
5
6
7
8
9
10 BY MR. MILLER:
11 Q
COMMISSIONER KEMPTON: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Purdy.
MR. PURDY: I have none. Thank you.
COMMISSIONER KEMPTON: Mr. Miller.
MR. MILLER: Just one question, please.
CROSS-EXAMINATION
Good afternoon, Ms. Smith.
Good afternoon.
13 Q Could you tell me in your view the main
18 A
12 A
14 distinctions between CWIP and Senate Bill 1123?
to that.
CSB REPORTING
[phone]
CWIP and what was the last part?
And the legislation that was recently
17 passed in the last legislative session.
15 A
16 Q
Sure. CWIP is in the form of the return
19 either on an average CWIP balance or, for example, the
20 AFUDC that is calculated which is a non-cash adjustment
21 that is recorded in income and so the difference is
22 really current cash flow that gets collected versus a
23 preapproval of our commitment estimate, for example,
24 would be there would be no current cash collected related.25
715 SMITH (X)
Idaho Power Company
.
.
1 MR. MILLER: Thank you very much. That's
2 all.
3 MS. BRIDGE: I have no questions,
4 Mr. Chairman.
5 COMMISSIONER KEMPTON: You have no
6 questions, Ms. Bridge?
7 MS. BRIDGE: No questions.
8 COMMISSIONER KEMPTON: Very well.
9 Mr. Woodbury.
10 MR. WOODBURY: Thank you, Mr. Chairman.
11
12 CROSS-EXAMINATION
13
14 BY MR. WOODBURY:
15 Q Good afternoon, Ms. Smith.
16 A Hi.
17 Q I have two sets of questions, maybe
18 indicating where the questions came from would help you
19 and Terri Carlock has this first set. Idaho Power
20 currently has shelf debt authority from this Commission
21 for $350 million in long-term debt and 450 million in
22 short-term debt. Based on reports to the Commission, the
23 Company issued $100 million on March 30th of this year
24 for 10 years under the long-term debt authority. The.25 Company has utilized the short-term line for 170 million
CSB REPORTING
[phone]
716 SMITH (X)
Idaho Power Company
.
.
.
1 on February 4th of this year for one year. Is it
2 accurate to state that the Company is currently able to
3 finance its current level of operations at reasonable
4 terms?
5 A Yes, it is fair to state that currently we
6 are able to finance our operations and --
7 Q When additional long-term finance -- did
8 you have anything further?
9 A Oh, I was just going to say and that
10 current operation is really a function of in 2009 because
11 of the granting of the PCA that we did file for, it has
12 provided a large amount of cash flow both from the prior
13 PCA deferral and the current forecast and so it has
14 really helped in the financing for 2009.
15 Q Okay, when additional long-term financing
16 is needed for Langley Gulch, will the Company review
17 conventional financing options to choose the best option
18 at the best rate and file required financing applications
19 with the Commission under Title 61, Chapter 9?
20 A Yes, we will be.
21 Q Other than conventional long-term debt and
22 equity issues, could you identify possible financing
23 options that could be explored by the Company and with
24 the concerns of the Company for each?
25 A Sure. In the financing package for
CSB REPORTING
[phone]
717 SMITH (X)
Idaho Power Company
1 Langley Gulch, our preferred method will be to enter the.2 markets on a traditional basis and what we have done
3 traditionally is we accumulate and use our commercial
4 paper balances for a short period of time until we have a
5 significant enough size to have an efficient long-term
6 debt offering and then we balance those offerings with
7 issuances of equity and so that would be our priority in
8 this case.
9 Q And are there specific concerns that you
10 have whether you can accomplish that?
11 A Yes, the concerns today are that we are
12 currently still trading below book value, have been since
.13 the credit crisis in the fall of 2008, and still hovering
14 around the 90 to 92 percent below book value based on our
15 first quarter SEC filings and so as I stated in my
16 testimony that issuing below book value from a
17 shareholder perspective can be problematic, so as we look
18 to the financing package over the next three years for
19 Langley Gulch, those are the assurances that we are
20 looking for, for the Commission to use the tools to help
21 us reduce the amount of financing really from the capital
22 markets.
23 Q Are there other financing options that you
24 would look at?.25 A Yes, some of the other more costly or
CSB REPORTING
[phone]
718 SMITH (X)
Idaho Power Company
.
.
.
1 complicated options would be convertible equity, for
2 example, and the way convertible equity works is you have
3 a period of time where an issuance is treated as
4 long-term debt, for example, and then it automatically
5 converts into equity. That would be a more costly
6 approach because you're paying a premium upfront for that
7 type of financing and it's a mechanism that would take
8 qui te a bit of internal education as well as education
9 for the Commissioners and for Staff. Another option
10 which is even less remote
11 Q Has the Company used that type of
12 financing before?
13 A No, we have not. We have monitored the
14 market for that over time, but we have never actually
15 issued any convertible equity or convertible debt.
16 Another option that would be considered would be a
17 sale-leaseback, for example, again, a method that we
18 would not want to use for a couple of reasons. One of
19 the main reasons or main benefits of a sale-leaseback is
20 if you are trying -- if you don't have taxable income, so
21 if a company has taxable income, it's not a very
22 efficient mechanism, so there are other al ternati ves that
23 we can consider in the financing of Langley Gulch.
24 Q There aren't any other options worth
25 mentioning at this point? Partnerships?
CSB REPORTING
[phone]
719 SMITH (X)
Idaho Power Company
.1 A Partnerships, j oint ventures, uh-huh.
2 Q Could you describe the financing
3 discussions or reviews completed related to the options
4 considered in financing Langley Gulch?
5 A We have had discussions with the Board on
6 the different options that we have considered. We will
7 put a final package together if the CPCN is granted and
8 then we'll know exactly what we're working with and what
9 the time frame is, and we've also had discussions with
10 our banking relationships, what alternatives are
11 available to us.
12
.
.
Q Should the Commission give you authority,
13 a certificate and some type of authorized recovery, how
14 long will it take you to put together a financing
15 package, complete a financing package?
16 A Well, the package will -- we won't
17 pre-fund the construction of Langley Gulch, so it will be
18 a package that's executed over time depending on how the
19 market is receptive both from a long-term debt
20 perspecti ve and from an equity perspective.
21 Q Does the Company in looking at the
22 financing time line, I guess, feel that they can meet
23 other requirements under the contracts you have with --
24 well, the contractors for Langley Gulch and the supply
25 contracts, they both have dates in there as far as action
CSB REPORTING
[phone]
720 SMITH (X)
Idaho Power Company
.
.
.
1 or forfeiture or contract termination?
2 A Yes. In the near term, yes.
3 Q Numerous Company witnesses in this case
4 discuss the ability to finance the Langley plant,
5 including yourself. Could you clarify whether we should
6 look at your testimony as intending to convey to the
7 Commission either, one, that there is reason to be
8 cautious and obtain the best financing at the least cost
9 to the customers for Langley Gulch or, two, the Company
10 can't finance Langley Gulch without specific
11 preapproval?
12 A The way I would answer that question is in
13 the time period of my direct testimony, there were
14 instruments that were not available. When we look at all
15 of the different options of financing that we do,
16 especially in the debt market, we have taxable debt, we
17 have tax exempt debt. There are auction rate securities
18 that can be issued. We've got secured and unsecured. In
19 the October time frame many of those markets were
20 completely frozen, so from a long-term debt perspective
21 over the last few months, the financing for those markets
22 has improved; however, the corporate credit spreads are
23 still quite wide. For an issuer of our credit, which is
24 triple B with S&P and B double A one with Moody's, we're
25 still looking at 300 to 350 basis points above Treasury
CSB REPORTING
[phone]
721 SMITH (X)
Idaho Power Company
.
.
.
1 which is still from a historical perspective very
2 expensive.
3 Q If there is difficulty obtaining
4 reasonably-priced financing for Langley Gulch, is there a
5 point when the second best bid under the RFP becomes the
6 best option for the Company?
7 A Well, given that the spread between the
8 20-year present value of the bid and the Benchmark is $95
9 million, I don't foresee that being made up in extra
10 financing costs.
11 Q If an alternative bidder under the RFP
12 process had been chosen by the Company, what financial
13 review would the Company have completed by this stage of
14 the contracting process?
15 A The financial review would have been,
16 would have consisted of reviewing their credi t quality,
17 reviewing their financial statements if an al ternati ve
18 bidder would have been selected. The real challenge
19 would be in the construction contract and the PPA or the
20 tolling agreement contract to capture all of the risks
21 and mitigate those risks in that contract.
22 Q What additional financing reviews,
23 conditions or terms could the Company have completed
24 related to the bidder before the final contract would be
25 signed?
CSB REPORTING
[phone]
722 SMITH (X)
Idaho Power Company
1 A Would you repeat the question? Sorry..2 Q Excuse me. You know, you partially
3 answered the question before and it's just an expansion
4 that we're requiring as far as what additional financing
5 reviews, conditions or terms would the Company be
6 completing towards a final contract if a second bidder
7 was awarded.
8 A Well, the additional work would just be in
9 assessing the risk of that long-term contract, so
10 capturing that and understanding that for a contract
11 that's a 20-year contract, for example, so it would be
12 due diligence on that counterparty to identify what
13 needed to be included in the contract..14 Q And what possibilities would you -- would
15 the Company consider lines of credit or what type of
16 financial assurances would you be asking for?
17 A Yes, if there were mitigations that need
18 to be taken or that need to take place, forms of
19 guarantees, forms of letter of credit for certain time
20 periods, debt covenant review, so triggers if, for
21 example, the counterparty had a downgrade in its credit
22 rating, what covenants do we want to monitor and keep
23 track of and actually identify what mitigation we would
24 want to take place, also..25 Q Okay, thank you. A few questions from
CSB REPORTING
[phone]
723 SMITH (X)
Idaho Power Company
.
.
.
1 Patricia Harms. Could you describe the cost
2 documentation created and retained by the Company
3 associated with construction proj ects through its work
4 order asset management process to comply with FERC state
5 accounting and reporting requirements?
6 A We keep all of the documentation of the
7 work orders, so, you know, invoices, we have labor
8 records. We have you know, contracts are a part of
9 the documentation of the expenditures.
10 Q Staff has not recommended that the Company
11 adopt the reporting requirements associated with the
12 International Financial Reporting Standards before the
13 mandatory time lines provided by the SEC, but wouldn't
14 you agree that the documentation created
15 contemporaneously with construction of Langley Gulch
16 proj ect would be sufficient to track costs when the
17 Company adopts those standards?
18 A Yes, I would.
19 Q What changes do you see in depreciation
20 for Langley Gulch plant related to the International
21 Financial Reporting Standards?
22 A Changes in the calculation or changes in
23 the--
24 Q No, changes in depreciation for the
25 proj ect, any changes in the requirement standards.
CSB REPORTING
[phone]
724 SMITH (X)
Idaho Power Company
.
.
.
1 A As I stated in my rebuttal testimony, the
2 depreciation expense related to IFRS is not going to be
3 that much different. We haven't actually calculated it
4 because we don't know what the final rules are, but for
5 utilities, we do already unitize and identify units of
6 property that is in more detail than general industry, so
7 as far as the componentization versus a unit of property
8 for a utility, we don't expect those to be significantly
9 different, and also, utili ties may have the option to
10 have an exception once IFRS is implemented, so what that
11 would mean is that the books and records that are in
12 place at the time of implementation, the companies may
13 have an exception to just continue that depreciation
14 stream versus reworking it, for example, so, again, it's
15 a little bit uncertain as far as what the rules are going
16 to be. I hope that answered your question.
17 Q I think so, but if you were just starting
18 ini tially, wouldn i t you comply with the requirements of
19 the international act?
20 A Yes.
21 MR. WOODBURY: All right, Mr. Chairman,
22 thank you. I have no further questions.
23 COMMISSIONER KEMPTON: Commissioner
24 Redford.
25 COMMISSIONER REDFORD: I have no
CSB REPORTING
[phone]
725 SMITH (X)
Idaho Power Company
1 questions..2 COMMISSIONER SMITH: No questions.
3 COMMISSIONER KEMPTON: Ms. Smith, I have a
4 couple of questions.
5
6 EXAMINATION
7
8 BY COMMISSIONER KEMPTON:
9 Q Ms. Smith, when you go out on the debt
10 markets, would you exercise that debt privilege under
11 Commission Orders that currently exist for the purpose of
12 borrowing money for Idaho Power? Do you want me to be
13 more specific?.14 A That might be helpful.
15 Q There are two Commission Orders. The one
16 I will refer to is -- well, I'll refer to both of them.
17 One of them is a borrowing authority for Idaho Power
18 that's in Order 30487 that came out of the Case
19 IPC-E-07-19 and it addresses the terms of the notes and
20 the interest and the due dates on those, and then in
21 Order No. 30294 which was a $450 million authority,
22 IPC-E-07-06, those extend out through 2010 and I believe
23 the first one may have gone out further than that. Let's
24 see, the authority, short-term debt authority, to 2014.25 and the amount would certainly seem like the borrowing
CSB REPORTING
[phone]
726 SMITH (Com)
Idaho Power Company
.
10
1 authority that Idaho Power is looking for would be within
2 that range. Is that the authority that Idaho Power would
3 use in going to the debt markets?
4 Yes, the 450 million, basically the cap onA
5 which we currently have authorization to issue.
6 Q Yes.
7 You know, if we're starting to approachA
8 the ceiling on that, then we would have to make another
9 filing.
Q In those Orders do you have authority to
11 do that subject to Commission approval of those
12 amounts?.
.
13 Yes, we do get Commission approval.A
14 So would that be one thing that would notQ
15 be under a preapproval process that is set in concrete at
16 the time the preapproval was established and that is
17 Commission review of the debt structure associated with
18 the borrowing and the borrowing rate?
19 Would it be included in that preapproval?A
20 Would you maintain that the preapprovalQ
21 process would abort the requirement for PUC review and
22 approval of the debt obligations that the Company would
23 undertake during the construction process or in the
24 process of obtaining the money that you're looking for
25 for the proj ect?
CSB REPORTING
[phone]
727 SMITH (Com)
Idaho Power Company
1 A I don't know the answer to that, I mean,.2 as far as the legal description.
3 Q I'll rephrase the question a little bit
4 because it's a pretty important point. It's argued that
5 in the capital cost side of the house that the
6 preapproval process has a commitment estimate that
7 essentially sets in concrete in the ratemaking treatment
8 the cap and that it binds future Commissioners to those
9 provisions, to the ratemaking provisions. A part of that
10 consideration would obviously be how much your debt
11 costs. You have a cap on the construction side --
12 A Yes.
13 Q -- Idaho Code 901, 61-901, says that.14 utili ties can issue debt on specific order by the
15 Commission and so the Orders that I just talked about,
16 30487 and 30294, fulfill the requirements of that
17 particular statute and they set in motion a review
18 process whereby Idaho Power can enter into debt
19 arrangements, but the PUC has an authority to review
20 prudency on those and to make a final determination of
21 allowance, of allowing that debt to go forward; is that
22 your understanding? All of the things related to the
23 Orders and to the statutory reference are subject to
24 verification..25 A Yes, I would agree.
CSB REPORTING
[phone]
728 SMITH (Com)
Idaho Power Company
.
.
.
1 Q But the question itself, is that your
2 interpretation of how your debt structure would work in
3 terms of the Commission authority to review and to make a
4 final decision based on prudency on the debt obligations
5 that you are undertaking?
6 A I believe that the Commission has the
7 authori ty to review what financing the Company puts in
8 place, not only for Langley Gulch, but for any capital we
9 raise.
10 Q And that's separate from the pre approval
11 process that would go forward in terms -- although it may
12 be referenced as a part of the ratemaking process, it
13 would be separate from the pre approval process related to
14 the capital expenditures themselves, the 427 million?
15 A Separate from what we currently have --
16 Q In terms of the preapproval commitment on
17 future Commissioners, yes.
18 A I guess the way I would answer it is I
19 believe that you have the authority to review and
20 acknowledge, determine if it's prudent in your review.
21 I'm not sure if I'm answering your question.
22 COMMISSIONER KEMPTON: Well, I think it's
23 close enough. If it isn't, I'm sure counsel for Idaho
24 Power will correct the situation. That's all the
25 questions I have. Ms. Nordstrom.
CSB REPORTING
[phone]
729 SMITH (Com)
Idaho Power Company
1 MS. NORDSTROM: Thank you..2
3 REDIRECT EXAMINATION
4
5 BY MS. NORDSTROM:
6 Q So Ms. Smith, just to clarify, the
7 preapproval process that may deal with the capital
8 structure and debt structure is a separate process from
9 the securities statutes that the Commission reviews the
10 Company's capital structure and approval for additional
11 debt; is that your understanding?
12 A I believe it would be.
13 Q Mr. Woodbury discussed with you how the.14 Company would do a financial review of the winning bidder
15 if it wasn't Idaho Power. Based on your understanding
16 and knowledge of the current capital markets, would you
17 have concern that other bidders if they had won would
18 also have trouble financing in the present market or is
19 that something that' s limited just to Idaho Power?
20 A I don't believe that is limited just to
21 Idaho Power and we did not verify the ability of the
22 other bidders' ability to finance. Gi ven Idaho Power's
23 Benchmark project was the lowest cost and the one
24 selected, we did not either layout criteria for how they.25 would finance it or, I mean, as Mr. Bokenkamp has
CSB REPORTING
[phone]
730 SMITH (Di)
Idaho Power Company
.1 indicated, they had a small section for scoring on
2 financial considerations.
3 MS. NORDSTROM: I have no further
4 questions.
5 COMMISSIONER KEMPTON: Commissioner
6 Redford.
7
8 EXAMINATION
9
10 BY COMMISSIONER REDFORD:
11
.
.
Q Ms. Smith, inasmuch as you used net
12 present value to review the bids, would it ever be
13 possible for a contractor to provide a plant -- they
14 never could provide a plant that had a net present value
15 of $95 million or $160 million. I mean, how could I as a
16 bidder provide that to you?
17 A Provide me with
18 Q The net present value of what you claim
19 you're saving of a plant based upon your build and
20 construct by Idaho Power.
21 Well, let me start by saying that the netA
22 present value of the revenue requirement test was
23 selected because it's a fairly common test where we could
24 take the contract value both from a Benchmark standpoint
25 and from the contract standpoint that was bid by some of
CSB REPORTING
[phone]
731 SMITH (Com)
Idaho Power Company
1 the other bidders and make them on an equal playing field.2 and the measure that was, I guess, from the Company's
3 perspective the most prudent was what was the cost to the
4 customer, so the present value of that cost is really
5 what we felt was important and so making those comparable
6 by using that present value was really the approach and
7 so I think your question is would the bidder have to
8 present that to us versus us calculating it?
9 Q Well, inasmuch as you used as a criteria
10 the net present value to the ratepayers, it would be
11 impossible for another bidder to provide you a bid that
12 would have a net present value of $ 95 million..13 A I guess I don't agree because it could
14 become a fact in the amount of return that they've
15 embedded into the contract, the costs that they have
16 embedded into the contract, so that's how we were
17 measuring is over time what is that cost and so for them
18 to get a benefit of $95 million cheaper than the
19 Benchmark, then that i s where those reductions would have
20 had to have taken place.
21 Q Where would they come from?
22 A They would come from them putting together
23 the best possible bid that they could.
24 Q Don't you think that they did put together.25 the best possible bid that they could do?
CSB REPORTING
[phone]
732 SMITH (Com)
Idaho Power Company
1 A They may have. What I don't know about.2 the bids, for example, is the return on equity that they
3 included into the price, so I mean, those are the
4 variances between the two bids that is captured in the
5 $ 95 million.
6 Q Well, if Idaho Power had really been
7 serious about soliciting bids for purchase power
8 agreements and tolling agreements, wouldn't that have
9 obviated your ability to raise capital to finance the
10 proj ect? On a purchase power agreement, the bidder
11 retains the ownership and it sells power to you.
12 A Yes.
13 Q So the financing would be on his plate and.14 not on Idaho Power's plate?
15 A That's true.
16 Q And in times of extreme financial crisis
17 or recession, Idaho Power would not have had to concern
18 itself with financing.
19 A Idaho Power would have had to concern
20 itself with contract risk and credit party risk in the
21 event that the tolling arrangement or PPA would have been
22 more than $95 million cheaper than the Benchmark and so
23 in that, you know, we would have avoided the financing,
24 but we would have taken on liquidity and capital adequacy.25 concerns for counterparty risk over a 20-year contract
CSB REPORTING
[phone]
733 SMITH (Com)
Idaho Power Company
1 and liquidity for counterparty performance, and so in the.2 selection of the bidders, as Mr. Porter has indicated,
3 you know, the Benchmark proj ect is the lowest cost
4 proj ect for the customer, so I think what you're saying
5 is the financing given the current market should have
6 overshadowed that?
7 Q Well, I'm just simply asking you, you've
8 testified that financing is of grave concern to Idaho
9 Power and your inability to raise capital to finance this
10 proj ect, either it won't be undertaken by Idaho Power or
11 you'll have to go to one of the alternatives provided by
12 the other bidders; is that correct?.13 A In the event that it can't be financed,
14 which like I said in my rebuttal testimony, the markets
15 have improved with the exception of the Company's current
16 common stock price and what we have between 2009 and 2011
1 7 given some deferrals on some of the other proj ects,
18 Hemingway to Boardman, for example, we have more room in
19 which to defer that equity issuance, so more time for our
20 stock price to recover.
21 Q What if it doesn't recover?
22 A If it doesn't recover, then -- if it
23 doesn't recover and we i re forced to issue equity, the
24 Company would reassess at that time, you know, what are.25 our options and the options could be that we would get a
CSB REPORTING
[phone]
734 SMITH (Com)
Idaho Power Company
.
10
11
1 credi t downgrade, for example, because we haven't been
2 able to issue equity nor to match the long-term debt that
3 has been issued. We could, again, explore alternatives
4 for j oint ventures or for additional capital that would
5 be invested by others, not dissimilar to Hoku, for
6 example.
7 This would be midstream in theQ
8 construction process?
9 A Yes.
Q Or the al ternati ve would be mothball it.
A That I would probably refer to Mr. Porter
12 whether we would mothball a proj ect or not..
.
13 Q I'm still confused and please excuse me,
14 how would a bidder who bid on a purchase power agreement
15 or a tolling agreement, how would he be able to provide a
16 price that would include, could be construed as $95
17 million net present value? Have you got any ideas how he
18 would do that?
19 By lowering the cost of the bid.A
20 By lowering the cost of the bid?Q
21 A Uh-huh.
22 It seems to me that the Company reallyQ
23 preferred the Benchmark proposal at the outset, wouldn't
24 you say?
25 No, Commissioner, I wouldn't agree withA
CSB REPORTING
[phone]
735 SMITH (Com)
Idaho Power Company
1 that. I think the Company approached the RFP very.2 seriously. The Chinese wall that you talked about
3 earlier was implemented from day one clear through the
4 Board review of this proj ect. The result of the bidders
5 and the evaluation of the bidders is what has had
6 Benchmark come to the surface as a $ 95 million unit to
7 serve the RFP for our customers.
8 Q Have you reviewed the bidding manual?
9 A No, I have not.
10 Q Al though you haven't reviewed the manual,
11 are you aware that the procurement for third parties
12 specified PPA and TA contracts?.13 A Yes.
14 Q And they could bid al ternati ves if they
15 wanted to, but you called out those types of contracts?
16 A Yes, they could submit their bid with
17 those.
18 Q Yes, and in the introduction to the
19 bidding manual, it says, and 11m paraphrasing, while
20 Idaho Power does not plan to have any of its subsidiaries
21 construct or procure this plant, and then in the next
22 paragraph you say, but Benchmark would provide a bid,
23 isn't that inconsistent?
24 A I think Mr. Bokenkamp needs to address.25 that.
CSB REPORTING
[phone]
736 SMITH (Com)
Idaho Power Company
.
.
.
1 COMMISSIONER REDFORD: Well, I guess I
2 don't have any further questions.
3 THE WITNESS: Thank you.
4 COMMISSIONER KEMPTON: Ms. Nordstrom,
5 redirect?
6 MS. NORDSTROM: Yes, thank you.
7
8 REDIRECT EXAMINATION
9
10 BY MS. NORDSTROM:
11 Q Ms. Smith, are you familiar generally with
12 the financial components of a bid, what types of things
13
14
15
16
go into a bid from a cost perspective?
A Yes.
Q And what are those?
A It's going to be the equipment, the labor
17 to build the equipment, the profit or return that is
18 expected from the bidder, the cost of the financing, any
19 of the consulting fees and things of that nature.
20 Q So each party that was bidding in this
21 process put together their bid, their best estimate of
22 what they could build the plant for or provide this power
23 underneath a PPA or a TA and offered that to Idaho Power;
24 correct?
25 Yes.A
CSB REPORTING
[phone]
737 SMITH (Di)
Idaho Power Company
.
.
.
1 So once you got all those bids together,Q
2 net present value was calculated on the bids that made
3 the short list; correct?
4 The 20-year net present value of theA
5 revenue requirement.
6 Okay; so what exactly does that mean?Q
7 Revenue requirement is what we need toA
8 collect from our customers, so if you look at -- you have
9 a revenue requirement, you have a current collection of
10 your revenues, if there's a gap between those, there i s a
11 revenue deficiency, so it is the top line cash flow that
12 needs to be collected.
13 Q And so that's over a 20-year period that
14 is reduced --
15 It i S counted over a 20-year period.
17
A
Q
correct?
A
Q
everyone?
A
Q
So that levels the playing field for
16 And it's reduced to today's value;
18 Yes.
19
20
23 plants versus tolling agreements versus purchase power
24 agreements and there i s a commonality between them based
25 on that measure?
CSB REPORTING
[phone]
738 SMITH (Di)
Idaho Power Company
1 A Yes..2 Q Okay; so in your opinion, could it be one
3 of the reasons why there was such a big difference
4 between the self-build project and the next closest bid
5 was the fact that there was no profit built into the
6 self-build proj ect?
7 A Well, there is profit built into the
8 self-build proj ect in the assumption that the 50-50 debt
9 and equity financing that Mr. Porter described, there is
10 a return component on 50 percent of that asset.
11 Q Okay; so both -- all types of bids had
12 profi t components built into them?
13.14
15 other bids?
16
A Yes.
Q So was Idaho Power's just less than the
A I don i t know exactly what line item was
17 less. The return on that size of an asset is going to be
18 a significant component, so I don't know what their
19 assumptions were.
20
21
22
Q Okay.
A The bidders' assumptions were.
Q Okay; so what was the end result of your
23 analysis on net present value, of the 20-year net present
24 value?.25 A The end result is a $95 million difference
CSB REPORTING
[phone]
739 SMITH (Di)
Idaho Power Company
.
.
.
1 in revenue requirement over the 20-year contract period
2 cheaper.
So presumably, other bids could have bid
4 in a less expensive proposal if they had chosen to?
3 Q
Yes, I believe so.
Are you the chief risk officer for Idaho
Yes, I am.
And do you evaluate power purchase
10 agreements and tolling agreements from a financial
5 A
Yes, we have looked at the components of
13 how rating agencies look at imputed debt in tolling
6 Q
14 arrangements and looked at it from that perspective.
18 Q
7 Power Company?
8 A
15 We've looked at it from mitigating the credit,
9 Q
16 counterparty credit, exposure associated with the
11 perspective?
12 A
17 contract performance.
So based on your analysis, is the Company
19 predisposed one way or another towards any of the options
20 that were before it in this process from a financial
21 perspective?
22 A No.
And why not?
Historically, the RFP and the IRP process
25 brings together, you know, different assets to consider
CSB REPORTING
[phone]
23 Q
24 A
740 SMITH (Di)
Idaho Power Company
.
.
.
1 and then when a bid is let, for example, the financing is
2 really incumbent on the bidder and from our perspective,
3 our typical practice historically has been to evaluate
4 the cost of those investments based on our current
5 weighted average cost of capital.
6 Q Do you consider Idaho Power's Benchmark
7 resource to be the same as an IDACORP affiliate bid?
8 A No.
9 Q Why not?
10 A Well, an affiliate bid would be a
11 subsidiary or from, you know, something I guess I would
12 consider as a legal, different legal structure than Idaho
13 Power Company.
14 Q So the Benchmark resource was built from
15 within Idaho Power Company, not an affiliate?
16 A Yes.
17 Q And from a rate base perspective, would an
18 affiliate get rate base treatment of its proposal as
19 compared to Idaho Power Company?
20 A Rate base treatment in the form of --
21 Q Let me ask that a little bit more clearly,
22 hopefully. Would an affiliate be treated more like a
23 developer or like Idaho Power with regard to rate basing
24 the expenses of the plant?
25 A An affiliate would be treated as a
CSB REPORTING
[phone]
741 SMITH (Di)
Idaho Power Company
.
.
.
1 developer.
2 MS. NORDSTROM: Correct. Thank you,
3 nothing further.
4 COMMISSIONER REDFORD: I have a few more
5 questions.
6 COMMISSIONER KEMPTON: Commissioner
7 Redford.
8
9 EXAMINATION
10
11 BY COMMISSIONER REDFORD:
12 Q It's astounding that you could suggest to
13 us that Benchmark resources is not related to either
14 IDACORP or Idaho Power and treat it as an affiliate
15 organi zation, are you telling me that it isn't?
16 A Well, the Benchmark proj ect was developed
17 by Idaho Power personnel and so I would not consider that
18 to be an affiliate; for example, if one of our
19 subsidiaries was in the business of developing generation
20 proj ects.
21 Q Does it have corporate status with the
22 Secretary of State? Does it apply for Articles? Does it
23 hold shareholder meetings?
24
25
A A subsidiary or Idaho Power?
Q Benchmark.
CSB REPORTING
[phone]
742 STERLING (Com)
Staff
.
.
.
1 A No, the Benchmark is a subset of Idaho
2 Power Company.
3 Q So it is an affiliate?
4 A Well, my understanding of an affiliate is
5 an entity that would be considered to be at arms length
6 wi th Idaho Power.
7 Q I can suggest to you that that's not the
8 case legally. Ms. Nordstrom also said that through some
9 method you leveled the playing field between the other
10 bidders, the PPA and TA bidders, and Benchmark. Could
11 you tell me again how you leveled the playing field so
12 that each of those entities had an opportunity to fairly
13 compete?
14 A The process that we took was to take the
15 bids, so the Idaho Power bid had a rate base component
16 and it had a variable net power supply cost component and
17 it had a return component. The folks in Mr. Gale's
18 department ran that through our regular regulatory
19 revenue requirement model and it produced a result, and
20 then for each of the other bidders, albeit they didn't
21 have a rate base amount, they had a variable net power
22 supply cost amount and they had an operation and
23 maintenance amount that was used in that same
24 calculation, so we used it -- you know, each one of those
25 components was put into that revenue requirement model
CSB REPORTING
[phone]
743 STERLING (Com)
Staff
.
.
.
20
21
22
23
24
25
1 that we use in all of our regulatory filings.
2 Q But you added a $95 million net present
3 value.
4 A No, it's an outcome. We didn't add it.
5 It's the result.
6 COMMISSIONER REDFORD: Okay, I guess I
7 don't have any further questions.
8 COMMISSIONER KEMPTON: Redirect?
9 MS. NORDSTROM: None.
10 COMMISSIONER KEMPTON: Without obj ection,
11 the witness may step down.
12 (The witness left the stand.)
13 COMMISSIONER KEMPTON: Ms. Nordstrom.
14 MS. NORDSTROM: Thank you. Idaho Power
15 would call Peter Pengilly as its next witness.
16
17
18
19
CSB REPORTING
[phone]
744 STERLING (Com)Staff
.
10
11
1 PETER PENGILLY,
2 produced as a witness at the instance of the Idaho Power
3 Company, having been first duly sworn, was examined and
4 testified as follows:
5
6 DIRECT EXAMINATION
7
8 BY MS. NORDSTROM:
9 Good afternoon.Q
A Hello.
Q Please state your name and spell your last
12 name for the record.
.13
14
A Pete Pengilly, P-e-n-g-i-l-l-y.
Q By whom are you employed and in what
15 capaci ty?
16 A Idaho Power Company. I'm the customer
17 research and analysis leader in the customer relations
18 and energy efficiency department.
19 Q Are you the same Peter Pengilly that filed
20 rebuttal testimony on July 2nd, 2009 and prepared no
21 exhibits?
.
22 That's correct.A
23 Do you have any changes to your rebuttalQ
24 testimony?
25 No, I don't.A
CSB REPORTING
[phone]
745 PENGILLY (Di-Reb)
Idaho Power Company
.1 Q If I were to ask you the questions set out
2 in your rebuttal testimony today, would your answers be
8
9 it is so ordered.
12
13
14
15
16
17
18
19
CSB REPORTING
[phone]
Yes, they would be.
MS. NORDSTROM: I would move that the
6 prefiled rebuttal testimony of Peter Pengilly be spread
3 the same?
4 A
5
7 upon the record as if read.
COMMISSIONER KEMPTON: Without obj ection,
10 (The following prefiled rebuttal testimony
11 of Mr. Peter Pengilly is spread upon the record.)
.
20
21
22
23
24.25
746 PENGILLY (Di-Reb)
Idaho Power Company
.
.
.
1 Q.Please state your name, address, and present
2 occupation.
3 A.My name is Peter Pengilly. My business address
4 is 1221 West Idaho Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by Idaho Power Company as a
7 Customer Research and Analysis Leader in its Customer
8 Relations and Energy Efficiency group.
9 Q.Please describe your educational background.
10 A.In May of 1976, I received a Bachelor of
11 Science Degree in Anthropology from University of Idaho,
12 Moscow, Idaho. In 1986, I began attending Boise State
13 University and, in 1992, I received Bachelor of Science
14 Degree in Mathematics. I continued at Boise State
15 University after graduation as an adjunct professor in
16 mathematics while completing courses specializing in
17 statistics.
18 I have since attended numerous seminars and
19 conferences on statistical analysis and on pricing issues
20 related to the utility industry and have attended
21 seminars and courses involving public utility regulation.
22 These courses include Edison Electric Institute's ("EEI")
23 Advance Rate Course and New Mexico States University's
24 Center for
25
747 PENGILLY, DI REB 1
Idaho Power Company
.
.
.
1 Public Utilities Rates Course and The Restructuring
2 Electric Industry Course. Additionally, I have attended
3 numerous conferences and forums on energy efficiency and
4 demand response, including the Demand Response
5 Coordinating Committee ("DRCC") meetings, the E Source
6 Forum, and Bonneville Power Administration post-2011
7 energy efficiency meeting.
8 Please describe your work experience.Q.
9 A.From 1976 until 1986, I worked as an
10 archaeological technician on contract with various
11 uni versi ties, government agencies, and private
12 contractors. At the same time, I was involved in managing
13 a small family-owned business. From 1986 until 1992, I
14 was employed by the Idaho State Historical Society
15 managing their Archaeology laboratory. In 1992, I went
16 to work as a Research Analyst for the Idaho Department of
17 Correction. In 1993, I transferred to the Idaho
18 Department of Labor as a Research Analyst Supervisor
19 under the auspices of the Bureau of Labor Statistics.
20 This position included supervising a staff as well as
21 performing a variety of economic and statistical analyses
22 and reporting. I was employed by Idaho Power Company in
23 December of 1999 as a Senior Pricing Analyst in the
24 Pricing and Regulatory Services Department. My duties as
25 a Senior Pricing Analyst
748 PENGILLY, 01 REB 2
Idaho Power Company
.
.
.
1 included the development of alternative pricing
2 structures, management of pricing programs, the analysis
3 of the impact on customers of rate design changes, and
4 the administration of the Company's tariffs. In that
5 posi tion I helped develop several demand response
6 programs, a time-of-use pilot program, and a critical
7 peak pricing program.
8 In 2006, I was promoted to my current position
9 as Customer Research and Analysis Leader in the Customer
10 Relations and Energy Efficiency Department.In this
11 position I am responsible for the research, analysis,
12 forecasting, and reporting associated with Idaho Power's
13 energy efficiency and demand response programs. As such,
14 I am a member of the Northwest Energy Efficiency Alliance
15 ("NEEA" ) cost-effectiveness expert committee, a
16 representative at the Pacific Northwest Demand Response
17 Proj ect (" PNDRP"), Idaho Power's representative at the
18 Regional Technical Forum ("RTF"), and a member of the E
19 Source DSM Executive Council.
20 What is the scope of your rebuttal testimony inQ.
21 this proceeding?
22 A.My testimony will address how Idaho Power
23 accounts for energy efficiency and demand response in the
24 Integrated Resource Plan (" IRP") process, and how Idaho
25 Power's energy efficiency programs affect its winter
peak.
749 PENGILLY, 01 REB 3
Idaho Power Company
.
.
.
1 ENERGY AND PEAK DEMD SAVINGS IN THE IRP PROCESS
2 Q.Could you explain how energy efficiency and
3 demand response are integrated in the IRP process?
4 A.The energy and peak demand reductions that
5 resul t from the energy efficiency and demand response
6 programs are integrated into the IRP process in two
7 distinct ways. Annually, all forecast results from the
8 existing and committed energy efficiency and demand
9 response programs are incorporated into the load
10 forecast. This forecast is reassessed each year taking
11 into account the results of the previous year. This
12 annual forecast is used in the IRP process for those
13 years when an IRP is produced. Additionally, for each
14 IRP, new energy efficiency and demand response potential
15 is identified as a new resource and is analyzed similar
16 to a new supply-side resource.
17 Q.Could you describe the difference in how energy
18 and peak demand savings are accounted for in the IRP or
19 forecasting process?
20 A.To get a true picture of Idaho Power's
21 projected reduction for energy efficiency programs, it is
22 necessary to add the incremental annual forecast of
23 existing and committed programs to the incremental annual
24 new potential and then accumulate them over the years.
25 The
750 PENGILLY, DI REB 4
Idaho Power Company
1./2
3
4
5
6
7
8
9
10
11
12
13
cumulati ve impact that was originally produced for the
2009 IRP can be seen in Figure 1.
Figure 1: Historic and Forecast Cumulative Impact of
IPC Energy Efficiency Programs 2002-2027
300
O~'"'Bis~~;i~:~'~"J-'--.------------"---'--.----'.----..-.---..-.----------.---..---.------.. --.-.... .--....
ii Forecast i.r~.:~.:';_";"'==.:~--.....-......--._...........---..----.---........--...-.........____.........._..___...._....___....__........_......................._.
I
i
250
¡~t1
'"b.i:oS;
t1VI::i:(1i:w
200 ..t--........---..........-................-....-............------............--..---...._____....___........___..........__......__............_...... ~
I
-r - --.- - ---. --- -- - -- _... -. --..._---._-..__.._-_........._-..._.._--- .-_.
¡
150
100 i..\" -- -........_- .........................._---......_--_............_-_............--_.. ... r -
so ..r.-----.--------..-------.-...------, ....~ L
I
o .... i = 1m,
"~~;,~~;,~~~~~;,~~~~~"-~~t~~t~"l~~"l~~"l;,~"l;,~t~"l;,~,,~~~~"lt~,,t~,,~~,,~~'\;,~'\;,~it~,,;.~,,~~v
15 In contrast, to understand the forecast peak demand
16 reduction from demand response programs, it is necessary
17 to add the annual existing and committed demand response
18 reduction with the annual new potential reduction. The
19 demand response reduction is not addi ti ve across years.
20 Q.Do you agree with Ms. Mi tcheii 's assertion on
21 page 29 of he r di rect testimony that there should be new
22 incremental savings included in the plan forecast for the
23 next 15 years?
24.25
A.No. As stated above, peak demand reduction
from demand response programs is not cumulative and is
751 PENGILLY, Dr REB 5
Idaho Power Company
1
e.2
3
4
5
6
7
8
9
10
11
12
. 1
independent from year to year. Idaho Power believes that
when these programs mature the peak demand reduction will
become relati vely constant as seen in Figure 2 below.
Figure 2: Historic and Forecast Impact of IPC Demand
Response Programs July Peak Hour 2002-2027
§'~co.¡:
u:i"0
QJ0:.:IIQ)c.?:i..
j
250 j
T.......... ......._--......_-...............................1; _ ,_t ..
';
200 -~--_._.._...._....__.___._._..'.. .. ..
150
",. , i
,.. i
¡,
100 ..,..--........_._._._.__.._
so
o ..m
"vi;i;~i;i;~ç:fJ°"vd::J'\~i;'t~~\~~~~~";~~\~~\I;~"vI;~~~~';~~'\~~'t~~\I;"vi;1;"v";~"v\~"v\~~"v~"v~~"v;~v
15 Figure 2 includes existing and committed peak
16 demand reduction from the A/C Cool Credit program and the
17 Irrigation Peak Rewards timer program as well as the
18 forecast increased peak demand reduction from the
19 FlexPeak Management and the Irrigation Peak Rewards
20 dispatchable programs. The maximum peak reduction from
21 these programs at maturity is expected to result in
22 approximately 312 MW achieved by 2013. This represents a
23 huge peak reduction - approximately 10 percent of Idaho
24 Power i s 2008 peak demand and about 8 percent of the.25 forecast peak for 2013. In
752 PENGILLY, Dr REB 6
Idaho Power Company
.
.
.
1 fact, this amount exceeds the FERC' s aggressive expansion
2 of Idaho's potential peak demand reduction identified in
3 its recent publication A National Assessment of Demand
4 Response Potential published in June 2009 (Appendix A -
5 State Profiles, p. 81). FERC reports that Idaho's
6 potential peak demand reduction from "aggressively
7 expanding today' s programs" to be 6 percent of load by
8 2014 and reports the same percentage for 2019.
9 Q.Wi tness Mitchell compares expected peak demand
10 savings from energy efficiency programs in the 2006 IRP
11 and the 2008 and 2009 updates, then concludes that peak
12 savings are surprisingly reduced in the 2009 IRP
13 Addendum. Are Idaho Power i s forecast peak savings from
14 energy efficiency programs decreasing as shown in Ms.
15 Mitchell's Figure 16?
16 A.No. In fact, these two forecasts are very
17 similar and both only include the peak demand reduction
18 from existing and corni tted energy efficiency programs.
19 Witness Mitchell's erroneous conclusion results
20 from using the estimated peak reduction published in the
21 2008 Update and 2009 Addendum, which are from two
22 different forecasts beginning with two different base
23 years. The expected case peak savings from Table 8, p.
24 21, in the 2008 Integrated Resource Plan Update include
25 cumulative savings
753 PENGILLY, 01 REB 7
Idaho Power Company
.
.
.
1 from 2007 through 2027. The expected case peak savings
2 published in the Integrated Resource Plan Addendum -
3 February 2009, p. A-24, begin in year 2009 and accumulate
4 through 2028. These two forecasts should not be compared
5 as they are in Mitchell's Figure 16 because the forecast
6 from the 2008 Integrated Resource Plan Update includes
7 more years of accumulated peak demand reduction data.
8 Q.How does Idaho Power account for its demand
9 response programs in the Company's load and resource
10 balance analysis?
11 A.Idaho Power accounts for its demand response
12 programs in two ways, as existing and committed resources
13 and as new resources. In the Company's Response to Staff
14 Production Request No. 84, Idaho Power included in its
15 committed peak reduction resources the A/C Cool Credìt
16 program, peak reduction from its energy efficiency
17 programs, and the peak reduction from its existing
18 Irrigation Peak Rewards timer program. Idaho Power
19 included the new Flex Peak Management program, and the
20 incremental difference of the new dispatchable Irrigation
21 Peak Rewards as new resources. For the Irrigation Peak
22
23 /
24
25 /
754 PENGILLY, DI REB 8
Idaho Power Company
.
.
.
21
1 Rewards program, the estimated load reduction was:
2 Irrigation Peak
Existing
34
34
34
34
Rewards
New
88
132
176
176
Total
122
166
210
210
3 2009
2010
2011
2012
4
5
6 Q.Is this the current level of peak reduction
7 Idaho Power forecasts from the Irrigation Peak Rewards
8 program?
9 A.No. Idaho Power made these estimates last year
10 during the course of preparing Case No. IPC-E-08-23,
11 prior to the implementation of the Peak Rewards program
12 changes. Since the dispatchable option for the
13 Irrigation Peak Rewards program is new this year (2009),
14 it has been and will continue to be difficult for Idaho
15 Power to forecast peak reduction until the Company has
16 operated the program and can determine more precisely
17 what the results of the program will be. The Company's
18 current estimates are included in Mr. Bokenkamp' s Exhibit
19 No. 10.
20 IMPACT ON WINTER PEA
Q.Could you explain how Idaho Power's energy
22 efficiency programs affect winter peak?
23 A.The savings from Idaho Power's energy
24 efficiency programs are achieved throughout the year,
25 including winter peak. Depending on the energy
755 PENGILLY, 01 REB 9
Idaho Power Company
1 efficiency program and measure, different programs affect.2 winter peak at different levels.
3 Idaho Power's programs incent customers with
4 inefficient electric heat to convert to efficient
5 electric heat and efficient air conditioning. For
6 example, in the Heating and Cooling Efficiency program,
7 customers are incented to either replace existing heat
8 pumps, install heat pumps where natural gas in not
9 available, or install a heat pump in new construction
10 where natural gas is not available.In the Rebate
11 Advantage program, customers are incented to buy new
12 electrically-heated Energy Star~ manufactured homes. In.13 the Energy Star~ Homes Northwest program, Idaho Power
14 pays incentives to builders who build homes heated with
15 any source, but the Company only counts the electric
16 savings in its cost-effective analysis. To ensure that
17 Idaho Power's programs are cost-effective, all of its
18 programs must result in electricity or electrical peak
19 demand savings.
20 Q.Does this conclude your testimony?
21 A.Yes, it does.
22
23
24.25
756 PENGILLY, 01 REB 10
Idaho Power Company
.
.
.
10
11
1 (The following proceedings were had in
2 open hearing.)
3 MS. NORDSTROM: With the Commission's
4 indulgence, I would like to ask Mr. Pengilly a few
5 supplemental direct questions in response to Exhibit 901
6 from Mike Heckler that was received last night.
7 COMMISSIONER KEMPTON: Proceed.
8 MS. NORDSTROM: Thank you.
9
DIRECT EXAMINATION
12 BY MS. NORDSTROM: (Continued)
13 Q Mr. Pengilly, were you at the public
14 hearing last night?
15 A No, I was not.
16 However, have you been presented with aQ
17 copy of the comments of Mike Heckler that has been marked
18 as Exhibit 901?
19 Yes, I received one this morning.A
20 I realize that you weren't present at theQ
21 hearing and you don't have a transcript, but do you have
22 any general observations based on your review of
23 Mr. Heckler's comments?
24 Yeah, after a brief review of this, I doA
25 see a few places in here I would like to comment on.
CSB REPORTING
[phone]
757 PENGILLY (Di-Reb)
Idaho Power Company
.
.
.
1 Most of the places that I will comment pertain to the
2 areas that I know about, that I'm knowledgeable on.
3 There may be other issues in here that other people may
4 choose to discuss because I think there are other issues,
~
5 but I guess what I would like to address first is in at
6 least two places in this document, Mr. Heckler says,
7 implies and says, that somehow our cost effectiveness for
8 demand side management programs is linked to the amount
9 of rider funding that we are provided and I would just
10 like to say that is not so.
11 Our Company has a direction and I think
12 we're on the record in numerous places of pursuing all
13 cost-effecti ve energy efficiency and demand response. We
14 meet, the energy efficiency group meets, regularly with
15 pricing and regulatory and senior management and we have
16 never been given the direction to limit our acti vi ties
17 based on rider funding, and in fact, pulling a few
18 numbers from our annual DSM report that we file with the
19 Commission, it shows that from Appendix 1 of the reports,
20 if you would look at them through the years, that
21 beginning in 2006, we actually spent more money on DSM
22 than we collected.
23 I started in this department three years
24 ago. We had approximately a $6.5 million balance in the
25 rider, the energy efficiency rider, account and at the
CSB REPORTING
[phone]
758 PENGILLY (Di-Reb)
Idaho Power Company
.
.
.
1 end of last month, we had a deficit balance of almost $10
2 million, $9.8 million, so I think it's obvious that the
3 Company is committed to this and has spent money beyond
4 the rider. It in no way is figured into our calculations
5 of cost effectiveness. That's not to say that we don't
6 take seriously how we spend it and how carefully we try
7 to be in making sure things are cost effective, but it
8 doesn't limit us in any way.
9 In several places in here he discusses air
10 condi tioning and the air conditioning load and how that
11 affects residential load profile and such. I'm
12 paraphrasing. I don't really want to go item by item,
13 but we have a very robust residential AC cycling program
14 where we cycle air conditioners. We have approximately
15 25-27,000 participants. We've recently expanded that
16 into Pocatello and Twin Falls and that's one way we're
17 addressing that peak load.
18 He also discusses more efficient air
19 conditioners and we have seriously looked into incenting
20 more efficient air conditioners, but as of January 2008,
21 the code changed to require SEER 13 air conditioners.
22 When you go above this amount to SEER 14, 15, 16, the
23 incremental savings compared to the incremental cost,
24 they're just not cost effective. They're not cost
25 effecti ve for the customer or for the Company to incent.
CSB REPORTING
[phone]
759 PENGILLY (Di-Reb)
Idaho Power Company
.
.
.
1 We realize there's a lot of legacy equipment out there
2 that is not up to that, but we've just not figured out a
3 way to incent those cost effectively, and I've also
4 learned that sometimes these more efficient air
5 condi tioners actually have the same or greater load on
6 peak, so they don i t necessarily decrease peak, but they
7 are over the long haul more energy efficient.
8 In here he discusses -- I'd also like to
9 say about that, we do incent efficient heat pumps which
10 are an air conditioner and a heater, especially in the
11 areas of our service territory without gas, so we do try
12 to get people to use efficient heating and cooling in
13 those areas combined.
14 In here he talks quite a bit about the
15 irrigation peak rewards program and how we are not
16 perhaps promoting that or something, getting as big a
17 participation as we possibly could. We also disagree
18 wi th that. We think that we are. We're just starting
19 the new dispatchable program this summer. We had planned
20 on about 1, 000 participants. We have somewhere in the
21 neighborhood of 1,200 now and it even got to the point
22 where we ran out of equipment, so we're still installing
23 equipment on that. I think we've promoted that program
24 and we see that program growing in the next few years as
25 we show in our load forecast.
CSB REPORTING
[phone]
760 PENGILLY (Di-Reb)
Idaho Power Company
.
.
.
1 Another point he makes is that we don't
2 attribute any energy savings to the peak rewards program
3 and he points out that irrigators irrigate 24/7, so
4 obviously, if they decrease any amount of usage, they
5 decrease the energy usage. Well, if that were true that
6 they did operate 24/7 all the time, he would have a valid
7 point, but I've consul ted with our irrigation experts and
8 in fact, many of these irrigators and farmers do not
9 operate 24/7, almost, 24/6, 24/6-and-a-half, but most of
10 them that are able to participate in these programs have
11 a little bit extra capacity; otherwise, they couldn't
12 participate. They need X amount of water on their crops,
13 so we do feel that any energy that is lost during the
14 demand response events is recouped somewhere else, so
15 there is no energy savings; however, we do account for a
16 slight bit of benefit from this because the energy that
17 they use is then not on peak or at least not on our
18 peakiest time, let's say.
19 In the very last part of the document he
20 says that in the IRP process we should take into account
21 price elasticity and the pricing and regulatory group and
22 our group perhaps should work more together or something.
23 I think we work very well together. Right now we're
24 working on the load forecast as you all know and there is
25 a price elasticity component in there. I would not
CSB REPORTING
[phone]
761 PENGILLY (Di-Reb)
Idaho Power Company
.
.
.
1 venture to be an expert on that, but in my discussions
2 with the IRP team, I know they are incorporating that.
3 Let me look through here real quickly. He
4 also in one of his graphs, he shows load reduction on
5 page 7 on the red line towards the bottom, he shows 176
6 megawatts of load reduction from the peak rewards
7 program, let's say new peak rewards program, the new
8 aspect of it. That is -- I explain that in my testimony,
9 actually. This is probably the first time we've had a
10 program that is included in the load forecast and the
11 incrementally new energy efficiency lines of these
12 documents, so it's a little confusing, I'll admit, but
13 the old program, so to speak, the timer program that is
14 accounted for in our DSM forecast of results we expect
15 includes that program, but the new program which is on
16 the lower lines of these documents, if we were to put the
17 full amount of load reduction in there, we'd be double
18 counting because in a sense we i re going to degradate the
19 old timer program in order to put some of those customers
20 into our dispatchable program, so that number down there
21 that he has as 176 should really be closer to 210 or so,
22 and I show a similar chart in my rebuttal testimony.
23 That's about it, I think, on a maybe not so brief look at
24 this document.
25 MS. NORDSTROM: Thank you. With that, I
CSB REPORTING
[phone]
762 PENGILLY (Di-Reb)
Idaho Power Company
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10
1 will tender this witness for cross-examination.
2 COMMISSIONER KEMPTON: Mr. Richardson.
3 MR. RICHARDSON: Thank you, Mr. Chairman.
4
5 CROSS-EXAMINATION
6
7 BY MR. RICHARDSON:
8 Q Good afternoon, Mr. Pengilly.
9 A Hello.
Q Staying with this Exhibit 901 that you i ve
11 been critiquing for your counsel, I'm going to read you
12 two sentences from it and ask whether or not you agree
13
14
wi th the author. On page 2, the second to the last
sentence in that first paragraph appears this sentence,
15 "The fundamental resource problem that Idaho Power faces
16 today -- that Idaho Power faces continues to be how to
17 meet its large and growing summer demand peak," and then
18 on the very last page in the second full paragraph the
19 author says, "The most compelling argument for its
20 immediate procurement -- Langley Gulch is a very
21 expensive resource. The most compelling argument for its
22 immediate procurement is that it might be needed as a
23 peaker in 2012." Do you have any comments on those two
24 sentences?
25 A Well, the load deficits are not really my
CSB REPORTING
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763 PENGILLY (X-Reb)
Idaho Power Company
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10
1 area of expertise. That would probably be better
2 directed at Karl Bokenkamp. My comments were directed at
3 our work to decrease peak and that's more of a historic
4 problem so far and it's accounted for in the load
5 forecast through 2012.
6 So you don't have an opinion as to whetherQ
7 or not the author was correct or not when he said that
8 the most important use for Langley Gulch is as a
9 peaker?
A Well, I think our load forecast and our
11 deficits presented by Mr. Bokenkamp show otherwise
12 personally, but...
13 MR. RICHARDSON: Thank you,
14 Mr. Chairman.
15 COMMISSIONER KEMPTON: Ms. Ackerman.
16 MS. ACKERMAN: None, Mr. Chairman.
17 COMMISSIONER KEMPTON: Mr. Olsen.
18 MR. OLSEN: No questions, Mr. Chairman.
19 COMMISSIONER KEMPTON: Mr. Purdy.
20
21
22
23
24
25
CSB REPORTING
[phone]
764 PENGILLY (X-Reb)
Idaho Power Company
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.
.
1 CROSS-EXAMINATION
2
3 BY MR. PURDY:
4 Q Well, I just wanted to clear something up,
5 if you would turn to your rebuttal testimony,
6 Mr. Pengilly, beginning on page 5 there, you have a
7 Figure 1 and then on the next page a Figure 2. Do you
8 see those?
9 Yes, I do.A
10 Q I just want to make sure I understand what
11 these purport to be and you use this to criticize Ms.
12 Mi tchell 's testimony, I believe, and say that she is
13 taking into account the cumulative when she shouldn't
14 have, cumulative effect of these various programs or
15 something along those lines. Excuse me if I
16 misparaphrase her testimony, but let me ask you straight
17 out: What is Figure 2 supposed to represent? Is that
18 the current and future demand side management programs,
19 their effect on load once they come to maturity; is that
20 what you're saying there?
21 Not exactly and that's what I wasA
22 attempting to clarify in this answer here. Those are
23 strictly from our demand response programs. Demand and
24 demand response programs, the demand reduction that you
25 attain is not cumulative. If you get it this year,
CSB REPORTING
[phone]
765 PENGILLY (X-Reb)
Idaho Power Company
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1 you're not necessarily going to get it next year and our
2 irrigation program in particular is almost like a new
3 program every year because of crop rotation, change of
4 ownership, perhaps weather , commodity prices. Farmers
5 change what they grow and where they grow it. Some of
6 these crops can tolerate participation in our program,
7 some can't, and so that's what I'm saying, every year is
8 like starting over and I guess what I was trying to
9 illustrate here primarily is that we do forecast a large
10 increase in our demand response, but we also expect it to
11 hi t maturity and flatten out at some point. Does that
12 answer your question?
13 Q Well, somewhat . Given and referring to
14 Exhibit 901 and given the admonition that Mr. Heckler
15 points out there that the Commission issued, I guess, in
16 the Evander Andrews power plant case to the Company to
17 diligently and vigorously pursue all available
18 cost-effecti ve DSM and yet, here you are now, of course,
19 asking for another peaker plant, have you run out of DSM
20 ideas? Are you vigorously pursuing all available DSM
21 possibilities?
22 A Well, first, I think I'd like to point out
23 that I don't think we're asking for a new peaker plant.
24 I think we're asking for a new baseload plant.
25 Q To meet your summer peak more or less;
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766 PENGILLY (X-Reb)
Idaho Power Company
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1 right? I mean, you don't need that for, as has been
2 pointed out you don't need that, the maj ori ty of the
3 year; correct?
4 Like I said, I'd have to refer to KarlA
5 Bokenkamp for that.
6 Q That's fine.
7 A No, we have not run out of ideas
8 necessarily. We just see a limit in demand response in
9 particular, not energy efficiency, we do see a limit at
10 some point.I'm not sure where that is. This just shows
11 the programs that we are committed to and that we have
12 started. This doesn't show any new programs. For
13 example, we have recently filed for a commercial demand
14 response program with the Commission as a pilot and that
15 was denied. We still plan on trying to obtain enough
16 data to someday offer that program cost effectively, but
17 right now we offer a demand response program to all of
18 our customer classes except the small commercial.
19 We're probably the only utility in the
20 Northwest that does that and this is our first year with
21 the dispatchable irrigation load control program. We'll
22 see where that goes, but we don't see a -- I mean,
23 there's only so many farmers out there, there's only so
24 many air conditioners.For example, right now we work
25 with the Regional Technical Forum over in Portland and
CSB REPORTING
[phone]
767 PENGILLY (X-Reb)
Idaho Power Company
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1 right now there's a lot interest in dispatchable electric
2 hot water heaters.
3 Are you saying that every customer in anyQ
4 given customer class is currently being served or even
5 eligible for whatever demand side management or demand
6 response program might be available to their class? In
7 other words, isn't there room still within the classes to
8 serve additional customers?
9 We hope so. We don't -- I'm not sayingA
10 that we offer for example, if you don't have a central
11 air conditioner, you can't participate in the A/C cool
12 credi t program, that's obvious.If an irrigator doesn't
13 have the band width or the capacity to participate in our
14 programs, they obviously can't. Our other program is the
15 flexpeak program for large commercial and industrial.
16 Some of those customers can, some can't, but at least we
17 offer it to the class.
18 Q All right, and in terms of your
19 responsibili ties with the Company, do you have a -- I
20 assume you have a group of co-employees that work under
21 you or with you and are, for lack of a better term,
22 brainstorming new DSM ideas and ways to pursue DSM in
23 general; is that right?
24 A Yeah, we actually have a staff of about 30
25 now. Those people do from marketing to advertising to
CSB REPORTING
[phone]
768 PENGILLY (X-Reb)
Idaho Power Company
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1 program management to research. We don't personally
2 spend a whole lot of money on research and development.
3 That's hard to justify, but we participate with a lot of
4 Northwest groups. We follow all the literature. You
5 know, we try to stay on the leading edge of technology.
6 Like I say, we work with the Technical Forum in Portland,
7 NEEA, the Power Planning Council. We talk to other
8 utili ties regularly on ideas. It's a pretty close
9 community. I mean, if somebody comes up with a great
10 idea, we know about it pretty quickly, but we don't spend
11 a whole lot of money on R&D. We spend a little bit.
12 Q And just one final question. Would you
13 agree that Idaho and Idaho Power's, in particular, needs,
14 unique needs and possible DSM opportunities might vary
15 significantly from those west of the Pacific Crest?
16 A They do.
17 Q Where a lot of these ideas that you refer
18 to originate?
19 A We do a lot of work with Rocky Mountain
20 Power down in Utah, northern Idaho, they're very similar.
21 We actually follow California. There's some participants
22 in the Pacific Northwest -- it's called PNDRP, Pacific
23 Northwest Demand Response Proj ect. There's
24 representatives there from California. The central
25 valley has very similar climate as we do. We work with
CSB REPORTING
[phone]
769 PENGILLY (X-Reb)
Idaho Power Company
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1 Berkeley Labs in Berkeley, obviously, and they are a big
2 research outfit. There's a lab up in Washington that's
3 sponsored by WSU, Washington State Uni versi ty. They do a
4 lot of research, a lot of the consultants actually that
5 do a lot of bench testing of appliances and bulbs and
6 whatnot.
7 MR. PURDY: Okay, well, thank you,
8 Mr. Pengilly. Mr. Chairman, thank you.
9 COMMISSIONER KEMPTON: Mr. Miller.
10
11 CROSS-EXAMINATION
12
13 BY MR. MILLER:
14 Thank you, Mr. Chairman, and goodQ
15 afternoon, Mr. Pengilly. We talk a lot in the IRP about
16 what is cost effective in terms of energy efficiency and
17 how we determine what constitutes cost effective and all
18 cost-effective measures and if I could direct you again
19 to Exhibit 901 at the bottom of page 10 and the very top
20 of page 11, I think you were asked, and this was through
21 an ICL Production Request No. 15, about what would happen
22 if we used the 12 cents a kilowatt-hour, which is what
23 Mr. Heckler puts Langley Gulch at, to model that and see
24 whether we could capture additional average megawatts or
25 megawatts and he quotes you as saying that that modeling
CSB REPORTING
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770 PENGILLY (X-Reb)
Idaho Power Company
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1 or that analysis had not been performed. My question is
2 do you think there is value in doing that analysis and if
3 we haven't done it, why not?
4 Well, we do consider levelized cost in ourA
5 analysis of cost effectiveness, but a program or a
6 measure can have a high or a low levelized cost and still
7 not be cost effective. We base our cost-effectiveness
8 analysis and tests on the California manual and the EPRI
9 TAG manual and we use those to determine our methodology,
10 not levelized costs, per se, although, like I say, we do
11 calculate that, but at the end of the day in the IRP
12 process after we identify cost-effectiveness programs and
13 potential, we do look at the levelized cost of those
14 programs or of those programs in aggregate and it's
15 listed right in the, like the '06 IRP, it's listed in the
16 stack of levelized costs, and we do it in that regard.
17 We've never looked at -- when I said we
18 hadn't done that analysis, we hadn't done that analysis,
19 but it may be of dubious benefit to look at just that
20 metric. If we determined a program was cost effective
21 and then looked at the levelized costs, then that's a lot
22 better way of looking at it.
23 There was a discussion yesterday, and I'mQ
24 hoping you can answer this, the question might be better
25 directed at Mr. Bokenkamp or Mr. Gale, about the timing
CSB REPORTING
[phone]
771 PENGILLY (X-Reb)
Idaho Power Company
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1 of the full featured sales and load growth in August and
2 the IRP in June and I guess my question from a DSM
3 perspective would be do you see any merit or value in
4 perhaps harmonizing those two so when you're putting
5 together the IRP you have that fresh sales and load
6 growth data?
7 Well, we actually contribute to that, theA
8 August forecast every year and, of course, in the years
9 when there's an IRP, that's the one that's used. I think
10 the reason for the delay, quite frankly, is just the
11 amount of work that it takes after we get a load forecast
12 to do an IRP, but Karl would be better to address that,
13 but, you know, of course, it would be better to have more
14 data sooner, but you don't always have that luxury and it
15 just takes a certain amount of time to put all that
16 together. Our piece is actually one of the less time
17 sensi ti ve, I suppose, unless, like Mr. Purdy suggested,
18 we get a pleasant surprise and there's some huge new cfl
19 bulb that comes out or something, but that's probably not
20 going to happen in eight or ten months, I mean no matter
21 what.
22 MR. MILLER: Thank you. Thank you, Mr.
23 Chairman.
24 COMMISSIONER KEMPTON: Ms. Bridge.
25 MS. BRI DGE : Thank you.
CSB REPORTING
[phone]
772 PENGILLY (X-Reb)
Idaho Power Company
1 CROSS-EXAMINATION. 2
3 BY MS. BRIDGE:
4 Q Mr. Pengilly, I'm still -- as Mr. Miller
5 said, through the IRP process it's often said that the
6 Company is committed to pursuing all cost-effective
7 efficiency and DSM programs. I'm still kind of
8 struggling with what you mean by cost effective. Could
9 you give a little bit more clarification as to what cost
10 effective means?
11 A Sure. Let me preface ita little bit by
12 saying this isn't our idea. We have to satisfy our
13 regulators in both Idaho and Oregon. We conform to most.14 of the other companies in the Northwest in basically how
15 we all do cost effectiveness probably in the West with a
16 few -- you know, everybody is a little bit different, but
17 generally, we obviously want to compare costs with
18 benefits, so we take a measure, say, cfl light bulbs,
19 there are certain load curves out there that show us when
20 cfl light bulbs provide their benefits.
21 These are usually produced by a regional
22 entity like the RTF or someone. These are very expensive
23 to get, so we don't all do them, so then we have an
24 end-use load curve, so to speak, of the benefits. That's.25 the reduced kilowatt-hours, and that's across the year
CSB REPORTING
[phone]
773 PENGILLY (X-Reb)
Idaho Power Company
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1 and then we have our DSM avoided or al ternati ve costs
2 that are produced in the IRP process that are published
3 in the technical appendix. They are time segregated into
4 on and off peak -- well, off and mid peak in the winter
5 and on peak, mid peak and off peak in the summer, and so
6 we know the cost, avoided cost, of that, so we put our
7 load curves against those costing periods and come up
8 wi th a benefit-cost in avoided energy, and then from the
9 cost side, we obviously put in what it costs to run the
10 program, what it costs to buy the bulb or whatever it is
11 and then we discount ita little bit for the probability
12 that perhaps a bulb might not get installed, might sit on
13 a shelf, get broken, you know, whatever.
14 Usually these benefits are slightly
15 discounted and those numbers we usually get from the DEER
16 database in California or some numbers the RTF put out
17 and so then we determine all of our costs rolled up and
18 then we see which is greater and if the benefits outweigh
19 the costs, if the ratio is greater than one, we like it
20 to be not 1.0111, we like it to have a little room there,
21 if it's greater than that, then we consider that cost
22 effecti ve.
23 Now, let me say sometimes on the benefit
24 side it's not strictly energy. There can be other
25 benefi ts that are rolled in there. Like with efficient
CSB REPORTING
[phone]
774 PENGILLY (X-Reb)
Idaho Power Company
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1 washing machines, you know, the water benefits can be
2 considered. The cost of heating that water can be
3 considered. You know, it just kind of depends on the
4 program. In some of our irrigation programs, for
5 example, our efficiency programs, not our demand response
6 programs, there's considerable labor savings to these
7 farmers when they switch from lines to pivots, so we add
8 in the benefit there. Does that help?
9 Q Yeah, thank you.
10 I guess I should continue a little. AfterA
11 we reach that threshold, then we go ahead and do the
12 program and sometimes these things are hypothetical at
13 first and then we like to look back and do an evaluation
14 and see, well, what did we get. Sometimes that's easy,
15 sometimes that's hard. Sometimes we use third parties,
16 but we do like to then look back, and then we adj ust all
17 this stuff based on those results and it's described in
18 our annual report in the first section and it's also
19 described in the technical appendix of the 106 IRP, but
20 that's getting a little bit dated, that description.
21 That's not as accurate as the one in our '09 DSM
22 report.
23 Thank you, and so your DSM and efficiencyQ
24 programs are funded by the tariff rider and you
25 previously mentioned that you're running at a deficit.
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[phone]
775 PENGILLY (X-Reb)
Idaho Power Company
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1 What are the implications of when you are implementing
2 more programs than the tariff rider funds?
3 Well, let me first say they're not allA
4 funded by the tariff. Most of them are, but our
5 weatherization for qualified customers, for example, is
6 funded through base rates. Some of our Oregon programs
7 are funded from other than the rider out of base rates,
8 but you're essentially correct. As you probably all
9 know, we filed for a rider increase in June and our
10 analysis of that, of our spending and savings, we should
11 come back into not being in deficit spending by mid
12 summer next year and then probably go back into deficit
13 briefly, because when our expenses hit is usually late
14 summer and then by the first of 2010 or into early 2011
15 we should be back with a so-called posi ti ve balance in
16 that account.
17 That is presuming pretty much running
18 programs as usual with a little bit of incremental
19 increase, but ideally, we would like to see that account
20 sort of dip in and out from a positive balance to a
21 negative balance. That's our goal. That's hard to do
22 and, like I say, our financial forecast is a forecast,
23 but we see coming out of that balance. The
24 ramifications, you mean from a --
25 When you go into a deficit, does thatQ
CSB REPORTING
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776 PENGILLY (X-Reb)
Idaho Power Company
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1 affect any of the programs?
2 No. Lori may be able to say how itA
3 affects our financials. I can't address that.
4 Q And do you believe that the Company at
5 this time is pursuing all cost-effective efficiency and
6 DSM programs?
7 I do. I'd like to put a little caveat onA
8 that, though. You know, it takes years to develop these
9 programs. We've been at it -- I've only been in the
10 department three years, but we've been pretty actively
11 going at it since about 2002, '03 and it's taken us -- I
12 think we've ramped up very quickly, but it still just
13 takes time. We aren't -- it takes customer
14 participation. It takes marketing. It takes a lot of
15 effort on the customer side of things to get into -- to
16 be able to provide these.
17 One of our programs, energy house calls,
18 it's for manufactured homes, we go in and seal the ducts,
19 replace the furnace filters, put in cfl's, give them
20 education materials, sort of consult with them on what
21 they can do to save energy. It's no cost to the
22 customer, no cost, and we still sometimes have a hard
23 time getting people to do it. You need that customer
24 participation, so I think we've ramped up as fast as we
25 reasonably could without being sloppy or unprudent or
CSB REPORTING
[phone]
777 PENGILLY (X-Reb)
Idaho Power Company
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1 something, but I think if you consider the ramp rate it
2 takes to do these programs, I think we are.
3 And just more question, do you think thatQ
4 the Company is pursuing all efficiency and DSM
5 opportunities that would be cheaper than building a new
6 power plant?
7 I don't know on that one. That's sort ofA
8 the question you asked before. We haven't really done an
9 analysis exactly like that, but we get our avoided costs
10 out of the IRP process, out of AURORA, which takes into
11 account all of our resources, how they're dispatched, you
12 know, so, for example, if a plant is not running and so
13 it's not in the resource stack at the time, those costs
14 shouldn't be included. Our avoided costs are calculated
15 differently than that and more robustly, I think, than
16 comparing it to one plant.
17 MS. BRIDGE: Thank you, Mr. Pengilly.
18 Thank you, Mr. Chairman, no further questions.
19 COMMISSIONER KEMPTON: Mr. Woodbury.
20 MR. WOODBURY: Thank you, Mr. Chairman.
21
22
23
24
25
CSB REPORTING
[phone]
778 PENGILLY (X-Reb)
Idaho Power Company
. 2
.
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1 CROSS-EXAMINATION
3 BY MR. WOODBURY:
4 Mr. Pengilly, there was some discussionQ
5 regarding Exhibit 901 which was the public testimony
6 exhibi t from yesterday evening and that was submitted by
7 Michael Heckler who in the course of this discussion and
8 I think as reflected in the exhibit has attended many of
9 the Company's integrated resource plan advisory group
10 meetings and there is a counterpart, though, for the
11 is the energy efficiency advisory group; correct?
12 A Correct.
13 And they deal with the DSM, energyQ
14 efficiency, conservation programs?
15 A Correct.
16 Does Mr. Heckler attend those meetings?Q
17 I can't say for sure, but I can't recallA
18 ever seeing him there. I don't really know him. I know
19 who he is.
20 Do you attend those meetings?Q
21 Oh, yes.A
22 MR. WOODBURY: Okay. Thank you very much.
23 Mr. Chairman, no further questions.
24 COMMISSIONER KEMPTON: Commissioner
25 Redford.
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779 PENGILLY (X-Reb)
Idaho Power Company
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1 COMMISSIONER REDFORD: No questions.
2 COMMISSIONER KEMPTON: Commissioner
3 Smith.
4 COMMISSIONER SMITH: Thank you.
5
6 EXAMINATION
7
8 BY COMMISSIONER SMITH:
9 Mr. Pengilly, I do appreciate one thingQ
10 about Mr. Heckler's testimony and that was being reminded
11 what we said in our Order concerning the Evander Andrews
12 plant about the Company being required to diligently and
13 vigorously pursue all available cost-effective DSM,
14 conservation and pricing options and it's always been my
15 belief that if a utility did that, it could postpone the
16 need for its next new baseload or peaker plant. Would
17 you agree with that?
18 A It kind of depends on the time lines that
19 you're looking at, how far in deficit you've gotten, what
20 kind of loads you need to make up. I know there are
21 certain utili ties that are attempting to do that
22 presently, but I don't know of anyone who has
23 successfully done that.
24 Well, it's clear, it doesn't take you intoQ
25 the future indefinitely, but a day, a week, a month. I
CSB REPORTING
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780 PENGILLY (Com-Reb)
Idaho Power Company
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1 mean, couldn't it take you some distance?
2 A Oh, I see what you mean. I suppose
3 theoretically it could. That's our goal is to decrease
4 load to where we need fewer resources whether it comes
5 from purchased power or any resource.
6 Q So if the Company has been diligently and
7 vigorously pursuing all available cost-effective DSM and
8 conservation, do you think it's had an impact on when new
9 resources are needed; i. e., Langley?
10 A You know, I'd hate to say definitively. I
11 think theoretically it could have pushed it out a ways.
12 I've got to remind you that we are -- you know, if you
13 look at that chart in my testimony, we're just now
14 ramping up to a point where we can have some more effect
15 on it. On page 5 of my testimony, if you look at that
16 through' 08, we're up, you know, in the 25 average
17 megawatt range, but in '12 we'll be up around 75 or
18 something, you know. It just takes awhile to ramp these.
19 I think eventually we could have an impact on resource
20 purchase.
21 Q Well, I guess from my point of view the
22 Company took a long time getting to ramp up, so I guess
23 maybe that's the unfortunate part about it. Given your
24 position as the -- you're the customer research and
25 analysis leader; is that right?
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781 PENGILLY (Com-Reb)
Idaho Power Company
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1 A Correct.
2 Q Okay; so maybe this is beyond, definitely
3 beyond, the scope of your testimony here, but have you
4 gotten any feedback on the tiered rates?
5 A A little bit, not as much as we expected,
6 though, so far. I don't know the exact numbers, but I
7 don't think we've gotten any positive feedback on them.
8 We have gotten some feedback.
9 So maybe the real measure will come in theQ
10 winter when the heating load is on?
11 A Yeah, and so far it's been a cool summer
12 and people haven't been hitting their air conditioners I
13 don't think. We may get more backlash because there's a
14 billing lag, so when they get their bills in August or
15 September and then the winter heating people will
16 definitely see the effect.
17 COMMISSIONER SMITH: Thank you very
18 much.
19 COMMISSIONER KEMPTON: I have no
20 questions. If there's no obj ection, the witness may step
21 down.
22 MS. NORDSTROM: I have no redirect.
23 (The witness left the stand.)
24 COMMISSIONER KEMPTON: We'll have a
25 10-minute recess.
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782 PENGILLY (Com-Reb)
Idaho Power Company
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10
1 (Recess. )
2 COMMISSIONER KEMPTON: Okay, the hearing
3 will come back to order and Mr. Richardson, any
4 addi tional witnesses that you have?
5 MR. RICHARDSON: Thank you, Mr. Chairman.
6 The Industrial Customers have one additional witness,
7 Dr. Reading.
8 COMMISSIONER KEMPTON: Call your witness
9 forward, please.
MR. RICHARDSON: Dr. Reading, would you
11 please take the stand?
12
13
14
DON READING,
produced as a witness at the instance of the Industrial
15 Customers of Idaho Power, having been first duly sworn,
16 was examined and testified as follows:
17
18 DIRECT EXAMINATION
19
20 BY MR. RICHARDSON:
21 Good afternoon, Dr. Reading.Q
22 Good afternoon.A
23 Would you please state your name and yourQ
24 business address for the record, please?
25 Don C. Reading, 6070 Hill Road, BoiseA
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783 READING (Di)
ICIP
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1 Idaho.
2 Q And are you the same Dr. Reading who
3 prepared prefiled direct testimony and Exhibits 201
4 through 205 in this proceeding?
5 A Yes.
And do you have any corrections or
7 addi tions to make to your testimony?
6 Q
One typo on page 6, let's see, line 14.
9 It should be "03" instead of "13" in the case number. It
8 A
10 should be the current case number.
11 COMMISSIONER KEMPTON: Which line was
12 that, Dr. Reading?
13 Q BY MR. RICHARDSON: Would you repeat that,
Okay, line 14, it should be "IPC-E-09-03,"
And do you have any corrections to make to
That's the only one. No corrections, just
And you were going to update the Oregon
22 dismissal versus --
14 Dr. Reading?
That's the NIPPC testimony.
Okay, I got confused, okay.
That's a different hat.
15 A
16 not "13."
17 Q
18 your testimony?
19 A
20 that one typo.
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CSB REPORTING
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784 READING (Di)
ICIP
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1 Q So if you were asked the same questions
2 this afternoon that you were asked in your prepared
3 testimony, would your answers be the same?
4 A Yes.
5 MR. RICHARDSON: Thank you. I would move
6 that Dr. Reading's testimony be spread upon the record as
7 if it were read in full and Exhibits 201 through 205 be
8 marked for identification purposes.
9 COMMISSIONER KEMPTON: Without obj ection,
10 so ordered.
11 (The following prefiled direct testimony
12 of Dr. Don Reading is spread upon the record.)
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CSB REPORTING
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785 READING (Di)
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1 Please state your name, address, andQ.
2 affiliation.
3 My name is Don Reading. I am Vice PresidentA.
4 and Consulting Economist for Ben Johnson Associates, 6070
5 Hill Road, Boise Idaho. My resume is attached as Exhibit
6 201.
7 On whose behalf are you testifying?Q.
8 The Industrial Customers of Idaho Power (ICIP)A.
9 have asked me to examine Idaho Power's (Company, IPCo)
10 filing for a certificate of public convenience and
11 necessity (CPCN) for its proposed Langley Gulch power
12 plant. I am filing separate testimony for the Northwest
13 & Intermountain Power Producers Coalition (NIPPC) that is
14 focused on the competi ti ve bidding aspects of the Request
15 for Proposals (RFP) process the Company used that
16 resul ted in the selection of the Langley Gulch facility.
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18
Q.What is the purpose of your testimony?
A.My testimony will focus on the competi ti ve
19 bidding process that Idaho Power used in its most recent
20 Request for Proposals (RFP) for a new supply-side
21 resource. The end result of that competi ti vely bid RFP
22 was that Idaho Power selected itself as the winning
23 bidder.Idaho Power issued its RFP on April 1, 2008 for
24 competi ti ve proposals for up to 600 MW of energy. In
25 June 2008, the amount was reduced to approximately 300
786 ICIP - Reading, Di 2
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1 MW.
2 How is your testimony organized?Q.
3 My testimony addresses several aspects of theA.
4 company's filing. I address the load proj ections used by
5 the Company to evaluate the four short-listed bids. I
6 examine the change, made in the middle of the RFP
7 process, that the company made in its natural gas
8 forecast used in developing the net present value (NPV)
9 estimates used to value the short-listed proj ects. I
10 analyze the scoring procedures used that resulted in
11 Langley Gulch being selected as the winner from the four
12 short-listed projects. I examine the company's
13 integrated resource plans (IRPs)
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787 ICIP - Reading, Di 2a
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1 and how they were used by the company in issuing its RFP.
2 I discuss the $8.7 million the company has paid to
3 reserve the Siemens equipment and how that may have
4 affected the selection of Langley Gulch. I will also
5 testify regarding the Company's refusal to allow a bid
6 and transfer (BAT) option other than their own. I
7 discuss financial considerations because of difficulties
8 the Company may face in raising capital for the plant and
9 point out that a tolling agreement or power purchase
10 agreement may solve that problem.
11 Q.Dr. Reading could you briefly review the four
12 proj ects that were short listed as the result of Idaho
13 Power's RFP process that resulted in the selection of the
14 self-build Langley Gulch proj ect.
15 A.Company witness Bokenkamp' s Exhibit Nos. 2 and
16 3 present the Company's NPV analysis for "each of the
1 7 three short-listed proj ects" . The Benchmark Resource is
18 Proj ect D. (Bokenkamp, pg 12). The other two proj ects
19 displayed in his Exhibits are Band E3.
20 *************BEGINNING OF CONFIDENTIAL*****************
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791 ICIP - Reading, Di 5
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1 What load forecast did the Company use in itsQ.
2 RFP analysis?
3 A.According to a computer file in Idaho Power's
4 Discovery Room titled, "Idaho Power Assumptions Scenarios
5 Worksheet. xls" the load forecast used was completed in
6 September of 2008. The forecast to be used in the 2009
7 IRP will be an updated forecast to be completed later
8 this summer. However, the Company has asked the
9 Commission that its 2009 IRP be delayed from June 2009
10 until December 2009 (IPC-E-09-03). This delay in the
11 filing of the IRP was in part due to:
12 "Substantial changes in economic condi tions
13 have occurred since September of 2008 when the load
14 forecast currently being used for the 2009 IRP was
15 completed. Slowed locan and national economic growth may
16 impact the future growth of Idaho Power's customers'
17 electric loads and the Company believes it would be
18 prudent to update the sales and load forecast prior to
19 completing the 2009 IRP. Idaho Power expects to complete
20 the new sales and load forecast in August 2009."
21 IPC-E-09-03, Application at pp. 2 - 3.
22 And:
23 "Unquestionably, the current recession has
24 temporarily slowed economic growth and correspondingly
25 affected Idaho Power's customers and their electric
792 ICIP - Reading, Di 6
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1 loads. Because Idaho Power will have completed a new
2 load forecast in August 2009, the Company has concluded
3 that the data from the August 2009 forecast should be
4 considered in the development of the 2009 IRP"5 Id. at p 6.
6 Idaho has not been immune from the current
7 economic downturn. According to the U. S. Bureau of Labor
8 Statistics, after being among the national leader.s in job
9 growth over the
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793 ICIP - Reading, Di 6a
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1 past decade, the state's non-farm jobs declined in 2008
2 for the first time since 1986. The decline was one
3 percent, and the loss has accelerated in the current
4 year. Job losses in Idaho were over 33,000 between March
5 2008 and March 2009. Idaho's unemployment rate hit 7.1
6 percent in March, up three percentage points from a year
7 earlier to its highest level in 21 years.
8 What impact does the economic slowdown andQ.
9 Idaho Power's revising its sales and load forecast have
10 on the Langley Gulch proposal?
11 The need for the resource called for in the RFPA.
12 and the evaluation of the proposals are not based on the
13 That the Company has asked theCompany's current needs.
14 Commission for a ruling on the CPCN by September 1st,
15 coupled with the new lower forecast, means the resource
16 may not be needed in the time frame currently proposed by
17 the Company. This is not to say the resources are not
18 needed, just that they may not be needed as soon as the
19 Company thought when it started the RFP process. The
20 economy is still in a state of flux.For example, just
21 last week it was announced by Hoku that they may not have
22 financing to finish the construction of their Pocatello
23 facili ty. This would mean a delay or reduction of 80 MW
24 in new load that Idaho Power currently expects to have to
25 meet.
794 ICIP - Reading, Di 7
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1 What natural gas forecast was used in the RFPQ.
2 evaluation process?
3 When the RFP was issued in April 2008 it statedA.
4 the gas assumption to be used in the evaluation process
5 would be the NWPCC forecast normalized with a 2.5%
6 escalation rate (the NWPCC forecast is done in real
7 terms). However, on October 17, 2008, the due date for
8 the proposals to be submitted, the Company revised its
9 natural gas forecast. The revised forecast was
10 significantly higher. The revised forecast and the
11 original forecast are shown on my Exhibit 203. It is
12 significant that the April 2008 forecast was relatively
13 low despite the fact that actual
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795 ICIP - Reading, Di 7a
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1 prices in April 2008 were comparatively high. When the
2 Company revised its forecast in October 2008 prices had
3 fallen, but the forecast went up.
4 Q.Why is this significant?
5 This means the evaluation of the variousA.
6 proposals was undertaken with a higher fuel forecast than
7 the bidders were led to believe would be used. A higher
8 gas forecast may have led some bidders to propose
9 al ternati ve generation configurations. With a lower gas
10 forecast, the resource bid may have been less efficient
11 than one with lower capital costs but higher running
12 costs. A costing factor as important as the natural gas
13 forecast should not be changed in the middle of the
14 process.This fact may have led to some potentially
15 lower cost facilities to be eliminated from bidding.
16 Did you examine the scoring of the price andQ.
17 non-price items?
18 Yes. I have questions about both. TheA.
19 evaluation process assigned 60 points for price based on
20 a five year, an eight year and a twenty year NPV
21 analysis. It assigned 20 points for each period. The
22 RFP does list the non-price factors that were considered
23 for the scoring of each short-listed proposal. The seven
24 categories of non-price variables that were scored were:
25 (1) project development; (2) project characteristics; (3)
796 ICIP - Reading, Di 8
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1 product characteristics; (4) proj ect location; (5)
2 environmental; (6) credit factors; and (7) financial
3 strength. These non-price factors account for forty
4 percent of the total with price variables accounting for
5 the remaining sixty percent. In the RFP there were
6 addi tional explanations of what would make up the scoring
7 for each factor along with their respective weightings.
8 Q.What questions do you have on the price
9 scoring?
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802 ICIP - Reading, Di 11
I PC-E-O 9-03
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1 Dr. Reading, the Company in Mr. Gale'sQ.
2 testimony, states its preferred method for the Commission
3 issuing the CPCN is under the provisions of the newly
4 passed Senate Bill 1123. Does SB 1123 address the need
5 for a Commission approved generating unit meeting the
6 utility's resource plan?
7 Yes. Mr. Gale states at page 4 in hisA.
8 supplemental testimony that:
9 "The construction of the Langley Gulch Power
10 Plant is consistent wi th Idaho Power r s resource plans and
11 is an appropriate resource to supplement the Idaho Power
12 system. The December 2012 on-line date is consistent
13 wi th Idaho Power r s resource plans and the anticipa ted
14 load requirements of Idaho Power r s retail customers."
15 Do you agree with Mr. Gale's assessment ofQ.
16 Langley Gulch meeting the Company Integrated Resource
17 Plan (IRP)?
18 Only in part. Idaho Power's resource plan hasA.
19 been evolving since it filed its IRP with the Commission
20 in 2006. According to Mr. Bokenkamp's testimony:
21 "The preferred portfolio in the 2006 IRP
22 refined this resource need to a 225 MW power purchase
23 facilitated from what we called a McNary to Boise
24 transmission upgrade in 2012, a 250 MW pulverized coal
25 baseload resource in 2013 and a 250 MW regional IGCC (or
803 ICIP - Reading, Di 12
IPC-E-09-03
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1 "clean coal") project in 2017. Since the 2006 IRP was
2 published, escala ting concerns regarding clima te change,
3 C02 emissions and the publics perception of coal-fired
4 resources has made coal-fired resource development an
5 unrealistic alternative.These concerns coupled wi th the
6 possibili ty of new large loads locating in our service
7 territory and the anticipated shift of flow augmentation
8 releases of wa ter from the federal dams on the Snake
9 River above Brownlee Dam from July and August to May and
10 June, have prompted the Company to (1) revise the 250 MW
11 coal-fired resource to a natural gas-fired baseload
12 resource, (2) increase the size of the
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804 ICIP - Reading, Di 12a
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1 baseload resource to approximately 300 MW, and (3)
2 accelerate the on-line date of the base load resource to
3 2012."
4 The Company filed an update of its 2006 IRP
5 2008. The Updated Preferred Portfolio calls for the 250
6 MW Boardman to Hemingway (B2H) transmission line and 250
7 MW Southwest Idaho CCCT both in 2012.When the Company
8 issued its RFP for a baseload generation resource in
9 April 2008 it requested bids on a resource from 250 to
10 600 MW. The unit size request was lowered to 300 MW two
11 months after the issuance of the original RFP. Idaho
12 Power is currently in the process of developing its 2009
13 IRP that is to be filed by the end of the year. The
14 Company has asked the Commission for a six month delay in
15 filing its 2009 IRP because:
16 "Since the completion of the 2008 upda te,
17 several major events have occurred that make it desirable
18 to delay the filing date of the 2009 IRP until the end of
19 2009 to allow the Company to include the following in the
20 2009 IRP: (a) Recent permi tting delays have pushed the
21 completion of the Boardman to Hemingway 500 kV
22 transmission proj ect beyond 2012, as sta ted in Idaho
23 Power's 2008 Update. With this delay, the Company plans
24 to treat the Boardman to Hemingway project as an
25 uncommitted resource in the 2009 IRP. As an uncommitted
805 ICIP - Reading, Di 13
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1 resource, the 2009 will address whether the Boardman to
2 Hemingway project continues to merit inclusion in the
3 Company's near-term action plan;" (IPC-E-09-03, Petition
4 at p. 2 J
5 In addition, there have been substantial
6 changes in economic conditions since September 2008 when
7 the load forecast currently being used for the 2009 IRP
8 Therefore, the Langley Gulch facilitywas conducted.
9 may be the 250 MW Southwest Idaho CCCT called for in the
10 2008 Updated Plan, however, as the 2009 IRP delay
11 Peti tion states, there have been two maj or changes that
12 have occurred that can significantly alter the Company's
13 resource needs. As
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806 ICIP - Reading, Di 13a
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1 pointed out above, economic conditions in Idaho Power's
2 service terri tory are currently as least as bad as they
3 have been in the past two decades.
4 The 2008 Updated IRP was issued in June of last
5 year. The 2009 IRP, with an updated load forecast and
6 new estimates of fossil fuel prices, will be issued by
7 the end of 2009. These changes can have a significant
8 impact on the size and type of resource needed by the
9 Company. The environment in Idaho Power's service
10 territory has changed significantly over the last
11 eighteen months. It is unknown what impact that will
12 have on the 2009 IRP. In addition, Idaho Power's
13 shareholders have asked the Company to develop a resource
14 strategy that will lead to a reduction in greenhouse gas
15 emissions. The Company is asking the Commission to issue
16 a CPCN for Langley Gulch by September 1 of this year,
17 despi te the fact that there will be a new forecast the
18 following month and a new IRP four months later. With
19 the downturn in the economy, both firm loads and the
20 expected influx of industrial demand will surely be
21 muted, by how much we don't know - but it makes sense to
22 wait and see what differences these updates could make.
23 As pointed out above, the Hoku load may well be delayed
24 or even fail to occur.
25 Doesn't the Company say that the CommissionQ.
807 ICIP - Reading, Di 14
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1 delaying the CPCN would increase the cost of the proj ect?
2 It would for Idaho Power. Idaho Power has paidA.
3 Siemens $8.7 million to reserve the gas turbine and steam
4 turbine for the Langley Gulch self-build option. The
5 reason they paid this reserve, according to Company
6 wi tness Porter at pp 8 - 9:
7 "Due to global high demand and long
8 manufacturing lead times for gas steam turbines, in 2008
9 Idaho Power entered into reservation agreements with
10 Siemens for combustion and steam turbines to assure their
11 delivering in time to permi t completion of construction
12 and commercial operation of the plant in 2012. Idaho
13 Power and Siemens have since executed final
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1 contracts rela ting to the purchase of the equipment.
2 Idaho Power has paid Siemens a total of $8,721,701 to
3 reserve the equipment. This sum is credi table against
4 the final purchase price of the equipment. No further
5 payments on the equipment are required before September
6 1, 2009.If Idaho Power terminates the contracts, the
7 payments made to date will be largely non-refundable.
8 The contracts are, however, potentially assignable
9 subject to certain condi tions.
10 Therefore Idaho Power has a compelling reason
11 to want the CPCN to be issued by September 1, 2009. Due
12 to its down-payment on the turbine, it has an incentive
13 to select the self-build option.
14 Q. But doesn't the Company say it could
15 potentially assign the reservation of the Siemens
16 combustion and steam turbines to another party?
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812 ICIP - Reading, Di 17
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1 Has the Company made other expenditures for theQ.
2 Langley Gulch proj ect?
3 In addition to the $ 8. 7 million reservation feeA.
4 to Siemens, Idaho Power has paid non-refundable costs in
5 the amount of $3.1 million for a variety of services and
6 equipment such as air-shed modeling, water purchase
7 costs, land options, etc. (Invenergy Data Request No.
8 19). It has also paid the EPC contractor $548,529.
9 (Invenergy Data Request No. 15 J. These EPC services
10 included developing specifications, competitive bidding
11 long-lead time equipment, and starting contract
12 negotiations with potential vendors. Equipment included
13 items such as the heat recovery steam generator,
14 condenser, cooling tower, and step-up transformers.
15 Therefore, the Company has already committed over $12
16 million toward the construction of the Langley Gulch
17 plant, much of which is non-refundable, before it has
18 received a CPCN from this Commission.
19 Are you saying due to the previous financialQ.
20 commitments the Company has made for Langley Gulch, they
21 should be allowed to continue building the plant?
22 No. Economists are fond of saying "sunk costsA.
23 are sunk". This simply means 'don't spend good money
24 after bad'. The important decision is what is best for
25 the Company and ratepayers going forward from this point
813 ICIP - Reading, Di 18
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1 in time. Delaying the on-line date for the plant or
2 reopening the bidding for a resource that would fit
3 wi thin the updated IRP and economic forecast, along with
4 the greenhouse plan could, in the long run, reduce costs
5 for both shareholders and ratepayers. The unprecedented
6 changes that have occurred in the past year all call for
7 reassessment before one can be sure this is a needed and
8 least cost resource.
9 Are you recommending, should the CommissionQ.
10 rej ect the Company's request for a CPCN, or that if the
11 Company fails to obtain financing, that Idaho Power would
12 lose its investment to date and thereby penalize the
13 shareholders?
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1 Not necessarily. As pointed out above, theA.
2 most rational course of action is to look forward and not
3 be guided by what costs have been sunk to this point in
4 time. The Commission has the power to allocate these
5 sunk costs in a variety of ways among shareholders and
6 ratepayers. It would not be unreasonable for the
7 Commission to allow these costs to be shared between the
8 shareholders and ratepayers in some fashion.From a
9 ratepayer perspective, it would be better to shoulder
10 these costs rather than have a resource built that would
11 cost more in the long run.
12 Q It appears the Company has a running head start
13 relative to the other bidders; that is, unless the other
14 bidders have made similar commitments. Do you feel this
15 has given the Company an advantage other bidders do not
16 have?
17 A.I, of course, don't know what financial
18 commi tments other bidders may have made prior to bidding.
19 It is certainly not a prudent business practice for a
20 potential bidder to purchase the equipment prior to
21 knowing whether or not it would be successful.If they
22 did, a prudent business person would build an off ramp
23 from the obligation, like a right to assign or refund.
24 However, as pointed out by Idaho Power, there is a world
25 wide high demand and long manufacturing lead times for
815 ICIP - Reading, Di 19
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1 combined cycle generating equipment. The Company now has
2 already delayed the on-line date until December 2012.
3 (However, apparently the Company is now attempting to
4 move the proj ect' s on-line date back up into the summer
5 of 2012. See the Affidavit of Vernon Porter, attachment
6 No. 3 in Response to Intervenor's Joint Motion to Stay.)
7 This decision to delay the proj ect was "not made until
8 early 2009 (after project selection was made), well after
9 the RFP had been issued and the period for bid submission
10 had closed." (Idaho Power Response to Staff Data Request
11 No. 26). The other bidders were required to meet the
12 June deadline. With the extended six months, other
13 bidders may have been able to option less
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816 ICIP - Reading, Di 19a
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1 costly equipment commitments from manufacturers . Given
2 how close the bids were for both price and non-price
3 variables, pre-purchase of equipment and an extended
4 deadline may have changed the results of the prices in
5 the bidding process.
6 Idaho Power did not allow build-and-transferQ.
7 (BAT) proposals to be considered in the RFP selection
8 process. Why did the Company reject this type of
9 project?
10 The Company states the reason it did not allowA.
11 BAT bidders is:
12 "When the Company made the decision to pursue a
13 combined cycle project, Company employees visi ted a
14 number of combined cycle projects. During these si te
15 visi ts, Company employees observed significant
16 differences between similar sized projects. Simply put,
17 some designs were much better than others. If
18 build-and~transfer option was permi tted, and projects
19 wi th significant design differences were proposed, the
20 evaluation process could become extremely complicated and
21 somewhat subjective. The Company concluded that the best
22 way to eliminate significant design differences between
23 the proposals and assure an effective evaluation process
24 was to prepare and issue a detailed specification with
25 the RFP to ensure uniform design cri teria between
817 ICIP - Reading, Di 20IPC-E-09-03
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1 projects. Given the decision to accelerate the on-line
2 date to 2012, information obtained regarding cri tical
3 equipment manufacturing lead times, and the
4 aforementioned differences in project design, in the
5 Company's opinion, it did not have enough time to meet
6 the 2012 on-line date.(Bokenkamp, Di. pp 7 - 8. J
7 When asked by Staff in discovery how long it
8 would take to develop the detailed design specifications
9 that would be necessary for a build-and-transfer bid, the
10 Company stated it would be four to six months. (Idaho
11 Power Response to Staff Data Request No. 24. ) Given the
12 six month delay in the on-line date, preparing detailed
13 specifications could have been undertaken without
14 impacting the Company's currently specified on-line date.
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818 ICIP - Reading, Di 20a
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1 Q.The Company is saying a maj or reason that BAT
2 proj ects were not allowed in the bidding process is that
3 the differences in design would make the evaluation
4 process "extremely' complicated and somewhat subjective".
5 Do you see this as a compelling reason to disallow a BAT
6 proj ect from bidding?
7 A.Allowing projects to be bid as different as a
8 self-build unit, PPAs, and TAs is also an evaluation
9 process that is complicated and subjective. These varied
10 proj ects can have, for example, very different financial
11 implications for the Company (discussed below) that
12 require subj ecti ve judgments in the bidding process. The
13 proj ects are in different locations that can impact their
14 probabili ty of being permitted. They can have
15 significant non-price differences. Not allowing BAT
16 proj ects to bid narrows the field of potential proj ects
17 and may have eliminated a least cost proj ect.
18 How different is a build-and-transfer projectQ.
19 from the Company building a resource 'independently' and
20 turning the proj ect over to itself?
21 The Company claims it did not submit aA.
22 build-and-transfer proposal:
23 "Idaho Power did not submi t a
24 build-and-transfer proposaL.Idaho Power had no guarantee
25 that any proposals would be submitted in response to the
819 ICIP - Reading, Di 21
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1 RFPr or that they would be competitively priced. With
2 this in mindr and Idaho Power's need for the addi tional
3 resources r the Company prepared and submi tted the
4 Benchmark Resource as an independent bid in the RFP
5 process.(Idaho Power Response to ICIP Data Request No.
6 10. J
7 It is prudent behavior for a utility to develop
8 a Benchmark Resource when acquiring resources through a
9 bidding process in order to create a baseline to judge
10 the other projects that may be bid. However, it is
11 conceptually the same as a build-and-transfer project,
12 just that it is the Company building the unit and turning
13 it over to itself. The fact that BATs were not allowed
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820 ICIP - Reading, Di 21a
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1 skewed the number of potential bidders and may have led
2 to a potential least cost resource not being selected.
3 Q.Why does the Company say the Benchmark
4 Resource is not a build-and-transfer proj ect?
5 A.The Company' s position is that there are
6 conceptual differences between a BAT and self-build
7 project:
8 "Under a build-and-transfer approach, Idaho
9 Power would (1) most likely not have a direct contractual
10 rela tionship wi th the project engineers, construction
11 contractors, or the equipment suppliers, (2) would have
12 taken ownership of the plant only upon completion, and
13 (3) would not have been in a posi tion to have direct
14 control of the ini tial project design, as the ini tial
15 design would have been determined by the bidder -- Idaho
16 Power may be able to request design changes at a later
17 da te, likely at addi tional cost. (Idaho Power Response to
18 ICIP Data Request No.9.)
19 These points are also discussed in the
20 Company's response to Staff's Data Requests Nos. 19 and
21 20. Idaho Power goes on to say that "a utility should
22 not be required to operate a plant unless the utility
23 participates integrally in the design and construction of
24 the plant." (Idaho Power Response to Staff Data Request
25 No. 20.) I do not believe there is really a significant
821 ICIP - Reading, Di 22
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1 conceptual difference. The Benchmark team assembled the
2 Company's bid that had to meet the same requirements as
3 the other bidders independently from the evaluation team.
4 What the Company seems to be saying is either that they
5 do not trust any other party to build a proj ect or that
6 they don't feel they can properly manage a build-and-take
7 proj ect. This is a curious position considering the
8 Company has never built or operated a combined cycle unit
9 and potential bidders may have extensive experience in
10 both building and operating CCCTs.
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822 ICIP - Reading, Di 22a
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1 Q.What are your conclusions about the Company not
2 allowing BATs to be bid?
3 A.I do not believe the Company's reason for not
4 allowing BATs to be bid are valid. Their reasons were
5 that they did not have time to develop detail
6 specifications because of the need for the proj ect, yet
7 the on-line date has been delayed by six months. The
8 Company expressed concern about the complexity and
9 subj ecti vi ty of the evaluation process if BATs were
10 allowed to bid, yet a variety of different types of
11 proj ects were allowed to be bid that also require
12 significant subj ecti vi ty in assigning scores. The
13 Company's reasoning all but eliminates the possibility of
14 operating any facility they do not build themselves.
15 However, on the other hand, they do say, "The Company
16 will give careful consideration to using
17 build-and-transfer proposals in the future." (Idaho Power
18 Response to Staff Data Request No. 23.) This is reason
19 enough for the Commission to deny the CPCN and instruct
20 the Company to re-bid its resource need after the 2009
21 IRP along with the greenhouse emissions report have been
22 completed.
23 Q.The Company has filed testimony discussing
24 potential problems it may have in financing the Langley
25 Gulch plant due to the current credit crisis in the
823 ICIP - Reading, Di 23
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1 capi tal markets, the drought in six of the last seven
2 years, and higher historical capital requirements. How
3 does the Company propose to deal with these financing
4 issues facing Langley Gulch?
5 A.The Company proposes two non-traditional
6 ratemaking approaches the Commission can use. The first
7 non-tradi tional ratemaking approach is the use of
8 construction work in progress (CWIP) which is now legal
9 in Idaho and was awarded by this Commission in the recent
10 case for Hells Canyon relicensing:
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824 ICIP - Reading, Di 23a
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1 "As Ms. Smi th notes in her testimony in this
2 proceeding, current financing condi tions are extremely
3 difficul t. Issuing large amounts of equi ty a tthis time
4 is simply not prudent. The authorization of CWIP for
5 this project would provide a strong signal of regulatory
6 support for capi tal projects to the financial communi ty
7 and provide increased cash flow throughout the
8 construction of the projects, thus decreasing the need
9 for equity issuances. (Gale, Di. p.12)
10 The second non-traditional ratemaking approach
11 is to use the recently passed Senate Bill 1123,
12 referenced above, that adds ratemaking certainty and thus
13 may help convince lenders to finance the proj ect. Again
14 quoting Mr. Gale:
15 "Q. Turning to the second regula tory
16 alternative described earlier. How would the inclusion
17 of specific ratemaking determinations in the CPCN order
18 be helpful in financing the Project?
19 A. A Commission order that adds certainty to
20 ratemaking treatment the Company could expect to receive
21 if it proceeds wi th the Langley Gulch Power Plant would,
22 in the Company's opinion, enhance its abili ty to obtain
23 financing.This type of ratemaking commitment is
24 currently being discussed in the Idaho Legislature in
25 Senate Bill 1123. (Gale, 01. p.8.)
825 ICIP - Reading, Di 24
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1 Q.Mr. Gale referenced Ms. Smith's direct
2 testimony in this proceeding. What did she say about the
3 Company's ability to finance Langley Gulch?
4 A.Ms. Smith's direct testimony focuses on the
5 current difficulties in the capital markets and the
6 impact of increased borrowing and debt on the Company for
7 the Langley Gulch proj ect. She echo's Mr. Gale's
8 testimony and states:
9 "Q. What is the impact of inadequate cash
10 flows?
11
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826 ICIP - Reading, Di 24a
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1 A.Inadequate cash flows cause credit rating
2 agencies to be concerned. The credi t ra ting communi ty
3 uses cash flow and other financial ra tios wi th more
4 subjective evaluations, such as perceived regulatory
5 support, to assess the financial heal th and prospects for
6 a utili ty. If changes in such measures exceed a ra ting
7 agency's thresholds, such changes can affect bond
8 ra tings. Bond ra tings, in turn, directly affect both the
9 cost and the availabili ty of debt, which are both
10 important components in determining the utili ty cost of
11 capital. (Smith, 01. pp. 5 - 6. J
12 Gi ven the meltdown in the capital markets and
13 the general state of the economy, the Company's concerns
14 about borrowing funds for Langley Gulch are legitimate
15 and financing problems could stall the proj ect.
16 Q.What does the Company say about its ultimate
17 abili ty to build the proj ect given today' s economic
18 crisis?
19 A.In Mr. Gale's last Q&A of his direct testimony
20 he states:
21 "Q. Can Idaho Power assure this Commission that
22 if the Commission authorizes either of the alternatives
23 requested, that the Company has the ability to finance
24 the Project?
25 A. No it cannot. Providing the regula tory
827 ICIP - Reading, Di 25
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1 assurances would give Idaho Power a better chance to
2 obtain financing, but in today's environment, we simply
3 do not know if it can be done. The Company will be
4 reviewing its financing alternatives for the Project
5 throughout this spring and, if necessary, may supplement
6 or amend this request based on its findings". (Gale, Di.
7 p. 12.)
8 Q.If. the Company cannot finance the Proj ect, or
9 if the Commission did not issue the CPCN, do you know
10 what plans the Company has to meet its loads?
11 A.In response to discovery on this issue the
12 Company stated:
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828 ICIP - Reading, Di 25a
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1 "If financing for the Langley Gulch project
2 cannot be obtained ei ther wi th or wi thout the Company's
3 proposed ratemaking treatments, the Company would have to
4 assess how it would proceed to add a new baseload
5 resource.In the interim, until such resource could be
6 added, the Company would attempt to meet its most
7 cri tical summertime loads through a combina tion of the
8 following: (1) short-tem demand management programs, (2)
9 market purchases delivered to the east side of Idaho
10 Power's system, (3) market purchases delivered at Mona or
11 Red Butte (both in Utah) and delivered to Idaho Power's
12 system via Idaho Power's firm transmission rights from
13 Red Butte to Boarh/Brady, (4) reductions in deliveries to
14 Hoku during the summer of 2012, or (5) purchases
15 delivered to Jim Bridger for loss repayment. Market
16 purchases from othe Pacific Northwest are also a
17 possibili ty when transmission is not constrained; PPAs
18 from generation resources are another possibility. (Idaho
19 Power Response to ICIP Data Request NO.2. J
20 Among the possible sources of power the Company
21 could pursue are various forms of purchase agreements.
*************BEGINNING OF CONFIDENTIAL*****************
829 ICIP - Reading, Di 26
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830 ICIP - Reading, Di 27
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1 Q.How did the RFP evaluation team consider
2 different proj ects' effect on the Company's ability to
3 finance the Langley Gulch proj ect?
4 A.The selection process did not differentiate
5 between the self-build proj ect and either PPAs or TAs.
6 Proj ect evaluations assumed the self-build proj ect would
7 be financed and the consequences on the Company's
8 financial position from different types of proj ects was
9 not part of the scoring and selection of the winning bid.
10 As the Company stated:
11 " (T) he RFP team did not assign a dollar amount
12 to ei ther case flow or imputed debt tha t would impact the
13 Company's financial ra tings.The RFP team worked under
14 the assumption tha t Idaho Power was capable of financing
15 the project and meeting the associated case flow
16 requiremen ts. (Idaho Power Response to ICIP Data Request
17 NO.6. )
18 It is incongruous that the Company would stress
19 the need for the Commission to issue its CPCN under
20 non-traditional ratemaking methods in order to finance
21 the proj ect and yet not to have considered financial
22 implications in the scoring and selection process. This
23 is especially true when the financing methods are so
24 different between a self-build project and either a PPA
25 or a TA.
831 ICIP - Reading, Di 28
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1 Q.Ms. Smith's testimony discusses the impact on
2 the Company's financial situation from imputed debt
3 should the Company enter into either a PPA or a TA. Do
4 you agree with her statements?
5 A.Only partly. I believe Ms. Smith overstates
6 the impact of imputed debt on the Company's financial
7 si tuation and the impact on its credit ratings. In
8 response to the question:
9 "In the event the Commission selected a
10 different alternative to the Project, do credit rating
11 agencies view credi t risk for purchase power agreements
12 or tolling agreements differently than a plant buil t by a
13 utili ty?
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832 ICIP - Reading, Di 28a
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1 Her answer was:
2 "No. When a company decides to buy genera tion
3 thru a long-term purchase agreement or a tolling
4 arrangement there is a risk transfer from the seller of
5 the energy to the buyer of the energy and its customers
6 and shareholders in the form of imputed debt. Imputed
7 debt is a measure of financial risk shifted to a utili ty
8 when it enters into a purchase power agreement ("PPA") or
9 tolling agreement ("TA").
10 The implication of her answer is that imputed
11 debt and the Company's debt are equivalent. To the
12 extent they are both debt, her statements are true.
13 However, when it comes to imputed debt, all debt is not
14 created equally in the eyes of rating agencies. Todd
15 Shipman of Standard & Poors described how his rating
16 agency considered the meaning of imputed debt:
17 "And then the final-the point I'd like to make
18 on purchase power adjustments is that they're often or
19 sometimes referred to as being a debt equivalent or
20 something like that. And we certainly don't see it that
21 way. All of the adjustments that we make to bring
22 something onto the balance sheet because we view it as
23 being a debt-like obligation is recognized by our
24 analysts and by the rating committees as being-that
25 adjustment is not the same thing as the actual debt that
833 ICIP - Reading, Di 29
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1 companies have and tha t they need to payoff over time,
2 hopefully. And so the real impact of the adjustment on
3 the credi t ra tings of utili ties can very by utili ty and
4 by the jurisdiction that they're in and it encompasses a
5 whole-the credi t analysis encompasses a whole lot more
6 than just throwing $500 million onto their balance sheet
7 as debt equivalent or something like tha t.
8 The overall impact of a utili ty' s and the
9 regulatory commission that regulates them-their policies
10 and their conduct of the competi tive procurement process
11 among other things-all will get factored into the rating.
12 And the true impact is a whole lot more than just a
13 simple mathematical exercise in coming up with some sore
14 of debt-like obligation that we put onto the
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834 ICIP - Reading, Di 29a
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1 balance sheet. (July 18,2007 NARUC FERC Competitive
2 Procurement Dialogue Meeting, Panel 2: 'Supply Financing
3 Procurement Perspectives. Transcribed from podcast at
4 hrcp://naaru.ore;ferc/7 18 2007podcast/default.html,
5 excerpt below from pages 20-21, Todd Shipman, Director,
6 Utili ties and Infrastructure Group, Standard and Poors. J
7 It is clear the rating agencies do not consider
8 the debt from utili ties' borrowings and imputed debt
9 equally.
10 How do the credit rating agencies treat imputedQ.
11 debt and utilities borrowings differently?
12 The EEl white paper, at page 12, by the BrattleA.
13 Group attached to Ms . Smith's testimony-states-:-
14 "Under current FASB standards, these
15 obligations are not reported on the company's balance
16 sheet al though the accompanying notes do disclose these
17 arrangements. However, these contracts have debt-like
18 characteristics because they commi t the utili ty to pay
19 periodically a fixed amount to an outside party. Because
20 these obliga tions have fea tures similar to debt, they are
21 treated as such to some degree by the credit rating
22 agencies. S&P has developed and publicized a standard
23 procedure for calculating the amount of imputed debt
24 resul ting from signing a long-term PPA contract and for
25 determining its impact on a utili ty' s credi tworthiness.
835 ICIP - Reading, Di 30
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1 Other credi t ra ting agencies, such as Moody r s or Fi tch
2 Ratings, have been less forthcoming in how they evaluate
3 the effect of a long-term PPA contract on a utili ty r s
4 credit rating.
5 Note the quote states that imputed debt has
6 'debt-like characteristics'not that it is the same
7 as debt. The Brattle Group White Paper goes on to
8 discuss mitigating factors that regulatory agencies can
9 use to reduce or eliminate the financial risk to a
10 utility from a rating agency's calculation of imputed
11 debt.
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836 ICIP - Reading, Di 30a
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1 Q.Please provide an example of the type of
2 mi tigation regulatory authorities could undertake to
3 lessen the financial risk of imputed debt.
4 One of the most important is the certainty thatA.
5 the utility will be able to recover payments to the PPA
6 or TA through rates. The Brattle Group Report provides
7 at page 25:
8 "The overall goals of mi tiga ting the nega ti ve
9 effects of imputed debt should be to insure tha t
10 investors, bondholders and equity holders are treated
11 fairly, while at the same time ensuring that the
12 utili ty' s customers are not overcharged. Al though these
13 goals are not controversial, the implementation of
14 mechanisms tha t achieve them requires balancing the needs
15 of investors and customers.
16 On method by which regulators can reduce the
17 amount of imputed debt that results from a PPA is by
18 adopting automatic cost recovery options that may
19 influence S&P (and perhaps the other credit rating
20 agencies) to reduce the risk factor assigned to a
21 utility.
22 I am sure the Brattle White Paper's reference
23 to an automatic cost recovery option is describing
24 something like Idaho Power's Power Cost Adjustment (PCA)
25 which automatically allows the Company to recovery 95% of
837 ICIP - Reading, Di 31
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1 the cost of any power purchase or tolling agreement
2 through rates on an annual basis. This factor alone,
3 will reduce financial risk to Idaho Power and will help
4 assure the rating agencies of cost recovery by the
5 Company.
6 Q.You have described the potential financing
7 problems described in Ms. Smith's testimony and the
8 statements of Mr. Gale that the Company can not guarantee
9 financing its self-build proj ect. How do you reconcile
10 the fact that the Company's RFP team did not consider the
11 important issues of cash flow and imputed debt in scoring
12 the bids?
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838 ICIP - Reading, Di 31a
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1 A.I cannot square the importance of the impact on
2 the Company's finances with a project of this magnitude
3 and the fact that it had no impact on the scoring of the
4 bids. The Company's RFP scoring team simply proceeded
5 "under the assumption that Idaho Power was capable of
6 financing the proj ect and meeting the associated cash
7 flow requirement" while the testimony of Ms. Smith and
8 Mr. Gale indicate that is simply not the fact. As
9 discussed above, the impact on the Company's financial
10 structure is quite different for borrowing for a
11 self-build project and the debt implications from a power
12 purchase or tolling agreement. As shown above, the
13 closeness of the scores indicate differing financial
14 impacts on the Company may well have changed the winning
15 bid.
16 Q.Idaho Power shareholders, at their most recent
17 annual meeting, passed a resolution directing the Company
18 to develop a plan for reducing greenhouse emissions --how
19 do you see that vote affecting the construction of
20 Langley Gulch?
21 A.Idaho Power shareholders passed, over the
22 obj ections of IDACORP management, an advisory resolution
23 directing the Company to develop a future resource
24 portfolio that would reduce its greenhouse emissions.
25 The Company's management has agreed to be bound by the
839 ICIP - Reading, Di 32
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1 resolution and have a report prepared for the
2 shareholders by September 30 of this year. Idaho Power
3 CEO, LaMont Keen is quoted in the IDACORP transcript of
4 its annual meeting as having said, "The Company takes
5 this vote, an expression of shareowner interest
6 seriously and will consider adopting carbon ini tiati ve
7 disclosure and/or goals this year." Granting a CPCN now,
8 before the Company has developed its greenhouse strategy,
9 is premature and possibly a costly mistake that may well
10 conflict with the Company's announced plans to reduce
11 greenhouse emissions. How the greenhouse emission plan
12 will fit with the Company's 2009 IRP that is due to be
13 filed with the Commission by the end of the year is also
14 unknown. Until the IRP
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840 ICIP - Reading, Di 32a
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1 is developed with the greenhouse strategy incorporated,
2 any new significant resource additions should be delayed.
3 Q.Dr. Reading, what recommendations do you have
4 for the Commission?
5 A.I recommend denial of the CPCN. Idaho Power
6 should re-examine the need for a new generating resource
7 after the 2009 IRP is updated with a current load
8 forecast. Then it can determine, if a new resources is
9 needed and if so what kind of a new resource is needed.
10 If one is needed a new RFP should be issued with
11 competitive bidding guidelines from the Commission on the
12 procedure the RFP should follow. Those guidelines should
13 include a truly independent evaluator who should be
14 invol ved in the process from start to finish. The new
15 RFP should allow a build and transfer option and scoring
16 should include the potential financial impact of each
17 option on the Company's financial structure and credit
18 rating.
19 Q.Does this complete your direct testimony as of
20 June 19, 2009?
21 A.Yes, it does.
22
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841 ICIP - Reading, Di 33
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2 open hearing.)
(The following proceedings were had in
MR. RICHARDSON: Thank you, Mr. Chairman.
4 Dr. Reading is available for cross-examination.
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7 cross.
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COMMISSIONER KEMPTON: Ms. Ackerman.
MS. ACKERMAN: Your Honor, I have no
COMMISSIONER KEMPTON: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Purdy.
MR. PURDY: I have none.
COMMISSIONER KEMPTON: Mr. Miller.
MR. MILLER: No questions.
COMMISSIONER KEMPTON: Ms. Bridge.
MS. BRIDGE: No questions.
COMMISSIONER KEMPTON: Mr. Woodbury.
MR. WOODBURY: Thank you, Mr. Chairman,
18 just a few questions for Mr. Reading.
19
20
21
22 BY MR. WOODBURY:
23 Q
CROSS-EXAMINATION
This is your testimony for the Industrial
24 Customers; correct?
25 A This is for the Industrial Customers,
CSB REPORTING
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842 READING (X)
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1 yes.
2 Q And this group, the Industrial Customers
3 of Idaho Power, doesn't represent the entire class but a
4 small subset of industrial customers?
5 Wow, I would have to look. By numbers, itA
6 would be a small subset. I i m not sure I could answer
7 that as far as
8 Q Well, in response to a production request
9 from Idaho Power indicated that the customer group
10 consisted of eight customers: Ashgrove Cement,
11 Amalgamated Sugar, Basic American Foods, Hewlett-Packard,
12 the Crookham Company, J. R. Simplot, Lamb Weston or
13
14
ConAgra, and CTI Foods. Do you believe it consists of
any more than that?
15 A No.
16 Q Would you agree that Idaho Power probably
17 has more industrial customers than that number?
18 Significantly more. As I said, I wouldA
19 have to, I would have to inquire on what their loads
20 were. Certainly, they are among the largest industrial
21 customers, so as a percent of either peak or energy
22 demand, they would be significantly larger than eight
23 versus the total number in the class.
24 Who in this case among the parties has theQ
25 duty and obligation to serve electric?
CSB REPORTING
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1 A I'm not sure I --
2 Q It's Idaho Power, isn't it? Of all the
3 parties to the case, Idaho Power is the only one with the
4 duty and obligation to serve?
5 A Yes, yes.
6 Q And who engages in the planning to ensure
7 its continued ability to serve?
8 A The Company engages in the planning with
9 the approval of the Commission in dockets like this.
10 Q And what are the expectations of this
11 industrial customer grouping with respect to Idaho
12 Power's obligations to meet their energy requirements?
13 A The customers certainly need the power to
14 produce their product.
15 Q And are any of your customers willing to
16 accept interruption or curtailment of load?
A They just filed the EnerNOC, I'm trying to
18 remember what the docket is, but the Company came up with
19 a demand reduction program, I'm sorry, I can't remember
20 the correct acronyms, and is negotiating with the
21 industrial class customers for curtailment of load in
22 return for capacity and energy payments if they're
23 interrupted.
24
25
Q Do you believe that the interests of your
subset of industrial customers as represented in your
CSB REPORTING
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844 READING (X)
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1 testimony are perhaps representative, also, of the entire
2 industrial class?
3 A The names that you read, I think they're a
4 relati vely -- I mean, they're spread out, but as I
5 mentioned earlier, they tend to be the bigger
6 customers.
7 Q If Idaho Power has determined that it
8 needs an energy resource in 2012, Langley Gulch, which is
9 a baseload resource, is it in the interests of those
10 customers -- oh, what do you believe the consequences are
11 of delay cost-wise with respect to contracts and
12 permi tting and perhaps equipment?
13
14
A To the Company? I would have to look at
the production request. I think I used the 23 million if
15 they missed the September 1st date. I haven't calculated
16 the whole spread, but to the Company there would be cost
17 consequences and in my testimony, as I recall, I had a
18 question in there about okay, there would be significant
19 costs for delays. I guess it's fair, we all know the
20 game, so I asked myself the question, do you think that
21 should be stuck with the Company and my answer was not
22 necessarily. There could be some sharing, and it was off
23 the top of the discussion I had on sunk costs. Looking
24 at this from an economist's perspective, the most
25 important thing is we are where we are. The Company has
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1 incurred the costs they've incurred, what's the best path
2 forward.
3 Q And I think that sharing proposal was made
4 also in the oral argument for stay and I think it was
5 represented there that there should be a sharing between,
6 there should be a sharing between shareholders and
7 customers.
8 A I was not at the hearing, but
9 Mr. Richardson told me he said that.
10 Q But there's additional risk to that of
11 just increased costs and that would be the Company's
12 inability to meet the load requirements based upon other
13 factors such as inability to bring in power from the
14 Pacific Northwest on transmission lines if they only have
15 non-firm rights to those lines.
16 A There are certainly cost consequences.
17 There could also be cost savings and when I say "cost
18 savings," I'm talking about cost savings to the customer.
19 In Mr. Bokenkamp' s cross-examination in his Exhibit 10,
20 they weren't running the peakers and there was a
21 discussion on the energy that they would supply. That
22 doesn't include the capital costs that the customers,
23 ratepayers, are going to incur should Langley Gulch go
24 forward.
25 Q Do the industrial customers believe that
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1 the Company should be running its peakers full time at 92
2 percent?
3 A It would depend on the cost-benefits, what
4 the loads are, et cetera. The customers don't run the
5 Company. We're just saying that there is options
6 available to the Company and that in the long run, as I
7 explained in my testimony, in the long run, the more cost
8 effective a better option would be to delay the plant
9 and rebid it.
10 Q If we get to December 31st, the Company
11 files its 2009 integrated resource plan, it still appears
12 that there's a resource need in 2012, June, isn't the end
13 resul t of that is higher cost that will be spread and
14 your customers, I guess, are willing to accept that
15 risk?
16 A Yes.
17 MR. WOODBURY: Okay. Mr. Chairman, no
18 further cross.
19 COMMISSIONER KEMPTON: Commissioner
20 Redford.
21 COMMISSIONER REDFORD: You said that
22 COMMISSIONER KEMPTON: Wait, just a
23 second.
24 MR. KLINE: I do have a few questions for
25 Dr. Reading.
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1 COMMISSIONER REDFORD: Oh, excuse me, I'm
2 sorry.
3
4 CROSS-EXAMINATION
5
6 BY MR. KLINE:
7 Q Dr. Reading, first of all, I need to say
8 that I am going to ask you to refer to a couple of Staff
9 exhibi ts that have been identified as confidential
10 exhibits and that would be Exhibits 113 and 114. Do you
11 have those with you?
12
13
14
20
A No, I do not.
MR. KLINE: Okay, could your counsel
supply those to you?
15 MR. RICHARDSON: Which exhibits?
16 MR. WOODBURY: 113 and 114.
17 Q BY MR. KLINE: And I'm going to try and do
18 the cross-examination in a way that won't require us to
19 clear the room, so I think I can limi t it that way.
A I understand and jump up and wave if I
21 cross some lines somewhere in an answer.
22 MR. RICHARDSON: May I approach the
23 witness?
24
25
COMMISSIONER KEMPTON: Yes.
(Mr. Richardson approached the witness.)
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1 Q BY MR. KLINE: Now, I'm going to ask a few
2 other questions first, Dr. Reading.
3 A Okay.
4 Q On page 7 of your testimony, you discuss
5 the Hoku load.
6 A Yes.
7 Q And I think you imply there that the Hoku
8 load may not materialize; is that a fair characterization
9 of your testimony?
A Yes, and I rely on what was discussed
11 yesterday about Hoku and the potential financing
12 problems.
13
20
Q Yeah, and you're aware -- I'm sorry, I
14 didn't mean to talk over you.
15 A The potential financing problems. I was
16 stuttering, I'm sorry.
17 Q And you're aware that Idaho Power has a
18 contract with Hoku?
19 A Yes.
Q And have you read that contract?
21 A No, I have not.
22 Q Okay.
23 A I have read some of the press releases and
24 testimony dealing with it, but I have not read the
25 contract.
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1 Q Okay. In this part of your testimony,
2 Dr. Reading, you're not suggesting that in planning
3 resources the Company should ignore the contracts that
4 it's signed with its industrial customers, are you?
5 A No.
6 Q But in this case you think that the
7 Company should ignore the contract that it signed with
8 Hoku?
9 A No. What I was saying was, and again
10 relying on the testimony that occurred yesterday, that
11 given the current economic conditions, given the
12 financing conditions that the world has changed
13 economically and financially, not only for Idaho Power in
14 an attempt to finance a plant, but also other industries
15 and so there needs to be a serious look at the whole
16 picture given the significant change that has occurred.
17 Q But put yourself in the shoes of the Idaho
18 Power resource planning folks. Should they -- there's
19 lots of talk in the newspaper about Micron perhaps not
20 survi ving. Should the planners in putting together their
21 plans make the assumption that maybe Micron won't be here
22 so we don't need to get resources to cover that load?
23 A I will repeat the same for Hoku, it's part
24 of the whole process. Certainly, if they have a load, if
25 there's indication the load mayor may not be there, you
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1 need to look at that load and assign some probability of
2 whether you think it mayor may not be there to put in
3 with all the other assumptions you make in a load
4 forecast.
5 Q And that's a discretionary call the
6 Company should make about the contracts that it has with
7 its customers when it's doing resource planning?
8 A Yes, and then in the IRP process we all
9 get to look at what those assumptions are and before this
10 Commission kibitz on whether we believe those are valid
11 or invalid assumptions.
12 Q All right, I'd like to take a look at page
13 19 of your testimony, if you would, please, turn to
14 there, and I'm specifically referring to your testimony
15 on page 19, the Q&A that starts, "It appears the Company
16 has a running start," and in that answer to your -- to
17 that question, you discuss the Company's decision to take
18 steps to acquire key pieces of generation equipment so
19 that it would have it available if it needed it to meet a
20 2012 resource need. In the discussions that we've had
21 today, you probably have heard that -- I'll ask you if
22 you agree with this time line: All bidders submitted
23 their bids based on the Company's stated need for a
24 resource like Langley Gulch to be available in June 2012;
25 is that correct?
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1 A Yes.
2 Q All right, and then in the fall of 2008,
3 we had the credit freeze and the economic meltdown and
4 the TARP and a lot of those kinds of things; is that
5 correct?
6 A Yes.
7 Q All right, and then in the spring of 2008
8 the Company filed its application for a CPCN and asked
9 for a delay in the on-line date.
10 A Yes.
11 Q Now, as I read your testimony on page 19,
12 it -- particularly and I'll be specific, lines 19 through
13 23, why don't you take a look at those.
14 A Okay.
15 Q Kind of going on to the next page, it
16 sounds to me like in this part of your testimony you're
17 saying that if back in the spring of 2008 when all the
18 bidders were getting together to submit their bids, if
19 they had known that in the spring of 2009 Idaho Power was
20 going to move the on-line date six months to the year-end
21 2012 that they might have submitted lower bids. Is that
22 your testimony?
23 A They may have changed their bids and I was
24 here when I think Mr. Bokenkamp testified that those
25 bidders had been contacted and told the Company that
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1 their bids would not change. That was information I did
2 not have when I wrote this testimony.
3 Q Well, and that's fine, but I'm just trying
4 to get a sense of what you were trying to portray there.
5 On line 23, let me just
6 A Sure.
7 Q -- read the sentence to you. "With the
8 extended six months, other bidders may have been able to
9 option less costly equipment commitments from
10 manufacturers. " Isn't that really kind of the perfect
11 example of 20-20 hindsight? I mean, you're sitting here
12 today saying well, if they had known in 2008 what
13 actually occurred in 2009, they might have done something
14 differently.
15 A Yes, what I was referring to was the fact
16 that all kinds of equipment prices have come down. They
17 may have been able to refresh their bids, I don't know,
18 but I would have to agree with you when they made the bid
19 the meltdown had not occurred.
20 Q And in fact, based on what they knew then,
21 they were seeing commodity prices going up, they were
22 seeing tight markets for all kinds of equipment. In
23 fact, if they had known it was going to be six months
24 later, they might have even had to put in higher bids,
25 mightn't they?
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1 A Maybe, maybe not, but I agree with
2 you that wi th your time representation I agree with
3 you.
4 Q Now, I'd like to refer you to page 27 and
5 28 of your testimony.
6 A Twenty-seven is yellow.
7 Q It is. Again, I think I can ask this in a
8 way that we won't have any problems with confidentiality.
9 A Okay.
10 Q In this section on page 27 and 28, you're
11 talking about the assessment that you think the Company
12 should have made with respect to the cost of financing
13 its proj ect versus the cost of a tolling agreement or a
14 power purchase agreement; is that correct?
15 A That is correct.
16 Q All right. Now, I'd like you to take a
17 look at those two Staff exhibits that I had you bring up
18 to the witness table with you and I'll direct your
19 attention to the top of Exhibit 113 --
20 A Okay.
21 Q and it's the section where they're
22 talking about the 20-year revenue requirement, net
23 present value, millions of dollars, and just looking at
24 those two lines, isn't it true that based on the net
25 present value analysis which would take into
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1 consideration costs of financing of both the Company and
2 the developer that it shows that that 20-year revenue
3 requirement difference means it's less expensive by $ 95
4 million for the Company to acquire the resource, the
5 Benchmark resource, versus bidder B?
6 A That's what that says, yes.
7 Q All right, and what that $95 million
8 represents, does it not, is that is a lower cost to Idaho
9 Power customers from buying the Benchmark resource as
10 compared to buying the power from the second place
11 bidder; isn't that what that $95 million shows?
12 A To the extent the net present value is
13 correct, yes, and that 95 million is spread out over the
14 20-year period. It doesn't impact ratepayers today 95
15 million.
16 Q Right, but over the life of the project it
17 would?
18 A Yes.
19 Q And as an economist, isn't the comparison
20 that the Company did there, the net present value over
21 the 20-year period, probably well, not probably.
22 Isn't that a very common way to compare two, in this
23 case, resources or cost streams over a long period of
24 time?
25 A It is a tool in the economist's kit that
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1 we use along with many others.
2 Q Do you think any of your customers would
3 say that that compare -- I'm sorry, any of your clients
4 in this proceeding, industrial customer clients, would
5 say that that kind of a comparison was unfair?
6 A Gi ven the context of my testimony and what
7 I view as the bidding process, what we have heard in this
8 Hearing Room about the scoring, I would say that
9 potentially a rebidding process where all of the bidders
10 knew all of the rules on how it was going to be evaluated
11 and discounted and I would go, I think, primarily to
12 Commissioner Redford's questions on the bidding, I'm
13 saying that it's very possible that it would be a better
14 deal for the customers, the industrial customers along
15 with everybody else, to rebid it.
16 Q Well, I must have not done a very good job
17 of asking the question. Let me rephrase it. When you're
18 comparing two net present value amounts and one of
19 those -- and sticking just to the net present value
20 analysis, that simple comparison, do you believe any of
21 your clients would say that simple comparìson is somehow
22 an unfair economic analysis, that it i S a poor economic
23 analysis, it's a unique economic analysis?
24
25
A Methodologically, I would agree with you.
Net present value is based on the revenue streams of the
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1 two, who have we got here, D & B and what I'm saying is
2 an equitable bidding process may well have produced
3 different streams of revenue that we were going to
4 discount over different periods of time which would have
5 then made this invalid. I mean, net present value, it's
6 a mechanical process. You know, we can fight over what
7 the discount rate is, but once you're given revenue
8 stream "A" over in this one case the 35-year hangover
9 where the 95 comes from and another revenue stream and
10 you pick your interest rate, that's mechanical. What I'm
11 saying is I'm not convinced that those two streams are in
12 the best interests of the customers.
13 Q But the stream from bidder B was prepared
14 and presented by bidder B, was it not?
15 A Yes, under what it understood was what it
16 was being asked to supply.
17 MR. KLINE: Okay. That's all the
18 questions I have for Dr. Reading.
19 COMMISSIONER KEMPTON: Commissioner
20 Redford.
21 COMMISSIONER REDFORD: I have no
22 questions.
23 COMMISSIONER KEMPTON: Commissioner Smith.
24
25
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2
EXAMINATION
3 BY COMMISSIONER SMITH:
4 Q Dr. Reading, I mean, you did a stint here
5 at the Commission, didn't you?
6 A Say it again.
You did a stint here at the Commission?
8 You were employed here?
11
12
13
14
15
16
17
20
7 Q
I'm sorry, yes, Commissioner, same time
You came a little before I did, didn't
Yes, and did I stay longer? I can't
I'm not sure.
I was employed at the Commission beginning
22 hearings and case.
18
A
Q
served?
A
you were.
Q
you?
A
remember.
Q
A
in 1981.
Q
I was employed at Idaho State University.
24 I was teaching at Idaho State and came over and testified
19
23 A
25 in the Pioneer hearing for Al Fothergill's consumer
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1 group.
2 Q Oh, excellent. Well, you were here
3 yesterday when I asked Mr. Gale whether this reminded him
4 of Pioneer and he said no, it was more like Valmy, so
5 what would be your take on that?
6 A When I saw that the Company had
7 pre-purchased the agreement -- pre-purchased the
8 equipment significantly before the bids were submitted
9 and had got a certificate from the Commission, I thought
10 gosh, I will be -- I guess I'll be honest, didn't they
11 learn anything in Pioneer was my immediate reaction.
12 Q Well, knowing how you like to opine to
13 Commissioners
14 A Yes.
15 Q I would give you that opportunity. As
16 I see it, this is a hard case.
17 A This is avery, very hard case for you
18 Commissioners.
19 Q Because I can see very clearly the
20 reliabili ty needs of this given our transmission
21 constraints, our summer peak and our winter peak, and the
22 new mandatory reliability criteria that carries
23 significant financial penalties and I think non-firm
24 transmission is not a real good way to serve firm load,
25 so I can see that very clearly. Load growth is hard.
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1 You know, we tanked a lot deeper than anyone thought we
2 would. It's anyone's guess how fast the recovery will
3 be--
4 A Right.
5 Q -- and whether you'll get new large loads
6 moving in, so if you have any suggestions for how the
7 Commission needs to balance all this , given that I think
8 if your decision is to delay, the ratepayers are still
9 going to be on the hook for a significant amount of money
10 one way or the other, so all of that is kind of just
11 tossing around.
12 A Thank you for the opportunity to opine.
13 First, I would agree with you that this for -- in my
14 mind, this for the Commissioners is the hardest decision
15 I've seen in a long time, and Mr. Mace's testimony,
16 nobody saw what was coming, so this is a very tough case.
17 In my opinion, and it's what I say in my testimony, I
18 think looking at the risks that a delay to see what the
19 information, what a real -- which an IRP which
20 incorporates what has happened to me is a smarter path
21 even though it's going to be costly no matter what you
22 select and it is, I would agree with you, there is
23 uncertainty on what those costs were. I know
24 Mr. Sterling's testimony looks at it as very
25 asymmetrical. I don't look at it as asymetrical as
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1 Mr. Sterling and that's why I recommended the delay.
2 COMMISSIONER SMITH: Okay.
3
4 EXAMINATION
5
6 BY COMMISSIONER KEMPTON:
7 Q Dr. Reading, just a couple of quick
8 questions as long as Valmy has been brought up. It's not
9 strictly germane to this other than in terms of talking
10 about uncertainty. I wasn't here, but in the course of
11 being a new guy, I've done a lot of back reading and that
12 happens to be one of them and so when the Commission made
13 its decision in that case to disallow the contractual
14 provisions that had been established in Valmy going
15 forward, the Commission in doing their risk analysis of
16 their options at the time elected to provide Idaho Power
17 Company about a million bucks, I think, back; is that
18 roughly correct?
19 A As I remember.
20 Q And that case was appealed and then in the
21 process of the court's determination on that, I think
22 Idaho Power came out on the high side of that with about
23 50 million; is that correct?
24 A As near as I remember, yes.
25 Q Which goes to show that risk assessments
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1 and decisions on load growth and how to work wi thin those
2 and predictions in the future is a risky business at best
3 and that in risk decision analysis that it isn't just
4 about cost, but it's also about the timing where
5 generation acquisitions may have to come on-line to serve
6 load that's out there in the haze and some of the haze
7 that we see right now is the drop out of the hydro system
8 because of the biological opinion. There's a possibility
9 of baseload requirements for wind power. There's the
10 issue of non-firm transmission requirements and the
11 penal ties associated with that if you continue to push
12 the line on them, so in those circumstances, going back
13 to a question that has been asked and that is, isn't
14 there a basis of good reason that goes beyond just simply
15 the cost of the project?
16 A Certainly, and I would say it's on both
17 sides and part of the balancing that I did to make my
18 recommendation is the severity of the economic downturn,
19 that I don't see the economy turning around that rapidly.
20 I don't see a real land rush for large industrial loads;
21 otherwise, those are the factors on the other side of
22 those that you brought in that said let's wait and I'll
23 harken back to a question I can't remember, Commissioner,
24 that you asked one of the Idaho Power witnesses and that
25 basically was wouldn't it be better to have better
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1 information six months down the road, and so those were
2 the kinds of factors that I weighed in this where I came
3 up with the recommendation that I thought delaying and
4 rebidding in a bidding process I would consider better
5 may yield a resource in the long run that will be better
6 both for the Company and the customers.
7 COMMISSIONER KEMPTON: Thank you.
8 Redirect.
9 MR. RI CHARDSON : Than k you, Mr. Cha i rman,
10 just one quick one.
11
12 REDIRECT EXAMINATION
13
14 BY MR. RICHARDSON:
15 Q Dr. Reading, are you recommending to your
16 industrial customer clients that they sign up and
17 participate in the EnerNOC demand reduction program?
18 A I certainly am.
19 MR. RICHARDSON: That's all I have,
20 Mr. Chairman. Thank you.
21 COMMISSIONER KEMPTON: If there is no
22 obj ection, the witness may step down.
23 (The witness left the stand.)
24 MR. ACKERMAN: Mr. President?
25 COMMISSIONER KEMPTON: I'm sorry?
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1 MS. ACKERMAN: I'm trying to say that
2 Dr. Reading is also testifying on behalf of the Northwest
3 & Intermountain Power Producers Coalition; so he has a
4 second piece of testimony.
5 COMMISSIONER KEMPTON: Step right back up
6 there.
7 MS. ACKERMAN: He could be considered
8 still under oath.
9 COMMISSIONER KEMPTON: Right, you're still
10 under oath.
11
12
13
DON READING,
produced as a witness at the instance of the Northwest &
14 Intermountain Power Producers Coalition, having been
15 previously duly sworn, resumed the stand and was further
16 examined and testified as follows:
17
18 COMMISSIONER KEMPTON: Thank you,
19 Ms. Ackerman, go ahead.
20
21 DIRECT EXAMINATION
22
23 BY MS. ACKERMAN:
24 Q Good afternoon, Dr. Reading.
25 A Good afternoon.
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864 READING (Di)
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1 Q You've been testifying on behalf of the
2 Industrial Customers in this proceeding, so let me ask
3 you, are you the same Dr. Don Reading that filed direct
4 testimony and Exhibit Nos. 701 through 703 on behalf of
5 the Northwest & Intermountain Power Producers Coalition
6 on June 19th, 2009?
7 A Yes, separate client, different
8 testimony.
9 Q Okay, and was that testimony and were
10 those exhibits prepared by you or under your direction
11 and control?
12 A Yes, it was.
13 Do you have any corrections to thatQ
14 testimony?
15 A Yes, I do.
16 Q Could you begin?
17 Okay, beginning on page 6, the lastA
18 sentence, lines 23 and 24, on line 23, strike "has not"
19 and substitute between "sought a" insert "but did not
20 receive." I'll read the whole sentence as corrected.
21 "However, the Company sought, but did not receive, a
22 wai ver from Oregon from compliance with those rules."
23 On page 7, lines 8 and 9, strike "to
24 ignore the requirement that they meet" and substitute
25 "not to comply with." I'll read the sentence as
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865 READING (Di)
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1 corrected. "Do you know why the Company chose not to
2 comply with the Oregon guidelines?"
3 Along the same vein, on page 9, lines 1
4 through 3, the first sentence, strike out "or ask for a
5 wai ver" and substitute on line 2 for "either" "fully" so
6 the sentence as corrected would be, "It is curious that
7 the Company would ask for a waiver of Oregon's
8 competitive bidding guidelines for a 150 megawatt
9 resource while it failed to fully comply with the
10 guidelines for what was originally a 600 megawatt
11 facility. "
12 The other addition is down in the lower
13 right-hand corner beginning on page 6. It has the wrong
14 case. From there through the end of the testimony it
15 says "IPC-E-08-10." They all should be the same as pages
16 1 through 5. They all should be the "09-03" case.
17 Thank you, Dr. Reading. With thoseQ
18 corrections, if I were to ask you the same questions
19 today as are printed in this testimony, would you give
20 the same answers?
21 A Yes.
22 MS. ACKERMAN: In that case,
23 Mr. Commissioner, I'd propose or move that the testimony
24 be spread into the record as though fully read into the
25 record and that the exhibits be marked for
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1 identification.
2 COMMISSIONER KEMPTON: If there is no
3 objection, so ordered.
4 (The following prefiled direct testimony
5 of Dr. Don Reading is spread upon the record.)
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
6
7
8
9
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867 READING (Di)
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1 Q. Please state your name, address, and
2 affiliation.
3 My name is Don Reading. I am Vice PresidentA.
4 and Consulting Economist for Ben Johnson Associates, 6070
5 Hill Road, Boise Idaho. My resume is attached as Exhibit
6 701.
7 On whose behalf are you testifying?Q.
8 The Northwest & Intermountain Power ProducersA.
9 Coalition (NIPPC) asked me to examine the competitive
10 bidding aspects of Idaho Power's filing for a Certificate
11 of Convenience and Necessity (CPCN) for its Langley Gulch
12 Power Plant. NIPPC is an association of independent
13 power producers established to actively pursue informal
14 and formal (i.e., laws, policies, rules and regulations)
15 avenues and forums to promote competi ti ve electric power
16 supply markets in the Pacific Northwest and Intermountain
17 West. NIPPC supports a fully competi ti ve electric power
18 supply marketplace. Among NIPPC' s 15 full members are
19 some of the major independent energy producers in the
20 country. The member companies' energy proj ects currently
21 on-line have a capacity of more than 3,500 MW in the
22 Northwest.
23 What is the purpose of your testimony?Q.
24 My testimony will focus on the competitiveA.
25 bidding process that Idaho Power used in its most recent
868 NIPPC - Reading, 01 2
IPC-E-09-03
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1 Request for Proposals (RFP) for a new supply-side
2 resource. The end result of that competi ti vely bid RFP
3 was that Idaho Power selected itself as the winning
4 bidder.Idaho Power (IPCO) issued its RFP on April 1,
5 2008 for competitive proposals for up to 600 MW of
6 energy. In June 2008 the amount was reduced to
7 approximately 300 MW.
8 How is your testimony organized?Q.
9 The testimony that follows contains four parts.A.
10 First, I will briefly review the bidding process and
11 provide a time-line with key dates. The second section
12 will discuss what aspects make up a transparent and
13 competi ti ve bidding process for utility resources that
14 assures
15
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21
22
23
24
25
869 NIPPC - Reading, 01 2aIPC-E-09-03
.
.
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1 all bidders (the purchasing utility and independent
2 suppliers) have an equal opportunity to supply power to
3 the utility seeking it. The third section will look at
4 Competitive Bidding Guidelines for the state of Oregon
5 where Idaho Power serves approximately 18,000 customers
6 who use 700,000 MWh annually. I conclude this testimony
7 by recommending the Commission deny a CPCN for Langley
8 Gulch at this time and adopt competitive bidding
9 procedures before the Company embarks upon a new RFP
10 process in the future.
11 Dr. Reading could you briefly review the RFPQ.
12 process the Company used that resulted in the selection
13 of its self-build Langley Gulch proj ect.
14 A. Company witness Bokenkamp discusses the
15 Company's RFP procedure on pages 5 through 13 from his
16 direct testimony. The following description is based on
17 that testimony and the Company's responses to discovery
18 requests. In September 2007 the Company decided it would
19 no longer pursue the conventional coal plant it had
20 previously planned. Idaho Power's 2008 Integrated
21 Resource Plan Update (2008 IRP Update) published in June
22 2008 confirmed that decision. In its 2008 IRP Update the
23 Company's analysis indicated a more cost effective
24 resource would be a combined cycle combustion turbine
25 (CCCT) rather than a coal-fired resource. IPC then
870 NIPPC - Reading, 01 3IPC-E-09-03
.
.
.
10
11 /
12
13
1 issued a request for proposals (RFP) in April 2008 for
2 250 to 600 MW dispatchable, physically delivered, firm,
3 or unit contingent energy resource with an on-line date
4 of June 2012. The energy acquisition would be through a
5 power purchase agreement (PPA), a tolling agreement (TA)
6 or a self-build facility. The Company excluded
7 build-own-transfer (BOT) proposals.
8
9 How many responses did the Company receive?Q.
/
14
15 /
16
17
18
19
20
21
22
23
24
25
871 NIPPC - Reading, 01 3a
IPC-E-09-03
.
.
.
1 The Company received responses from sixA.
2 organizations. One proposal failed to provide an intent
3 to bid and thus the bid was returned unopened. The five
4 remaining proposals offered one PPA, nine TA' s, two
5 "hybrid" bids, along with the Company's own benchmark
6 resource. The thirteen al ternati ves contain a variety of
7 different gas fired technologies. The Company, through
8 its screening process, vetted four offers from three
9 bidders. The four short listed gas plants, from three
10 bidders, had significant variation in operational
11 considerations. Two of the facilities were combined
12 cycle, including the Company's benchmark at Langley
13 Gulch, and two were combustion turbine. The three short
14 listed proposals, other than the self-build, were tolling
15 agreements.
16
17 Dr. Reading, you have filed testimony beforeQ.
18 this Commission relating to competitive bidding practices
19 in another docket, GNR-E-08-03. How will this direct
20 testimony differ for that filed in the generic
21 competitive bidding docket?
22 In the generic competi ti ve bidding docket,A.
23 GNR-E-08-03, I addressed Idaho Power's RFP process that
24 resul ted in the Commission issuing a CPCN for the Evander
25 Andrews gas plant at Mountain Home. The current RFP
872 NIPPC - Reading, 01 4
IPC-E-09-03
.
.
.
1 process differs from the Evander Andrews RFP in several
2 ways. In other ways the selection process used to select
3 Langley Gulch parallels the Evander Andrews RFP.
4 Therefore, some of the same discussion points will be
5 used here when they are applicable to this docket.
6 In your GNR-E-08-03 testimony you referenced aQ.
7 report by the Analysis Group for NARUC that discusses
8 recent trends in state policies as they relate to
9 competi ti ve bidding practices and guidelines.
10 (Competitive Procurement of Retail
11
12 /
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17
18
19
20
21
22
23
24
25
873 NIPPC - Reading, DI 4a
IPC-E-09-03
.
.
.
1 Electricity Supply: Recent Trends in State Policies and
2 Utility Practices, July 2008, Analysis Group, Boston,
3 Mass. J What did that report recommend?
4 A.As the Report title implies it contains a
5 review of competi ti ve procurement rules and guidelines
6 that have been implemented in various states. These
7 bidding rules, as would be expected, vary among different
8 states. The study provides a good summary of the
9 guidelines in various states that includes the maj or
10 elements the researchers found. The Executive Summary
11 outlines the elements that lead to a robust and
12 transparent competi ti ve bidding process.
13 Q.Please summarize those elements.
14 First, the procurement process should be fairA.
15 and obj ecti ve. Second, the procurement should be
16 designed to encourage robust competitive offerings and
1 7 creative proposals from market participants. Third, the
18 procurement should select winning offers based on
19 appropriate evaluation of all relevant price and
20 non-price factors. Fourth, the procurement should be
21 conducted in an efficient and timely manner. Finally,
22 when using a competitive procurement process, regulators
23 should align their own procedures and actions to support
24 the development of a competitive response. 1
25 Q.The five elements you just presented appear to
874 NIPPC - Reading, DI 5
IPC-E-09-03
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.
.
1 be goals of a good bidding process that almost everyone
2 could agree with. Did the Report describe specific
3 procedures that can be used to achieve those goals?
4 Yes, the Executive Summary describes what theA.
5 researchers found.
6 The first key issue for incremental resource
7 procurements is the design of safeguards to prevent
8 potential improper self-dealing by the utility. Because
9 the utility may financially
10
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16
17
18
19
20
21
22
23 lCompetitive Procurement of Retail Electricity Supply: Recent
Trends in State Policies and Utility Practices, July 2008,
24 Analysis Group, Boston, Mass., p. ii.
25
875 NIPPC - Reading, 01 SaIPC-E-09-03
.
.
.
1 benefi t from the selection of its own self-build offer or
2 a proposal from an affiliate, safeguards are necessary to
3 ensure that the process is not improperly til ted toward
4 the selection of such offers. As the report describes, a
5 variety of means are available to provide such
6 safeguards, including: The involvement of a third-party
7 independent monitor (" 1M") and/or independent evaluator
8 (" IE"); Measures to increase the transparency of the
9 procurement process to market; Providing potential
10 bidders with detailed information needed to prepare
11 competi ti ve bids; Utility codes of conduct to prohibit
12 improper sharing of information that is valuable to
13 utili ty affiliates in their design of procurement offers
14 and/ or their competitiveness in other electricity
15 markets; and, Careful disclosure and review of how
16 "non-price" factors are considered and evaluated by the
17 utili ty in weighing offers from third parties against
18 self-build or affiliate offers. 2
19 I think it is significant that the "first key
20 issue" is that a utility may derive financial benefit
21 from building its own resources and that could "tilt" the
22 utili ty issuing the RFP in its own favor.
23 Idaho does not have competi ti ve biddingQ.
24 guidelines in place. However the State of Oregon does
25 have guidelines in place. Since Idaho Power serves
876 NIPPC - Reading, DI 6
IPC-E-09-03
.
.
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1 18,000 customers in that state did the Company follow
2 Oregon's guidelines in the Langley Gulch bidding process?
3 A.No. Idaho Power did not follow Oregon's
4 bidding rules despite the fact that it is covered by
5 those rules. In Oregon if an electric utility plans to
6 acquire a resource that is larger than 100 MW, and with a
7 duration greater than five years, then it must comply
8 wi th that state's competi ti ve bidding rules. Although
9 there are elements of the Company's bidding process that
10 appear would meet the Oregon Public Utility Commission
11 Guidelines, while there are others that did not.
12 However, the Company sought, but did not receive, a
13 waiver from Oregon from compliance with those rules.
14
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20
21
22
23
24
25 2Ibid, p. v
877 NIPPC - Reading, DI 6a
IPC-E-09-03
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.
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1 Q.What could be the consequences to the Company
2 for not following the Oregon guidelines?
3 A.Since Idaho Power derives approximately four
4 percent of its revenue from its Oregon jurisdictional
5 operations it could potentially not be permitted to rate
6 base four percent of the cost of Langley Gulch. This
7 would put the responsibility for that portion of the
8 plant on the Company shareholders' shoulders.
9 Q.Do you know why the Company chose not to comply
10 with the Oregon Guidelines?
11 A.No, I do not. Although in response to the
12 Industrial Customers of Idaho Power i s discovery request
13 Nos. 33 and 34, the Company states that it intends to
14 file for rate recovery in Oregon. It also stated that it
15 believes that it has "substantially" complied with the
16 Oregon rules.
17 Q.You stated above that there were elements of
18 the Langley Gulch bidding process that seemed to meet the
19 Oregon guidelines and other that did not. Could you
20 describe those guidelines?
21 A.In discussing the Company's RFP procedure the
22 following testimony will use those Guidelines as a
23 touchstone. (See attached, Guidelines Adopted, UMl182,
24 Order No. 06-446, August 10, 2006, Exhibit 702.)I am
25 not assuming the Oregon guidelines would be the same ones
878 NIPPC - Reading, DI 7
IPC-E-09-03
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.
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10 /
11
12 /
1 the Idaho Commission would approve if they open a generic
2 docket on competi ti ve bidding. However, the Oregon
3 guidelines do insure that the bidding process is fair and
4 the resulting selection was arrived at where all parties
5 had an equal chance of selection.
6 Could you discuss the first Oregon Competi ti veQ.
7 Bidding Guideline?
8 A.Oregon Guideline One states,
9
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15
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18
19
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21
22
23
24
25
879 NIPPC - Reading, DI 7a
IPC-E-09-03
.
.
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1 RFP Requirement: A utili ty must issue an RFP
2 for all Major Resource acquisi tions identified
3 in its last acknowledged Integrated Resource
4 Plan (IRP). Major Resources are resources with
5 durations greater than 5 years and quantities
6 greater than 100 MW.
7 Idaho Power met this Oregon Guideline
8 requirement originally requesting bids on a resource from
9 250 to 600 MW. The size request was lowered to 300 MW
10 two months after the issuance of the original RFP.
11 Q.Could you discuss the second Oregon Guideline
12 for Competi ti ve Bidding?
13 A.Oregon Guideline 2 deals with the conditions
14 for exempting a utility from the competi ti ve bidding
15 requirements. There three conditions for an exemption:
16 (1) Acquisition of a Major Resource in an emergency or
17 where there is a time-limited resource opportuni ty of
18 unique value to customers, (2) Acknowledged IRP provides
19 for an al ternati ve acquisition method for a Maj or
20 Resource. (3) Commission waiver on a case-by-case basis.
21 None of these three conditions were met in
22 Idaho Power's RFP process that resulted in the Company
23 selecting Langley Gulch. Therefore it seems that Idaho
24 Power is not exempt from following the Guidelines.
25 Q.Dr. Reading, are you aware of Idaho Power
880 NIPPC - Reading, 01 8
IPC-E-09-03
.1 as king the Oregon Commission for a waiver of its
2 competi ti ve bidding guidelines for any resource?
3 On June 2nd, 2009, Idaho Power filed a PetitionA.
4 for Partial Waiver of Competi ti ve Bidding Guidelines for
5 150 MW of wind generation to be added to the Company's
6 resources in 2012.(In the Matter of Idaho Power
7 Company's Peti tion for Partial Waiver of Competi tion
8 Bidding Guidelines - 2012 Wind Resource UM 1433.) The
9 Company states it needs to act quickly to take advantage
10 of a time-limited resource acquisition opportunity. This
11 short time frame is the basis for the Company's request
12 for a waiver.
.
.
13
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16 /
17
18 /
19
20
21
22
23
24
25
881 NIPPC - Reading, DI 8a
IPC-E-09-03
.
.
.
1 It is curious that the Company would ask for a
2 wai ver of Oregon's competi ti ve bidding guidelines for a
3 150 MW resource while it failed to fully comply with the
4 guidelines for what was originally a 600 MW facility.
5 Langley Gulch will more than double the wind resource and
6 add significantly more to the Company's rate base. In
7 addition, Langley Gulch is not a time-limited resource
8 that needs to be fast-tracked.
9 Q.Oregon Guidelines 3 and 4 are related, did the
10 Company comply with those two guidelines?
11 A.Guidelines 3 and 4 state:
12 "Affiliate Bidding: A utility may allow its
13 affiliates to submit RFP bids. If affiliates are allowed
14 to bid, the utility must blind all RFP bids and treat
15 affiliate bids the same as all other bids."
16 And:
17 "Utility Ownership Options: A utility may use a
18 self-build option in an RFP to provide a potential
19 cost-based al ternati ve for customers. A site-specific,
20 self-build option proposed in this way is known as a
21 Benchmark Resource. A utility may also consider ownership
22 transfers within an RFP solicitation."
23 Idaho Power no longer has an affiliate that is
24 involved in building generating resources therefore
25 Guideline 3 would not apply. A self-build Benchmark
882 NIPPC - Reading, 01 9
IPC-E-09-03
.
.
.
20
21
22
23
24
25
1 Resource was announced as being part of the RFP process
2 and was ultimately selected as the winning bid.
3 Q.Would you please discuss Guideline 5?
4 A.The fifth Oregon Guideline states that an
5 Independent Evaluator must be used in the RFP process and
6 defines how the IE is to be selected.
7 "Independent Evaluator (IE): An IE must be used
8 in each RFP to help ensure that all offers are treated
9 fairly. Commission Staff, with input from the utility and
10 interested, non-bidding parties, will recommend an IE to
11 the Commission, which will then select or approve an IE
12 for the
13
14 /
15
16 /
17
18 /
19
883 NIPPC - Reading, DI 9a
IPC-E-09-03
.1 RFP. The IE must be independent of the utili ty and
2 likely, potential bidders, and also be experienced and
3 competent to perform all IE functions identified in these
4 Guidelines. The IE will contract wi th and be paid by the
5 utili ty. The IE should confer wi th Commission staff as
6 needed, on the IE's duties under these Guidelines. The
7 utili ty may request recovery of its payments to the IE in
8 customer ra tes. "
9 The Company states that it did hire an
10 "independent third-party to review the Company's RFP and
11 bid evaluation process" (Bokenkamp, p. 6.)R. W. Beck
12 was selected to aid the Company in the RFP process and
.13 Steven Stein of that firm has filed testimony in support
14 of his Letter Report attached to Company witness
15 Bokenkamp' s direct testimony.
16 Mr. Stein, in his Letter Report, reiterates
17 Section 5.5 of the Company's RFP that outlines five items
18 the independent evaluator "may" perform to help ensure
19 the RFP is "conducted fairly and properly". Mr. Stein
20 goes on to say Idaho Power asked his firm to perform only
21 three of the five criteria. R. W. Beck was requested to
22 consul t with the Company in preparing the RFP and
.
23 evaluation criteria along with the evaluation of the
24 proposals. In addition, they were asked prepare reports
25 including those to the Public Utilities Commissions of
884 NIPPC - Reading, DI 10
IPC-E-09-03
.
.
.
1 Idaho and Oregon. The two items listed in Section 5.5
2 RFP that R. W. Beck was not requested to undertake was an
3 independent scoring of all or a sample of the proposals
4 to insure they were consistent with the scoring criteria
5 and compare their scoring results with that of the
6 Company's to reconcile and resolve any scoring
7 differences.
8 Q.In what aspects did Idaho Power fail to meet
9 the fifth Oregon Guideline?
10 A.R. W. Beck was selected by Idaho Power, not
11 Commission Staff, nor the firm approved by the Commission
12 of either state. Aside from these specific criteria, the
13 essence of Guideline 5 is to insure that the IE is truly
14 independent. It is clear the Company selected R. W. Beck
15 and directed their responsibilities . Consulting with the
16 utili ty and receiving direction from it is different from
17 being an independent third party approved by a Commission
18 and operating
19
20 /
21
22 /
23
24 /
25
885 NIPPC - Reading, 01 lOa
IPC-E-O 9-03
.
.
.
1 under pre-established guidelines. This is not to say
2 that R. W. Beck may not have done a proper job, given its
3 limi ted role in this RFP process. What is important is
4 what it was not asked to do - to be a truly independent
5 evaluator from start to finish. The conclusion of the Mr.
6 Stein's Letter Report states,
7 "Finally, based on our work wi th the Idaho Power RFP
8 Evaluation Team as described above, we believe that the
9 Idaho Power 2012 Baseload RFP process was conducted
10 fairly and properly and that offers provided to Idaho
11 Power as part of the RFP process, including the
12 Benchmark Resource, were treated objectively and
13 consistently as set forth in Section 5.5 of the RFP".
14 The key phase in R. W. Beck's conclusion that
15 the RFP process was conducted fairly and properly is
16 "based on our work". Section 5.5 of the RFP, as stated
17 above, provides that the Company "may" ask the IE to
18 perform the given tasks. Any firm, or individual, hired
19 to consult on specified selected items in the RFP process
20 while working under the directives of the hiring utility
21 cannot be assumed to totally independent. This fact
22 casts a cloud over the selection process, especially when
23 the results of the RFP process is the selection of the
24 utili ty' s own self-build option.
25 Q.You just stated that pre-established guidelines
886 NIPPC - Reading, DIll
IPC-E-09-03'
.1 are an important element in the process because they
2 establish the rules the IE must follow in the bidding
3 process. Do the Oregon Guidelines give direction to the
4 selected IE?
5 Yes. The maj ori ty of the Guidelines outlineA.
6 specific actions the IE must follow. Rule 6 establishes
7 RFP design criteria:
8 "RFP Design: The utili ty will prepare a draft
9 RFP and provide it to all parties and interested persons
10 in the utility's most recent general rate case, RFP and
11 IRP dockets. The utili ty must conduct bidder and
12 stakeholder workshops on the draft RFP. The utili ty will.13
.
then submi t a
14
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18
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20
21
22
23
24
25
887 NIPPC - Reading, DI 11a
IPC-E-09-03
.1 final draft RFP to the Commission for approval, as
2 described in Guideline 7 below. The draft
3 RFPs must set forth any minimum bidder requirements for
4 credi t and capabili ty, along wi th bid eval ua tion and
5 scoring cri teria. The utili ty may set a minimum resource
6 size, but Qualifying Facili ties larger than 10 MW must be
7 allowed to participate. The final draft submitted to the
8 Commission must also include standard form contracts.
9 However, the utili ty must allow bidders to negotia te
10 mutually agreeable final contract terms that are
11 different from ones in the standard form contracts. The
12 utili ty will consul t wi th the IE in preparing the RFPs,.13 and the IE will submi tits assessment of the final draft
14 RFP to the Commission when the utili ty files for RFP
15 approval."
16 Many of the criteria described in the Oregon
17 Guidelines were included in the RFP used by Idaho Power.
18 However, some of the most important guidelines that help
19 insure the impartially of the selection process were not.
20 A draft RFP was not submitted for Commission approval,
21 nor did the Commission approve and direct the IE, nor did
22 the IE submit its assessment of the final draft RFP to
23 the Commission.These facts cast serious doubt on the
24 independence and transparency of the competitive bidding.25 process.
888 NIPPC - Reading, DI 12
IPC-E-09-03
.
.
.
1 Q.Please comment on guideline 7.
2 A.Guideline 7 deals with Commission approval of
3 the RFP.
4 Q.Didn't you state earlier the Company did not
5 submi t the RFP to either state Commission?
6 A.That is correct. The Company did not submit
7 ei ther its draft or final RFP to either Commission.
8 Oregon Guideline 7 states:
9 "RFP Approval: The Commission will solici t
10 public comment on the utili ty' s final draft RFP,
11 including the proposed minimum bidder requirements and
12 bid scoring and evaluation criteria. Public comment and
13 Commission review should focus on: (1) the alignment of
14 the utili ty' s RFP wi th its acknowledged IRP; (2) whether
15 the RFP sa tisfies the Commission's competi ti ve bidding
16 guidelines; and (3) the overall fairness of the utili ty' s
1 7 proposed bidding
18
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20
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22
23 /
24
25
889 NIPPC - Reading, DI 12a
IPC-E-09-03
.
.
.
1 process. After reviewing the RFP and the public comments,
2 the Commission may approve the RFP wi th any condi tions
3 and modi fica tions deemed necessary. The Commission may
4 consider the impact of multi-state regulation, including
5 requirements imposed by other states for the RFP process.
6 The Commission will target a decision wi thin 60 days
7 after the filing of the final draft RFP, unless the
8 utili ty requests a longer review period when it submi ts
9 the final draft RFP for approval".
10 Idaho Power developed and issued the RFP with
11 only R. W. Beck providing input. There were no
12 independent third pari ties having input in the
13 development of the RFP to insure it was not constructed
14 in ways that would favor the utilities own self-build
15 proj ect.
16 Q.What is the focus of Guideline 8?
17 A.Guideline 8 establishes the rules for scoring
18 the utilities Benchmark Resource, if one has been part of
19 the bidding process. Guideline 8 states:
20 "Benchmark Resource Score: The utili ty must
21 submi t a detailed score for any Benchmark Resource, wi th
22 supporting cost information, to the Commission and IE
23 prior to the opening of bidding. The score should be
24 assigned to the Benchmark Resource using the same bid
25 scoring and evaluation criteria that will be used to
890 NIPPC - Reading, DI 13
IPC-E-09-03
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.
.
1 score market bids. In forma tion provided to the Commission
2 and IE must include any transmission arrangements, and
3 all other informa tion necessary to score the Benchmark
4 Resource. If, during the course of the RFP process, the
5 utili ty, wi th input from the IE, determines tha t bidder
6 updates are appropriate, the utility may also update the
7 costs and score for the Benchmark Resource. The IE will
8 review the reasonableness of the score (s) for the
9 Benchmark Resource. The information provided to the
10 Commission and IE will be sealed and held until the
11 bidding in the RFP has concluded."
12 The Company reports that it did make efforts to
13 separate the bidding evaluation process from the group
14 within the Company that developed Benchmark Resource
15 resul ting in Langley Gulch CCCT proposal. The Company
16 formed a separate team to develop the
17
18 /
19
20 /
21
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23
24
25
891 NIPPC - Reading, DI 13a
IPC-E-09-03
.
.
.
1 Benchmark Resource. The Benchmark Resource development
2 team did not include any members of the RFP evaluation
3 team. The RFP evaluation team treated the proposal
4 presented by the Benchmark Resource development team in
5 an identical manner as it treated all other entities
6 submi tting proposals in the RFP process. The Benchmark
7 Resource development team received no preferential
8 communication or treatment and the Benchmark Resource
9 proposal was evaluated utilizing using the same
10 evaluation manual and techniques as applied to the other
11 proposals (Application, pgs. 4, 5).
12 However, as pointed out above, there was no
13 independent scoring by a Commission approved IE. To
14 insure the scoring process is transparent and fair,
15 Guideline 8 specifies the scoring of the Benchmark bid
16 should be provided to the Commission and its IE. The
17 Benchmark scoring should then be sealed and held until
18 the bidding of the RFP is concluded. The sealing and
19 holding of the scoring of the Benchmark bid may sound as
20 if the utility is not to be trusted in scoring its own
21 resource. It is really for the utility's benefit and
22 protection because it removes any hint of self dealing.
23 Q.Could you discuss Oregon Guideline 9?
24 A.Oregon Competi ti ve Bidding Guideline 9 states,
25 "Bid Scoring and Evaluation Criteria:
892 NIPPC - Reading, 01 14
IPC-E-09-03
.
.
.
1 Selection of an ini tial short-list of bids
2 should be based on price and non-price factors, and
3 provide resource diversity (e.g., with respect to fuel
4 type and resource dura tion). The utili ty should use the
5 ini tial prices submi tted by the bidders to determine each
6 bid's price score. The price score should be calculated
7 as the ra tio of the bid's projected total cost per
8 megawatt-hour to forward market prices, using
9 real-levelized or annuity methods. The non-price score
10 should be based on resource characteristics identified in
11 the utility's acknowledged IRP Action Plan (e.g.,
12 dispatch flexibility. resource term, portfolio diversity,
13 etc.) and conformance to the standard form contracts
14 attached to the RFP.
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19
20 /
21
22
23
24
25
893 NIPPC - Reading, DI 14a
IPC-E-09-03
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.
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1 Selection of the final short-list of bids
2 should be based, in part, on the resul ts of modeling the
3 effect of candida te resources on overall system costs and
4 risks. The portfolio modeling and decision cri teria used
5 to select the final short-list of bids must be consistent
6 wi th the modeling and decision cri teria used to develop
7 the utili ty' s acknowledged IRP Action Plan. The IE must
8 have full access to the utili ty' s production cost and
9 risk models.
10 Consideration of ratings agency debt imputation
11 should be reserved for the selection of the final bids
12 from the ini tial short-list of bids. The Commission may
13 require the utili ty to obtain an advisory opinion from a
14 ra tings agency to substantia te the utili ty' s analysis and
15 final decision."
16 Idaho Power's IRP process met most of the
17 cri teria in this ninth Guideline. The Company used its
18 AURORA model to evaluate the impact of the short-listed
19 proposals on Idaho Power's system, including forward
20 market prices as part of the input to AURORA. Debt
21 imputation was not factored in the valuation of the
22 non-self build short-listed proposals. The exclusion of
23 estimated debt imputation would tend to favor the tolling
24 and purchase power proposals over the Company's
25 self-build option. Company witness Lori Smith does
894 NIPPC - Reading, DI 15
IPC-E-09-03
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1 discuss imputed debt as relates to general financing
2 issues facing Idaho Power in raising capital to build
3 Langley Gulch.
4 The Company's IRP does not specifically discuss
5 non-price factors. The RFP does list the non-price
6 factors that were considered for the scoring of each
7 short-listed proposal. The seven categories of non-price
8 variables that were scored were: (1) proj ect development;
9 (2) proj ect characteristics; (3) product characteristics;
10 (4) proj ect location; (5) environmental;(6) credit
11 factors; and (7) financial strength. These non-price
12 factors accounted for 40 percent of the total with price
13 variables accounting for the remaining 60 percent. The
14 RFP contained additional explanations as to the scoring
15 for each factor along with their respective weightings.
16 This
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21
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23
24
25
895 NIPPC - Reading, 01 15a
IPC-E-09-03
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.
.
1 addi tional scoring information was a significant
2 improvement over the RFP for Evander Andrews which did
3 not provide information to bidders about how they were to
4 be scored.
5 Q.What factors does Guideline 10 consider?
6 A.Guideline 10 outlines the roles of the utility
7 that issues the RFP and IE. It provides:
8 "Utili ty and IE Roles in the RFP Process:
9 The utili ty will conduct the RFP process, score
10 the bids, select the initial and final short-lists, and
11 undertake negotia tions wi th bidders.
12 The IE will oversee the RFP process to ensure
13 that it is conducted fairly and properly.
14 If the RFP does not allow affiliate bidding and
15 does not incl ude ownership options (i. e., the utili ty is
16 not including a Benchmark Resource or considering
17 ownership transfers), the IE will check whether the
18 utili ty' s scoring of the bids and selection of the
19 short-lists are reasonable.
20 If the RFP allows affiliate bidding or includes
21 ownership options, the IE will independently score the
22 utili ty' s Benchmark Resource (if any) and all or a sample
23 of the bids to determine whether the selections for the
24 initial and final short-lists are reasonable. In
25 addi tion, the IE will evalua te the unique risks and
896 NIPPC - Reading, 01 16
IPC-E-09-03
.
.
.
1 advan tages associa ted wi th the Benchmark Resource (if
2 used), including the regulatory treatment of costs or
3 benefi ts rela ted to actual construction cost and plant
4 operation differing from what was projected for the RFP.
5 Once the competing bids and Benchmark Resource
6 (if used) have been scored and evaluated by the utility
7 and the IE, the two should compare resul ts. The utili ty
8 and IE should attempt to reconcile and resolve any
9 scoring differences. If the two are unable to agree, the
10 IE should explain the differences in its Closing Report".
11 Since the IE was not asked to score the
12 proposals, no reconciliation could occur (see above
13 Guideline 8 above). R. W. Beck was also not asked to
14 evaluate the unique risks and
15
16 /
17
18 /
19
20 /
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23
24
25
897 NIPPC - Reading, 01 16a
IPC-E-09-03
.
.
.
1 advantages that are associated with the Benchmark
2 Resource. This is another example where fairness and
3 transparency would be improved and the utili ties
4 self-build resource could be held above any acquisitions
5 of self-dealing.
6 Q.What topics do the final three Oregon
7 Guidelines cover?
8 A.Guidelines 11, 12, and 13 deal with reporting,
9 confidentially, and Commission acknowledgment:
10 IE Closing Report: The IE will prepare a
11 Closing Report for the Commission after the utili ty has
12 selected the final short-list. In addition, the IE will
13 make any detailed bid scoring and evaluation resul ts
14 available to the utili ty, Commission staff, and
15 non-bidding parties in the RFP docket, subject to the
16 terms of a protective order.
17 Confidential Treatment of Bid and Score
18 Informa tion: Bidding informa tion, including the utili ty's
19 cost support for any Benchmark Resource, as well as
20 detailed bid scoring and evalua tion resul ts will be made
21 available to the utili ty, Commission staff and
22 non-bidding parties under protective orders tha t limi t
23 use of the information to RFP approval and acknowledgment
24 and to cost recovery proceedings.
25 RFP Acknowledgment: The utili ty may request
898 NIPPC - Reading, DI 17
IPC-E-O 9-03
.
.
.
1 tha t the Commission acknowledge the utili ty' s selection
2 of the final short-list of RFP resources. The IE will
3 participate in the RFP acknowledgment proceeding.
4 Acknowledgment has the same meaning as assigned to that
5 term in Commission Order No. 89-07. RFP acknowledgment
6 will have the same legal force and effect as IRP
7 acknowledgment in any future cost recovery proceeding.
8 The utili ty' s request should discuss the consistency of
9 the final short-list wi th the Company's acknowledged IRP
10 Action Plan."
11 The Company is making available, under
12 protecti ve order, documents used in the RFP process to
13 interveners in this docket. However, as discussed above,
14 there was no request to provide a scoring critique. Mr.
15 Stein of R. W. Beck has filed testimony support his Letter
16 Report and will be available for cross examination.
17
18 /
19
20 /
21
22 /
23
24
25
899 NIPPC - Reading, 01 17a
IPC-E-09-03
.
.
.
1 Q.You stated above that following the Oregon
2 Competi ti ve Bidding Guidelines would insure a bidding
3 process that is fair and would result in the selection of
4 a resource where all parties had an equal chance of
5 selection. Do you believe the Company made sufficient
6 efforts to conduct a fair competi ti ve bidding process?
7 A.No. It is my belief the Company did not take
8 enough precautions to insure that the process did give
9 all parties an equal chance. Idaho Power states the RFP
10 process leading up to the selection of Langley Gulch was
11 competitive.
12 "The competi ti ve RFP process allows the Company
13 to access the broader power supply market to obtain the
14 best resource for our customers. It gives us access to a
15 spectrum of potential resources and resource developers.
16 Use of a formal RFP process provides customers and
17 regula tory agencies wi th the assurance tha t the resource
18 selection process was competi tive, all potential
19 suppliers had an equal opportunity to participate, and
20 that the best resource alternative was selected".
21 (Bokenkamp direct testimony, p. 5)
22 An example of where the Company's RFP process
23 failed to provide 'a spectrum of potential bidders' is
24 contained in a letter sent to Idaho Power by a potential
25 bidder. (Exhibit 703)
900 NIPPC - Reading, DI 18
IPC-E-O 9-03
.
.
.
1 *************BEGINNING OF CONFIDENTIAL*****************
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901 NIPPC - Reading, 01 19
IPC-E-09-03
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902 NIPPC I 19aReading, D 09 03
IPC E
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IPC E 09 03
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904 NIPPC - Reading, 01 20a
IPC-E-09-03
.
.
20
21
22
23
24.25
1 Q.What are your recommendations for Commission in
2 this docket?
3 A.I recommend the Commission deny the CPCN for
4 Langley Gulch at this time. In my testimony filed on
5 behalf of the ICIP in this docket I show why the plant is
6 not needed at this time, and why a tolling agreement or
7 power purchase may well serve the Company and its
8 ratepayers better. As I have outlined above, the bidding
9 process has not been conducted in a fair and transparent
10 manner. Therefore, I recommend the Commission in its
11 Order denying the Langley Gulch CPCN include some
12 condi tions for the new issuing of an RFP. Specifically
13 that the Commission and Commission Staff and relevant
14 stakeholders become involved with the selection of the IE
15 and establishing specific duties that the selected firm
16 should follow.
17 Q.Does this complete you this testimony on
18 June 19, 2009?
19 A.Yes it does.
905 NIPPC - Reading, 01 21
IPC-E-09-03
.1
2 open hearing.)
(The following proceedings were had in
MS. ACKERMAN: And the witness is
4 available for cross.
.
20
21
22
.
3
5
6
7 Mr. Chairman.
8
9
10
11
12
13
14
15
16
17 Dr. Reading.
18
19
23 BY MR. KLINE:
24
25
Q
COMMISSIONER KEMPTON: Mr. Richardson.
MR. RICHARDSON: No questions,
COMMISSIONER KEMPTON: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Purdy.
MR. PURDY: No questions.
COMMISSIONER KEMPTON: Mr. Miller.
MR. MILLER: No questions.
MS. BRIDGE: No questions, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Woodbury.
MR. WOODBURY: I have no questions of this
COMMISSIONER KEMPTON: Mr. Kline.
MR. KLINE: Thank you.
CROSS-EXAMINATION
Looking at your corrected testimony on
page 6, line 23 --
906 READING (X)
NIPPC
CSB REPORTING
[phone]
.
.
1 A Yes.
2 Q you're certainly not implying that the
3 Company's request for a waiver was rej ected, are you,
4 Dr. Reading?
5 A No.
6 Q No, and in fact, the Company withdrew it
7 at the request of the OPUC staff; isn't that correct?
8 A Relying on, I guess, Mr. Gale's testimony,
9 that's what he represented.
10 Q All right.
11 A If I might add, I'll apologize, I called
12 the Oregon Commission and I misunderstood between not
13 comply and ask for a waiver; otherwise, I didn't realize
14 that when I wrote the testimony.
15 Q Okay, just one more question about the
16 Oregon guidelines. The Oregon guidelines require that
17 the Company present a benchmark resource, do they not?
18 A I think it's optional. I'd have to
19 re-read them.
20
21
Q Okay, I thought it was mandatory.
A I think they can, but I don't think
22 they're required to.
23 Q All right. Now, your recommendation to
24 the Commission as to how this Commission should respond.25 to the Company's request for a certificate is identical
CSB REPORTING
[phone]
907 READING (X)
NIPPC
.
.
.
1 for both ICIP and NIPPC, is it not?
2 A Yes.
3 Q And as I read your testimony, you're
4 requesting that the Commission, No.1, deny the
5 certificate?
6 A Correct.
7 Q No.2, wait until the 2009 IRP is
8 acknowledged; correct?
9 A I'm not sure. There could be some
10 overlapping, but, yes, certainly not make a decision
11 until that's final.
12 Q All right, and then adopt new competitive
13 bidding guidelines; correct?
14 A What I was attempting to say is I do not
15 believe there, and I think I said it in my testimony, I
16 do not believe there is really time to go through the
17 full generic docket that's been filed for long-run
18 competi ti ve bidding in all of Oregon. What I was
19 attempting to say in my testimony was that the Commission
20 can lay down some sideboards or requirements for the new
21 bidding and the one that I specifically mentioned was an
22 independent evaluator that was approved by the Staff and
23 the Commission would have approval of the independent.
24 There could be other requirements, but not necessarily a
25 full-blown put in the rules because I think the time
CSB REPORTING
[phone]
908 READING (X)
NIPPC
.
.
.
1 frames are too tight.
2 Q All right, and then once that was done,
3 you'd recommend the Company just then completely redo the
4 RFP process?
5 A Correct, under those stipulations as set
6 down by the Commission.
7 Q So you i re really recommending a process
8 that's a whole lot more than just waiting until a new
9 load forecast comes out in the IRP, aren't you?
10 A Yeah, it's more, yes, and that's why I
11 said I think should the Commission accept my
12 recommendations, there could be some parallel tracking on
13 the processes.
14 Q But you're not talking probably months or
15 maybe even weeks that would be required for the
16 Commission to receive a new load forecast in the IRP,
17 you're probably talking years to go through the full
18 process that you've recommended.
19 A I certainly wouldn't put an "s" on the
20 end.
21 Q Well, that would certainly be inconsistent
22 wi th what happened in Oregon; isn't that true?
23 A If you are referring to Mr. Gale 's
24 discussion of PacifiCorp, yes, that process took a long
25 time and let's see, how can I say this without -- my
CSB REPORTING
[phone]
909 READING (X)
NIPPC
.
.
.
1 experience in the regulatory arena has shown me that
2 sometimes it is the commission, commissioners and/or
3 commission staffs that jam the process up and sometimes
4 it's the utili ties that j am the process up by changing
5 things. As I understand it, the PacifiCorp original
6 filing was based on a coal plant and then during the
7 process they changed to a gas plant. The Oregon -- there
8 have been examples in Oregon where the RFP process has
9 been followed and the whole thing has taken a year or
10 less.
11 Q All right, Invenergy is a member of NIPPC;
12 is that correct?
13 A Boy, I'd have to check. Subj ect to check,
14 yes.
15 Q Subj ect to check, I'LL represent that that
16 was presented to us in response to a production request,
17 and Invenergy was one of the three short-listed bidders,
18 were they not?
19 A Am I allowed to say that?
20 Q Yes, because they intervened here and they
21 said that.
22 A Okay.
23 Q If Invenergy would have won the bid, you
24 really wouldn't be here today testifying that we need to
25 redo the IRP process, would you?
CSB REPORTING
[phone]
910 READING (X)
NIPPC
.1 A I cannot answer that because NIPPC may
2 have never called me as a witness, so I may have been
3 representing only the Industrial Customers of Idaho Power
4 and I would have to review the case given the fact that
5 they were the winning bidder.
6 Q But you had already been retained by NIPPC
7 in the generic proceeding, had you not?
8 A Yes.
9 Q So you were retained before that, before
10 this case?
.
.
11 A Not for this docket, no.
12 Q Right, but in another docket?
13 A Right.
14 Q And would you expect that NIPPC would be
15 here in this case asking for a redo if one of their
16 members had won?
17 A I would, boy, and this is speculating,
18 really speculating, i would assume that the independent
19 power producers in a bidding process if an independent
20 power producer were the winning bid, then they wouldn't
21 have the heartburn they have on a self-build.
22 Q And really the only reason that a redo is
23 on the table as far as NIPPC is concerned is that one of
24 its members just got a little bit greedy and didn i twin
25 the bid; isn't that true?
CSB REPORTING
[phone]
911 READING (X)
NIPPC
.1 A I certainly would not term it as greedy
2 and I cannot speculate that.
3 MR. KLINE: All right, that's fair.
4 That's all I have.
5 COMMISSIONER KEMPTON: Commissioner
6 Redford.
7
8 EXAMINATION
9
10 BY COMMISSIONER REDFORD:
11
.
20
.
Q Just a couple of questions, Dr. Reading.
12 The bidding manual called for bids for a power purchase
13 agreement and for a tolling agreement.
14 A Excuse me, clarification, do you mean the
15 evaluation manual or the RFP?
16 Q The RFP, excuse me.
17 A The RFP, yes, it did.
18 Q And Benchmark chose to submit a bid where
19 Idaho Power would own the facilities.
A Correct.
21 Q There's been testimony from Idaho Power
22 today that in fact Idaho Power attempted to level the
23 playing field as far as the net present value calculation
24 and an agreement for a power purchase agreement and a
25 tolling agreement. Isn i t that like comparing apples and
CSB REPORTING
[phone]
912 READING (Com)
NIPPC
.
.
.
1 oranges?
2 A Yeah, I would agree the RFP did not
3 specify that net present value would be used. It also,
4 and I don't know what I'm allowed to say, there were
5 three different year sets can I say what they are?
6 MS. ACKERMAN: I would suggest that if you
7 want to go into things that you think are confidential,
8 Dr. Reading, we should get people in the room who are not
9 on the protective order to leave.
10 THE WITNESS: The methodology that was
11 incorporated in the evaluation manual was not fully
12 explained in the RFP. I guess that's as far as I can go.
13 Q BY COMMISSIONER REDFORD: I believe one of
14 the Idaho Power witnesses, I think Ms. Smith, stated that
15 all the other bidders could have just lowered their price
16 and as a result, they could have been competitive where
17 the evaluation was done on the basis -- one of the
18 elements which was net present value. Do you agree with
19 that?
20 A I certainly don't know their financial
21 si tuations, and I will refer back to Mr. Kline's
22 question. The difference between making a profit and
23 being greedy sometimes is a fine line in people's heads,
24 but certainly, independent power producers are not in the
25 business to lose money, so they have their costs. They
CSB REPORTING
[phone]
913 READING (Com)
NIPPC
.
.
.
1 do their best to put together a bid that they think is
2 valid, and so they can't just arbitrarily lower their
3 price, no, not and stay in business.
4 Q Is there anything that one of the other
5 bidders could have done to compete with the evaluation
6 that took into consideration net present value?
7 A I believe that if the bidders would have
8 fully understood what the evaluation criteria were, what
9 the methodology was being used, they may well have been
10 able to put together a bid that would have been more
11 competitive. I mean, I guess that's all I can say. I
12 testified in the Evander Andrews case and had criticisms
13 about the bidding process in that particular case and one
14 of them was the fact that the evaluation manual was not
15 known to the bidders. This bid certainly explained more
16 than the Evander Andrews RFP, but in my mind has not
17 explained enough.
18 I disagree with Mr. Stein's testimony when
19 he was on the stand that said they should be kept from
20 the bidders because they will game the system. As I
21 remember in my Evander Andrews testimony, I likened it to
22 what my firm does and that is when we submit an RFP, the
23 first thing we do is we look at what the evaluation
24 criteria are, because that's the only way we know what's
25 important to the client. It's not to game the system,
CSB REPORTING
[phone]
914 READING (Com)
NIPPC
.
.
.
1 it's to understand what the client is asking for and how
2 can we, you know, bid to fill that need.
3 COMMISSIONER REDFORD: Thank you. I have
4 no further questions.
5 COMMISSIONER KEMPTON: Commissioner
6 Smith.
7 COMMISSIONER SMITH: Oh, just one.
8
9 EXAMINATION
10
11 BY COMMISSIONER SMITH:
12 Q Dr. Reading, if all the bids had come in
13 at the same price, would they all have had the same net
14 present value?
15 A Not necessarily,not the way the Company
evaluated it.It would depend on --
Q The revenue stream?
A And was it front-loaded,back-loaded,
bumped in the middle,were there breaks,were there
16
17
18
19
20 balloons, all those kinds of things would change the net
21 present value of it.
22
23
COMMISSIONER SMITH: Okay, thank you.
COMMISSIONER KEMPTON: I have no
24 questions. Redirect, Ms. Ackerman?
25 MS. ACKERMAN: Yes, just one, Your
CSB REPORTING
[phone]
915 READING (Com)
NIPPC
.
.
.
17
1 Honor.
2
3 REDIRECT EXAMINATION
4
5 BY MS. ACKERMAN:
6 Q Dr. Reading, are you familiar with the
7 generic docket that's been opened?
8 A Yes, I filed testimony in it.
9 Q Okay, and so the question I've got for
10 you, was that generic docket opened before the bidding
11 resul ts were known or after the bidding results were
12 known? And by bidding results, I mean --
13 A I think it was after. Boy, I'd have to
14 look at the date, I'm sorry.
15 Q Was the generic docket opened before
16 bidding results were known or after?
18 come from your own lawyer.
COMMISSIONER SMITH: The hardest questions
19
20 through it.
THE WITNESS: Yeah, I'm trying to think
21 Q BY MS. ACKERMAN: Well, I wonder if you
22 would accept, subj ect to check --
23 A I certainly would. My attorney, I
24 certainly would, yes.
25 Q -- the generic docket was opened before
CSB REPORTING
[phone]
916 READING (Di)
NIPPC
.
.
.
16
1 the bidding results were known in this case.
2 A Okay, I would accept that, yeah. I'm
3 sorry, I'm hazy when do I this stuff.
4 MS. ACKERMAN: That's it,
5 Mr. Commissioner.
6 COMMISSIONER KEMPTON: I only wish that we
7 could have gone ahead with the generic docket prior to
8 the time that we went ahead with this hearing only in the
9 sense that we could have perhaps separated the issues and
10 moved forward faster, but that isn't the way it is and
11 we're just doing fine here.
12 Mr. Olsen, if it's all right with you, I'd
13 like to go to Mr. Purdy because of his time constraints.
14 Mr. Purdy, do you have a witness?
15 MR. PURDY: Yes, I do.
17 Dr. Reading is excused?
MS. ACKERMAN: I guess that means
18 COMMISSIONER KEMPTON: Yes. Well, we can
19 hold him up there for awhile, but it wouldn't last longer
20 than my memory, so why don't you go ahead and step down,
21 Mr. Reading.
22
23
24
25
THE WITNESS: Thank you.
(The witness left the stand.)
MR. PURDY: Yes, Mr. Chairman, I just have
one, Ms. Ottens. The Community Action Partnership
CSB REPORTING
[phone]
917 READING (Di)
NIPPC
.1 Association of Idaho calls Teri Ottens.
2
3 TERI OTTENS,
4 produced as a witness at the instance of the Community
5 Action Partnership Association of Idaho, having been
6 first duly sworn, was examined and testified as follows:
7
8 DIRECT EXAMINATION
9
10 BY MR. PURDY:
11 Q Would you please state and spell your name
12 and provide your business address?
13.
.
A Teri Ottens, O-t-t-e-n-s. My business
14 address is 5420 West Franklin, Suite B, Boise.
15 Q By whom are you employed and in what
16 capacity?
17 A I'm the policy director for the Community
18 Action Partnership Association of Idaho.
19 Q Thank you, and have you previously filed
20 direct testimony in this matter consisting of, I beg your
21 pardon, 12 pages and no exhibits?
22 A Yes.
23 Q Do you have any corrections you'd like to
24 make to that testimony?
25 A I do. On page 6, lines 7 and 8, on line 7
CSB REPORTING
[phone]
918 OTTENS (Di)
CAPAI
.
.
.
1 I transposed the figures. Instead of "247," it should
2 read "427," just a $200 million mistake, and on the next
3 line after reading Mr. Gale's testimony, I recalculated
4 and agree with his testimony or his rebuttal that the
5 figure is closer to 20 percent of the entire rate base
6 rather than 25.
7 Q Now, I'm double checking, did you say line
8 7 or line 6?
9 A Mine shows line 7. Is it line 6 or line
10 5? Oh, I must have an earlier version, I apologize.
11 MR. PURDY: I'm sorry, Mr. Chair, I would
12 note for the record that it is in fact on line 6 and Ms.
13 Ottens might have an earlier version of her testimony.
14 Q BY MR. PURDY: So with that correction,
15 Ms. Ottens, if I were to ask you the same questions
16 contained today with the corrections you've just made,
17 would your answers be the same?
18 A They would.
19 MR. PURDY: All right, I ask that the
20 direct testimony of Teri Ottens as corrected be spread
21 upon the record as if read and tender her for cross.
22 COMMISSIONER KEMPTON: Without obj ection,
23 it is so ordered.
24 (The following prefiled direct testimony
25 of Ms. Teri Ottens is spread upon the record.)
CSB REPORTING
[phone]
919 OTTENS (Di)
CAPAI
.
.
1 I.INTRODUCTION
2 Q.Please state your name and business address.
3 A.My name is Teri Ottens. I am the Policy
4 Director of the Community Action Partnership Association
5 of Idaho headquartered at 5400 W. Franklin, Suite G,
6 Boise, Idaho, 83705.
7 Q.On whose behalf are you testifying in this
8 proceeding?
9 A.The Community Action Partnership Association of
10 Idaho ("CAPAI") Board of Directors asked me to present
11 the views of an expert on, and advocate for, low income
12 customers of Idaho Power.
13 Q.Please describe CAPAI' s organization and the
14 functions it performs, relevant to its involvement in
15 this case.
16 A.CAPAI is an association of Idaho's six
1 7 Community Action Partnerships, the Community Council of
18 Idaho and the Canyon County Organization on Aging,
19 Weatherization and Human Services, all dedicated to
20 promoting self-sufficiency through removing the causes
21 and conditions of poverty in Idaho's communi ties.
.
22 Q.What are the Community Action Partnerships?
23 A.Community Action Partnerships ("CAPs") are
24 private, nonprofit organizations that fight poverty.
25 Each CAP has a designated service area. Combining all
920 OTTENS, 01 2
CAPAI
.
.
.
1 CAPS, every county in Idaho is served. CAPS design their
2 various programs to meet the unique needs of communi ties
3 located wi thin their respective service areas. Not every
4 CAP provides all of the following services, but all work
5 wi th people to promote and support increased
6 self-sufficiency. Programs provided by CAPS include:
7 employment preparation and dispatch, education assistance
8 child care, emergency food, senior independence and
9 support, clothing, home weatherization, energy
10 assistance, affordable housing, health care access, and
11 much more.
12 Q.Have you testified before this Commission in
13 other proceedings?
14
15 /
16
17 /
18
19 /
20
21
22
23
24
25
921 OTTENS, DI 2a
CAPAI
.
.
.
1 A.Yes, I have testified on behalf of CAPAI in
2 numerous cases involving Idaho Power Company, PacifiCorp,
3 AVISTA, Intermountain Gas, and United Water as well as in
4 multi-utility proceedings.
5 II. SUMY
6 Q.Would you please summarize your testimony in
7 this proceeding?
8 A.Yes. CAPAI is concerned about the Company's
9 investment in, and its quest to seek, rate base assurance
10 for, a generation proj ect that will be the largest
11 acquired by Idaho Power since the 1950s. CAPAI is
12 concerned about the rate impact that such a large
13 addi tion to the Company's rate base will result in and
14 its effect on Idaho Power's low-income customers.
15 Specifically, CAPAI questions whether the Company and the
16 Commission have sufficient information at this point in
17 time to make a determination whether the proposed Langley
18 Gulch plant is in the public convenience and necessity
19 and whether the relief sought by Idaho Power is fair,
20 just and reasonable.
21 Q.Do you have any exhibits to your testimony?
22 A.No, I do not.
23 III. THE APPLICATION
24 Q.You seem to express doubt regarding whether the
25 Langley Gulch proj ect is in the public convenience and
922 OTTENS, 01 3
CAPAI
.1 necessi ty. Do you have specific, technical rationale for
2 this?
3 A.First, I am not a lawyer, engineer, or
4 economist, so I do not purport to possess expertise in
5 any of those disciplines and nothing in my testimony
6 should be construed to suggest otherwise. My expertise
7 lies wi thin the area of the needs of Idaho's poor and, in
8 the context of this proceeding, how a large electric rate
9 increase will impact Idaho Power's low-income customers.
10 I honestly do not know if Langley Gulch is in the public
11 convenience and necessity and whether it would result in
12 fair, just and reasonable rates. I adamantly believe,
.13 nonetheless, that in order to make these decisions, the
14
15
16 /
17
18 /
19
20 /
21
22
23
24.
Commission
25
923 OTTENS, DI 3a
CAPAI
.
.
.
1 must be equipped with as much relevant information as is
2 reasonably possible to obtain wi thin an acceptable
3 timeframe. I submit that the Commission is faced wi th a
4 balancing act of comparing the risks associated with
5 deferring a ruling on the Company's application until
6 additional information is available, to the advantage of
7 possessing such additional information.
8 Q.Are you suggesting that the proposed Langley
9 Gulch proj ect would not help Idaho Power to meet future
10 load growth?
11 A.No, it appears that no party disputes that
12 Langley Gulch, as proposed, should be more than adequate
13 to meet future load growth, for at least the near to
14 medium term future. The analysis, however, does not end
15 there. One does not need to be an expert in these
16 matters to embrace the obvious proposition that a
17 regulated public utility should, among other things, make
18 every attempt to pursue least cost al ternati ves, best
19 suited to meet the needs in question, when it does
20 acquire new resources, thereby minimizing increases to
21 rates. Indeed, this is one of the fundamental purposes
22 of the Integrated Resource Planning process; to identify
23 the relative costs of various resource alternatives.
24 Q.Is it your position that Langley Gulch does not
25 consti tute the least cost al ternati ve to meet the
924 OTTENS,. 01 4
CAPAI
.
.
20
21
.
1 Company is perceived capacity deficit as it contends in
2 its application and supporting testimonies?
3 A.Again, I lack sufficient expertise and/or
4 knowledge to testify with authority whether Langley Gulch
5 is the most suitable alternative, from a cost and other
6 standpoint, for meeting Idaho Power's proj ected capacity
7 defici t, or when that date will occur.Moreover, CAPAI
8 believes that Idaho Power is genuinely concerned about,
9 and takes quite seriously , its legal obligation to serve
10 its customers, and to make sensible decisions in planning
11 how to acquire sufficient resources to comply with that
12 legal obligation now and in the future. CAPAI was
13 graciously allowed to intervene late in this proceeding
14
15 /
16
17 /
18
19 /
22
23
24
25
925 OTTENS, DI 4a
CAPAI
.
.
.
1 and, therefore, did not sign on to the j oint intervenors'
2 motion to stay the application. Nonetheless, as the
3 Commission noted during a decision meeting conducted to
4 address the motion to stay, the points raised by the
5 motion go to the merits of the application and are now
6 fully on the table. Based on the brief filed in support
7 of the intervenors' motion, and my review of the
8 Company's application and supporting testimonies, it
9 seems apparent, from a layperson's point of view, that
10 the other intervenors have articulated legitimate
11 concerns regarding the overall merits of the Application
12 and, without the benefit of additional information,
13 whether Langley Gulch is the best means, at this
14 juncture, to meet imminent system load growth.
15 Q.If you are not taking a specific position
16 regarding whether Langley Gulch should be constructed at
17 this point in time, then what is the purpose of your
18 testimony in this case?
19 A.The best response I can provide to that
20 question is to use Idaho Power's own words when it
21 characterized the joint intervenors' motion as a
22 collection of "what ifs." Response to Joint Motion at p.
23 2. The same characterization could be applied to the
24 assumptions built into Idaho Power's load forecasting,
25 it's proj ected date of capacity deficit, whether there
926 OTTENS, DI 5
CAPAI
.
.
.
1 are more sui table resources available to meet load
2 growth, and so on. Again, I do not possess the knowledge
3 or expertise to argue with authority whether Idaho
4 Power's load forecasting methodology and the assumptions
5 buil t into that methodology are appropriate. It strikes
6 me as inherently logical, however, that the more
7 information that the Company, the Commission, and all
8 parties have, the better able the collective group is to
9 assess whether Langley Gulch is the generation resource
10 of choice to meet the Company's load growth.
11 Q.There is obvious risk in not meeting the
12 Company's future capacity requirements to avoid
13 blackouts. Do you perceive other risks that the
14 Commission faces in ruling on Idaho Power's application
15 in this case?
16
17 /
18
19 /
20
21 /
22
23
24
25
927 OTTENS, DI Sa
CAPAI
1 A.Yes. First, it cannot be overstated that the.2 Commission carries an awesome responsibility to ensure
3 that Idaho Power's customers are not, literally, left in
4 the dark. The importance of attempting to engage in the
5 most accurate load forecasting possible, however, and to
6 fully and fairly analyze all al ternati ves to Langley
7 Gulch, also cannot be overstated. Thus, the Company's
8 application poses two risks. With an estimated cost of
9 $427 million, Langley Gulch will constitute approximately
10 one-fourth of Idaho Power's entire rate base. This is
11 the single largest investment that would be made by Idaho
12 Power since the Hell's Canyon complex some 50 years ago.
.13 Naturally, the rate impact of an investment of this
14 magni tude, which disproportionately affects the poor, is
15 tremendous. CAPAI is uncertain as to the precise amount
16 of increase to residential rates that Langley Gulch will
17 resul t in, and concedes that any al ternati ve resource, or
18 collection of resources to meet load growth, will also
19 have an upward impact on rates. The sheer magnitude of
20 Langley Gulch's estimated cost, however, warrants a very
21 careful analysis of whether there might be considerably
22 cheaper, and equally viable , alternatives available.
23 Thus, the other side of the equation that I speak of is
24 that if Langley Gulch is not the least cost al ternati ve.25 for meeting future load growth, and given the immediate,
928 OTTENS, DI 6
CAPAI
.
.
.
1 irreversible ratebasing assurance that Idaho Power seeks
2 in this case, then ratepayers could be saddled with
3 unnecessarily excessive rates for many years to come.
4 This too, constitutes a serious risk.
5 Q.So, what would you have the Commission do in
6 weighing the two primary risks presented by Idaho Power's
7 application?
8 A.Again, I propose that the arguments made in
9 support of the j oint intervenors' motion to stay the
10 application, at least for some reasonable time, be
11 seriously considered and that the assumptions built into
12 the Company's assessment of the need for Langley Gulch,
13 be carefully scrutinized. Specifically, the other
14 intervenors have raised, among others, the
15
16 /
17
18 /
19
20 /
21
22
23
24
25
929 OTTENS, 01 6a
CAPAI
.1 following questions regarding the merits of Langley Gulch
2 including, among others, the following: Is Langley Gulch
3 the least cost alternative for meeting future load
4 growth? Has the Company engaged in a fair bid
5 procurement process resulting in the least cost for
6 constructing Langley Gulch? Has Idaho Power pursued
7 other al ternati ves such as demand side management
8 programs aggressively enough? Has Idaho Power factored
9 in the reduction in load demand that existing and future
10 DSM programs will have? Has the Company considered
11 impending or existing state and federal legislation
12 regarding greenhouse gas emissions, and whatever action
13 the Company will take in response to a recent shareholder.14 resolution regarding gas emissions that might increase
15 the relative costs of a thermal plant such as Langley
16 Gulch? Is Langley Gulch appropriate in light of
17 renewable portfolio standards that I am told might be
18 legislated and enforced upon the Company, and so on?
19 Q.What are the ramifications of failing to
20 aggressively pursue demand side management programs and
21 the effect that this has on the perceived viability of
22 Langley Gulch?
23 A.Regarding demand-side al ternati ves, it is my
24 understanding that Idaho Power is a "twin peaking".25 utili ty in terms of its load. That is, the utility's
930 OTTENS, 01 7
CAPAI
.
.
.
1 highest demands come in the summer (due largely to
2 irrigation and air conditioning) and in the winter (due
3 largely to electric space heating). One advantage that a
4 revised IRP might provide is a revelation whether
5 increased investment in residential demand side
6 management programs, such as the Company's
7 cost-effective, low-income weatherization program, are
8 being fully exploited and, if not, might a more
9 aggressi ve approach to such DSM programs shave the peaks
10 off the summer and winter loads in a more cost-effective
11 manner than Langley Gulch?
12 Q.Would you please provide an example of what you
13 are referring to?
14
15 /
16
17 /
18
19 /
20
21
22
23
24
25
931 OTTENS, 01 7a
CAPAI
.
.
.
1 One example pertains to the Company'sA.
2 low-income weatherization program. According to CAPAI' s
3 records, all low-income weatherization programs funded by
4 Idaho's three largest public electric utili ties (i. e. ,
5 Idaho Power, Rocky Mountain Power and AVISTA) served only
6 10% of all LIHEAP eligible residences in the most recent
7 year for which information is available. In recent
8 cases, including the Commission-initiated energy
9 affordability case (Case No. GNR-U-08-1), Idaho Power has
10 characterized its low-income weatherization program as a
11 very cost-effective DSM resource. This is merely one
12 example of what the Company itself deems to be a
13 relatively cost-effective DSM resource that, arguably, is
14 not being fully taken advantage of. While an increased
15 investment in the Company's low-income weatherization
16 program is hardly a surrogate for a large generation
17 plant such as Langley Gulch, it is an example of just one
18 of a number of potentially low-cost, DSM alternatives
19 that the Commission could analyze through the IRP process
20 at the end of this year. Another example is the changes
21 to the Irrigator's Peak Rewards Programs. A thorough
22 analysis of Langley Gulch that contains the additional
23 information mentioned above might demonstrate that a
24 combination of DSM measures, retooling of existing
25 thermal generation plants (e. g., converting simple cycle
932 OTTENS, DI 8
CAPAI
1 gas turbines to combined cycle), and other measures, will.2 prove to be the least cost means to meet load growth.
3 Q.In their motion to stay, the other intervenors
4 in this case urge the Commission to defer a ruling on
5 Langley Gulch in order to obtain additional information.
6 What is CAPAI' s position in this regard?
7 A. As stated, CAPAI did not join in the motion to
8 stay. Just the same, CAPAI respectfully urges the
9 Commission to scrutinize whether Idaho Power's assertion
10 that there is insufficient time for the Commission to
11 defer issuing a ruling on whether to irreversibly commit
12 to ratebasing Langley Gulch is accurate. If the
13 Commission determines that there.14
15 /
16
17 /
18
19 /
20
21
22
23
24.25
933 OTTENS, DI 8a
CAPAI
1 is sufficient time to obtain some or all of the.2 addi tional information identified by the intervenors,
3 then deferring a ruling on Langley Gulch would seem to be
4 warranted. In addition, the Company's Integrated
5 Resource Planning process is currently on hold. It is my
6 understanding that the process will resume in September
7 wi th a final result estimated close to the end of the
8 year. The IRP process should shed light on some of the
9 assumptions that I understand are incorporated into the
10 viability of Langley Gulch, the possibility of other,
11 lesser cost al ternati ves, the accuracy of the estimated
12 capaci ty deficit date, and so on. Additional time might
13 also provide information such as federal legislation.14 regarding carbon emissions, the effect of the recession
15 on load growth, Idaho Power's actions in response to its
16 shareholders' greenhouse gas resolution and how that
17 might affect Langley Gulch's place in the Company's IRP
18 and, finally, the implementation of renewable portfolio
19 standards that might be required under state or federal
20 law. CAPAI urges the Commission to consider whether
21 waiting until this additional information is available
22 would truly create a risk of blackouts.
23 Q.Are you taking a position as to whether this
24 additional information will prove Langley Gulch to not be.25 the least cost al ternati ve for meeting load growth?
934 OTTENS, DI 9
CAPAI
.
.
.
1 A.No, I am not. I am simply expressing concern
2 regarding the long-term rate implications of such a large
3 investment on the Company's low-income customers and
4 concern regarding whether the issues raised by the other
5 intervenors are being given their due consideration.
6 Again, there is much at stake for all concerned. CAPAI
7 greatly appreciates the careful and fair analysis that it
8 knows the Commission will give this most important
9 matter.
10 Q.Finally, does CAPAI have a position regarding
11 Idaho Power's proposal to collect a return on its
12 investment during construction of Langley Gulch during
13 the plant's construction period through the use of
14 Construction Work In Progress (CWIP)?
15
16 /
17
18 /
19
20 /
21
22
23
24
25
935 OTTENS, 01 9a
CAPAI
.
10
11
1 A.Though it is an issue unrelated to the merits
2 of Langley Gulch as an appropriate resource, the
3 Company's application itself seems to suggest that if the
4 Commission believes that Langley Gulch should be given
5 rate base assurance for Langley Gulch, then use of the
6 recently enacted legislation granting such assurance is
7 sufficient without the need for immediate recovery
8 through CWIP. CAPAI agrees with this concession.
9 iv. CONCLUSION
Q.Would you please summarize your testimony?
A.The importance of this case is equaled by the
12 magni tude of the proposed investment in Langley Gulch.
.13 Due to budgetary constraints, CAPAI did not retain a
14 technical expert in this case and does not, itself,
15 possess the technical expertise to weigh in on numerous
16 issues raised by those intervenors who argue in favor of
17 deferring a ruling on Langley Gulch until additional
18 information is available. CAPAI does agree with the
19 other intervenors that it is imperative to carefully
20 examine whether such lesser cost alternatives exist and
21 whether they can be implemented in time to meet the
22 estimated point of capacity deficit, whatever that might
23 be. Most of all, CAPAI respectfully asks this Commission
24 to balance the temptation to avoid the distasteful.25 prospect of a capacity deficit against the need to
936 OTTENS, DI 10
CAPAI
.
.
.
1 determine whether the perceived point of load deficit is
2 accurate and whether there are more economical means of
3 avoiding that deficit than Langley Gulch.
4 Q.Does that conclude your testimony?
5 A.Yes, it does.
6
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25
937 OTTENS, DI lOa
CAPAI
.1
2 open hearing.)
(The following proceedings were had in
COMMISSIONER KEMPTON: So you're looking
do you have anything else for the
5 witness, then, at this point? I missed whether you had
3
4 at me like you
MR. PURDY: I said I tender her for
COMMISSIONER KEMPTON: Okay, fine.
10 Mr. Richardson.
11
6 opened her for
7
8 cross-examination.
9
MR. RICHARDSON: I have no questions,
12 Mr. Chairman, and neither does Ms. Ackerman for NIPPC.
13.14
15
16
18
20
21
17 Thank you.
19
COMMISSIONER KEMPTON: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Miller.
MR. MILLER: No questions for Ms. Ottens.
COMMISSIONER KEMPTON: Ms. Bridge.
MS. BRIDGE: No questions.
COMMISSIONER KEMPTON: Mr. Woodbury.
MR. WOODBURY: Staff thanks Ms. Ottens for
22 her testimony and has no questions.
.
23
24
25
COMMISSIONER KEMPTON: Ms. Nordstrom.
MS. NORDSTROM: Yes, thank you.
938 OTTENS
CAPAI
CSB REPORTING
[phone]
.1
2
3 BY MS. NORDSTROM:
4 Q
CROSS-EXAMINATION
Good afternoon, Ms. Ottens.
Good afternoon.
As you state on page 2 of your testimony,
7 you present the views of an expert on the low income
5 A
8 customers of Idaho Power Company. You also advocate for
6 Q
9 low income customers as well; correct?
10 A Correct.
In your opinion, do low income customers
12 want reliable power service?
.
11 Q
I would say yes.
In your opinion, do low income customers
15 want that reliable power service provided at the least
17
18
13 A
14 Q
16 cost possible?
A
Q
19 testimony.
20
Yes.
Let me direct you to page 7 of your
MR. PURDY: Mr. Chair, if I could
21 interrupt, given that Ms. Ottens has an incorrect version
22 of her testimony, may I approach and give her a correct
23 version?
24.25
COMMISSIONER KEMPTON: Yes.
(Mr. Purdy approached the witness.)
CSB REPORTING
[phone]
939 OTTENS (X)
CAPAI
.
.
.
1 THE WITNESS: Go ahead.
2 Q BY MS. NORDSTROM: Directing your
3 attention to lines 13 and 14 of page 7, in that question
4 you seem to imply that Idaho Power is failing to
5 aggressively pursue demand side management programs. Is
6 that what you intended to communicate?
7 A Well, I'm not sure I was saying you were
8 failing to. I think what the question says is that we
9 would like to or the answer is that we would like to make
10 sure that it's being aggressively pursued.
11 Q Are you concerned that Idaho Power is not
12 aggressively pursuing demand side management programs?
13 A Well, yes, we think that there could be
14 more done on a demand side management and I think that is
15 the result of the statistics that we have on how many
16 households actually benefit from the demand side
17 management programs and how many are eligible to
18 benefit.
19 Q Let me direct you to Mr. Pengilly's
20 testimony. Are you familiar with his testimony regarding
21 demand side management programs?
22 A I'm sorry, I don't have it with me,
23 though. I did read it. I have his rebuttal but not his
24 original testimony.
25 MR. WOODBURY: He only had rebuttal.
CSB REPORTING
[phone]
940 OTTENS (X)
CAPAI
.
.
1 THE WITNESS: Oh, there was only rebuttal?
2 MR. WOODBURY: Yes.
3 THE WITNESS: Yeah, I have that here. I
4 have to find it, I'm sorry.
5 Q BY MS. NORDSTROM: That's okay.
6 A Is there a specific question?
7 Q Yeah, page 7.
8 A I don't have it, I'm sorry. Brad?
9 MR. PURDY: I failed to bring a paper
10 copy. Hang on, here's one. Thank you.
11 (Mr. Purdy approached the witness.)
12 THE WITNESS: Thank you. Page 7?
13 Q BY MS. NORDSTROM: Yes. On page 7 of his
14 testimony, Mr. Pengilly testifies that Idaho Power's peak
15 demand reduction at program maturity is expected to be
16 312 megawatts by 2013. He also states that this is 10
17 percent of last year's peak demand and eight percent of
18 forecasted peak demand in 2013. By comparison, are you
19 aware that FERC estimates aggressive expansion of Idaho's
20 programs to be six percent of load by 2014?
21 MR. PURDY: Mr. Chair, I would object to
22 that question on the basis that Ms. Ottens has already
23 answered the question that really led to that which is
24 does she believe that all DSM opportunities are being.25 fully pursued and exhausted. She referred simply to one
CSB REPORTING
[phone]
941 OTTENS (X)
CAPAI
.
.
.
1 which is the proj ect share or, I'm sorry, the low income
2 weatherization program that Idaho Power has in place.
3 She did not expand or proclaim to expand her knowledge or
4 expertise to FERC documents and the greater issue of DSM.
5 COMMISSIONER KEMPTON: I don't think the
6 question is a reflection on the witness. It's simply a
7 question as to whether she knows that or whether she
8 doesn't know and I think that the question is perfectly
9 correct for this environment.
10 MR. PURDY: Thank you.
11 COMMISSIONER KEMPTON: The obj ection is
12 overruled.
13 THE WITNESS: So my answer is I was not
14 fully aware of that fact.
15 Q BY MS. NORDSTROM: By that measure, it
16 would seem that Idaho Power's peak load demand side
17 management programs are quite aggressive by FERC' s
18 estimation, wouldn't you agree?
19 MR. PURDY: Well, Mr. Chair, again, maybe
20 I need to ask for a standing objection to this line of
21 questioning, but now we're going from do you know this or
22 were you aware of something to, well, now that you don't
23 know it, can we go ahead and make some suppositions or
24 some presumptions or conclusions based on it and that is
25 very definitely going outside her stated area of
CSB REPORTING
[phone]
942 OTTENS (X)
CAPAI
.1 expertise in all of this.
2 COMMISSIONER KEMPTON: Ms. Nordstrom,
3 where were you intending to go with your line of
4 questioning?
5 MS. NORDSTROM: I was just trying to
6 compare her definition of aggressive pur sui t of demand
7 side management versus the FERC' s.
8 COMMISSIONER KEMPTON: As averse to her
9 testimony or as averse to how she wrote this in her
10 direct testimony?
11
12
BY MS. NORDSTROM: Both.
COMMISSIONER KEMPTON: In the direct
.13 testimony, it's a question. In the case of the
14
.
testimony, you elicited a direct answer, so there's a
15 mix. I think that the fact that she's asked these as
16 questions in her testimony, it's filed, is sufficient to
17 the obj ecti ve that you have, so I'm going to sustain the
18 motion on that line of questioning only.
19 MS. NORDSTROM: I think I've got ten my
20 point across. Thank you, no further questions.
21 COMMISSIONER KEMPTON: Commissioner
22 Redford.
23 COMMISSIONER REDFORD: I have no
24 questions.
25 COMMISSIONER KEMPTON: Commissioner Smith.
CSB REPORTING
[phone]
943 OTTENS (X)
CAPAI
.1 COMMISSIONER SMITH: No questions.
2 COMMISSIONER KEMPTON: And the Chair has
3 no questions. Redirect.
4 MR. PURDY: Just one on redirect.
5
6 REDIRECT EXAMINATION
7
8 BY MR. PURDY:
9 Q It was brought up, as I alluded to, the
10 Company's low income weatherization assistance program.
11 Could you just very, very briefly give us an idea, you
12 indicated that it was not being perhaps fully exploited
.
.
13 or taken advantage of, can you give us an idea to what
14 extent that's the case?
15 Well, I can say that we had approximatelyA
16 10,000 households, not in Idaho Power territory but
17 around the state, that were eligible for weatherization.
18 Only 1,500 were actually weatherized and I do have the
19 Idaho Power -- well, at least the agency statistics here,
20 but I think the same percentage applies to the Idaho
21 Power territory that there are homes that are eligible
22 for this program and not enough resources being applied
23 to meet the program's needs.
24 MR. PURDY: Thank you, Mr. Chair, that's
25 all I have. Thank you, Ms. Ottens.
CSB REPORTING
[phone]
944 OTTENS (Di)
CAPAI
.1 COMMISSIONER KEMPTON: If there is no
2 objection, the witness may step down.
3 THE WITNESS: Thank you.
4 (The witness left the stand.)
5 COMMISSIONER KEMPTON: Mr. Olsen.
6 MR. OLSEN: Thank you, Mr. Chairman. The
7 Idaho Irrigation Pumpers Association would like to call
8 to the stand Mr. Anthony Yankel.
9 MR. PURDY: And while he approaches, may
10 Ms. Ottens be excused?
.
.
11 COMMISSIONER KEMPTON: Yes.
12 MR. PURDY: Thank you.
13
14 ANTHONY YANKEL,
15 produced as a witness at the instance of the Idaho
16 Irrigation Pumpers Association, having been first duly
17 sworn, was examined and testified as follows:
18
19 DIRECT EXAINATION
20
21 BY MR. OLSEN:
22 Q Mr. Yankel, can you please state your name
23 and spell your last name for the record and give us your
24 address?
25 A Anthony Yankel, Y-a-n-k-e-l, 29814 Lake
CSB REPORTING
[phone]
YANKEL (Di)Irrigators945
1 Road, Bay Village, Ohio, 44140..2 Q And then who are you employed by?
3 A Yankel and Associates, Incorporated.
4 Q Are you the same Tony Yankel who prefiled
5 direct testimony on June 19th, 2009 in this matter?
6 A Yes.
7 Q And that consisted of 33 pages and no
8 exhibits?
9 A Correct.
10 Q Do you have any corrections to your
11 prefiled testimony?
12 A Yes, I do.
13 Q Could you please go through those slowly.14 so we can track those?
15 A Page 16, line 8, the second to the last
16 word in the line is "in," delete the word "in." Page 23,
17 line 7, near the end of the line there's a word "years,"
18 drop the "s." Page 28, line 6, there is a figure of
19 "91%," it should be "84%." The footnote on the bottom of
20 that page, footnote 15, it would just read clearer if at
21 the end of the first line after the word "and" there was
22 inserted" Idaho Power Company's response." Page 2 9, line
23 5, the figure of "91%" percent should be "84%."
24 COMMISSIONER KEMPTON: Should be what?.25 THE WITNESS: "84%."
CSB REPORTING
[phone]
946 YANKEL (Di)Irrigators
.
.
20
.
1 COMMISSIONER KEMPTON: Okay.
2 THE WITNESS: Also on page 29, line 20,
3 there's a sentence there at the second half of the line,
4 "This problem did not exist in the 2006 IRP," there
5 should be a period and the rest of the sentence dropped.
6 Those are all the corrections I'm aware of.
7 Q BY MR. OLSEN: Okay. Well, with those
8 corrections, if I were to ask you those same questions
9 today, would your answers be the same?
10 A Yes, they would.
11 MR. OLSEN: Mr. Chair, I move to spread
12 Mr. Yankel' s testimony on the record as if read here
13 completely and tender the witness for
14 cross-examination.
15 COMMISSIONER KEMPTON: Without obj ection,
16 so ordered.
17 (The following prefiled direct testimony
18 of Mr. Anthony Yankel is spread upon the record.)
19
21
22
23
24
25
CSB REPORTING
[phone]
947 YANKEL (Di)Irrigators
.
.
.
1 Q.PLEASE STATE YOUR NAME, ADDRESS, AND
2 EMPLOYMENT.
3
4 A.I am Anthony J. Yankel. I am President of
5 Yankel and Associates, Inc. My address is 29814 Lake
6 Road, Bay Village, Ohio, 44140.
7
8 Q.WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL
9 BACKGROUND AND PROFESSIONAL EXPERIENCE?
10
11 A.I received a Bachelor of Science Degree in
12 Electrical Engineering from Carnegie Institute of
13 Technology in 1969 and a Master of Science Degree in
14 Chemical Engineering from the University of Idaho in
15 1972. From 1969 through 1972, I was employed by the Air
16 Correction Division of Universal Oil Products as a
17 product design engineer. My chief responsibilities were
18 in the areas of design, start-up, and repair of new and
19 existing product lines for coal-fired power plants. From
20 1973 through 1977, I was employed by the Bureau of Air
21 Quali ty for the Idaho Department of Health & Welfare,
22 Division of Environment. As Chief Engineer of the
23 Bureau, my responsibilities covered a wide range of
24 investigative functions. From 1978 through June 1979, I
25 was employed as the Director of the Idaho Electrical
948 Yankel, DI 1Irrigators
.
.
20
21
22
23
24.25
1 Consumers Office. In that capacity, I was responsible
2 for all organizational and technical aspects of
3 advocating a variety of positions before various
4 governmental bodies that represented the interests of the
5 consumers in the State of Idaho. From July 1979 through
6 October 1980, I was a partner in the firm of Yankel,
7 Eddy, and Associates. Since that time, I have been in
8 business for myself. I am a registered Professional
9 Engineer in the states of Ohio and Idaho. I have
10 presented testimony before the Federal Energy Regulatory
11 Commission (FERC), as well as the
12
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949 Yankel, DI 1aIrrigators
.1 State Public Utility Commissions of Idaho, Montana, Ohio,
2 Pennsyl vania, Utah, and West Virginia.
3
4 Q.ON WHOSE BEHALF ARE YOU TESTIFYING?
5
6 A.I am testifying on behalf of the Idaho
7 Irrigation Pumpers Association, Inc. (Irrigators).
8
9 Q.WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
10 PROCEEDING?
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
A.My testimony will address:
Idaho Power's (IPCo or Company) forecasted
load that serves as a basis for the
percei ved need of the Langley Gulch
facili ty by December 1, 2012;
The economic change that has occurred
since the forecasted loads were
established that were used to justify
Langley Gulch;
The Company's recent round of updated
forecasts;
System impacts if Langley Gulch is
postponed; and
How the new Company-Option Irrigation Peak
Rewards Program will further reduce peak
950 Yankel, DI 2Irrigators
1 demand requirements on the system..2
3 Q.WHAT ARE YOUR CONCLUSIONS IN THIS CASE?
4 A.I make the following conclusions:
5 The decision to build Langley Gulch was
6 based upon data that is now outdated and
7 thus inappropriate;
8
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17
18
19
20
21
22
23
24.25
951 Yankel,DI 2aIrrigators
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1 There has been a significant economic
2 downturn since the Company developed its
3 load forecast data upon which its decision
4 to build Langley Gulch was based;
5 Given the recent quarterly economic
6 forecasts made by the Idaho Division of
7 Financial Management, the growth
8 proj ections are such that Idaho Power
9 likely will not encounter the forecasted
10 loads that Idaho Power relied upon to
11 justify the need for Langley Gulch in the
12 time frame set out in this case;
13 The data in the Company's three new
14 forecasts have been only recently offered
15 wi thout support or explanation for peer
16 review. Not only are these new forecasts
17 not aligned with the economic downturn,
18 but they are internally inconsistent and
19 ignore the ability to import energy (as
20 opposed to peaking capacity) on the
21 system;
22 There will be no adverse impact if Langley
23 Gulch is postponed for 10 months, which is
24 effecti vely what the Company did when it
25 moved the on-line date of Langley Gulch
952 Yankel, 01 3Irrigators
.1
2
3
4
5
6
7
8
9
10 Q.
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18
19
20
21
22
23
24
25
from June 1 to December 1, 2012;
The new Irrigation peak rewards program
will significantly reduce summer peak
demand; thus, further postponing the
requirement for additional generation; and
There is no need for Langley Gulch in the
timeframe proposed by the Company in this
case.
WHAT ARE YOUR RECOMMENDATIONS IN THIS CASE?
.
.
953 Yankel, 01 3aIrrigators
.1 A.Idaho Power has stated that it will be
2 developing a new load forecast later this year. Gi ven
3 the expected reductions in load growth, there may also be
4 changes in the Company's overall Integrated Resource Plan
5 (IRP), which may further impact the need to construct
6 Langley Gulch. For these reasons, I recommend that the
7 Commission postpone any decision on the issuance of a
8 Certificate of Public Convenience and Necessity for at
9 least 10 months or until IPCo has updated its load
10 forecast and all parties have had an opportunity to
11 review and comment on that data.
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22
23
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25
954 Yankel, 01 4Irrigators
.
.
.
1 COMPANY'S JUSTIFICATION FOR LAGLEY GULCH
2 (2006 IRP AN 2008 UPDATED IRP)
3
4 Q.UPON WHAT BASIS DOES IDAHO POWER JUSTIFY ITS
5 NEED FOR AND THUS ITS REQUEST FOR A CERTIFICATE OF
6 CONVENIENCE AND NECESSITY FOR LANGLEY GULCH?
7 A.Primarily, the Company bases its need for
8 Langley Gulch on the results of its 2006 IRP as well as
9 its 2008 Updated IRP. Essentially, it is the Company's
10 position that the loads that are found in the 2006 IRP
11 and the 2008 Updated IRP are best matched by the
12 resources in the 2008 Updated IPR, which includes a 300
13 MW combined cycle gas turbine such as Langley Gulch.
14 My testimony will focus on the "need aspect" of
15 the plant and more specifically changes in the Company's
16 load/resource balance since the 2006 IRP and the 2008
17 Updated IRP. I will address the forecasted load growth
18 that Langley Gulch is proposed to meet/offset. I will
19 also address the Company's new load/resource balances as
20 they relate to the need for Langley Gulch. I will not
21 address the type of resource that could be developed.
22
23 Q.WILL LANGLEY GULCH SERVE BASE LOAD OR PEAK
24 REQUIREMENTS?
25 A.Generally speaking, Langley Gulch is capable of
955 Yankel, 01 5Irrigators
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10 /
11
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.
1 serving both peak as well as base or the energy
2 requirements of the system. However, a combined cycle
3 plant is a plant that is designed (from a cost
4 standpoint) to focus more on supplying an energy need as
5 opposed to a peaking requirement. The Company has
6 focused most of its attention on the fact that Langley
7 Gulch will be serving a base load requirement and that it
8 is supposed to operate at a high
9
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16
17
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19
20
21
22
23
24
25
956 Yankel, DI SaIrrigators
.1 capacity factor. The Company's 2008 Updated IRP shows
2 very little peaking requirements in the near-term. The
3 most recent updates to IRP data show even less of a need
4 for peaking capacity. i
5
6 Q.IN THIS CASE, ARE THERE ANY SPECIFIC
7 INACCURACIES THAT YOU WISH TO ADDRESS WITH RESPECT TO THE
8 FORMULATION OF THE 2006 IRP OR THE 2008 UPDATED IRP?
9 My testimony does not address inaccuracies inA.
10 these two IRP' s, but it addresses the appropriateness of
.
.
11 using these IRP' s in an economic environment that has so
12 drastically changed since the time that those IRP' s were
13 developed. Essentially, the IRP' s are an attempt to
14 match resources with forecast load. Over the near term
15 (the time it will take to build Langley Gulch), the
16 growth in load has greatly changed to the point where
17 Langley Gulch will not be needed in the timeframe
18 specified by the IRP' s.
19
20 WHAT WERE THE GROWTH PROJECTIONS AND THUS THEQ.
21 LOAD FORECAST IN THE 2006 IRP?
22 According to page 11 of the 2006 IRP, theA.
23 Company's load was expected to increase an average of 40
24 aMW per year through 2025 and the total number of retail
25 customers was expected to increase from 11,000-12,000 per
957 Yankel, 01 6Irrigators
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10
11
12
13.14
.
1 The number of residential customersyear through 2025.
2 was projected to increase from 8,600-10,700 customers per
3 year between
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15
16
17
18
19
20
21
22 i Later in my testimony, I will address the new, Company Option Peak
Rewards Program for the Irrigators that is not included in the 2008
Updated IRP and was not fully included in the more recent update.
This Company Option program will further reduce peaking requirements
below those last addressed in any of the 2009 IRP data. For these
reasons, my testimony will primarily address Langley Gulch on an
energy as opposed to a peak load basis.
23
24
25
958 Yankel, DI 6aIrrigators
.1 2006 and 20132. Commercial customers were proj ected to
2 increase from 1,500-1,800 per year between the 2006 and
3 2013 planning horizon3. The overall system load was
4 projected to increase between 22 and 37 aMW per year over
5 the 2006-2013 timeframe4.
6
7 Q.WHAT DOES THE 2008 UPDATED IRP STATE ABOUT WHY
8 GENERATION RESOURCES MUST BE ADDED TO THE SYSTEM?
9 Absent additional conservation and/or DSMA.
10 programs, the Company's 2008 Updated IRP states5 the
11 obvious:
12
.
.
13
Customer growth is the primary factor leading to
Idaho Power's need for additional resources.
Population growth throughout southern
Idaho-specifically in the Treasure Valley-requiresaddi tional resources to meet both the instantaneous
peak and the sustained energy needs of the new
customers.
14
15
16
17 Q.WHAT WERE THE GROWTH PROJECTIONS AND THUS THE
18 LOAD FORECAST IN THE 2008 UPDATED IRP?
19 A.The 2008 Updated IRP projected more customer
20 growth than did the 2006 IRP-at between 12,500 and 13,000
21 total customers per year. At page 10 of the 2008 Updated
22 IRP it states:
23 Figure 1 shows a comparison of the 2006 and 2008
updated customer forecasts. Figure 1 shows that
there will be a greater number of retails customers
than were forecast in the 2006 IRP-nearly 26,000
more retail customers by 2027. The additional
24
25
959 Yankel, DI 7Irrigators
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13 /.
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1 26,000 more retail customers represent a change in
total customers of almost 4 % by the end of the
20-year planning period.2
3 Somewhat offsetting this growth in the number of
4 customers, the 2008 Updated IRP demonstrates that at the
5 end of the 20-year planning period that DSM and increases
6 in retail electric prices results in reductions in the
7 use per customer such that the overall energy usage at
8
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16
17
18
19
20
21
22
23
24 2 See 2006 IRP, Appendix A, page 26.3 See 2006 IRP, Appendix A, page 28.
25
960 Yankel, 01 7aIrrigators
.1 the end of the 20-year planning horizon is less in the
2 2008 Updated IRP than in the 2006 IRP. However, this is
3 after the 20-year planning period, but not what is
4 forecasted to occur during the early years of the
5 planning period.
6
7 Q.HOW DOES THE OVERALL FORECASTED SYSTEM LOAD IN
8 THE 2008 UPDATED IRP COMPARE TO THE OVERALL FORECASTED
9 SYSTEM LOAD FOR THE FIRST SEVERAL YEARS OF THE PLANNING
10 PERIOD?
11
.
.
A.During the next several years (when the need
12 for Langley Gulch is claimed to develop), the two IRP' s
13 contain the following forecasts for expected system
14 sales:
15 2008
Update
MWH
14,773,134
15,318,384
15,588,906
15,817,567
15,934,177
Change
-0.6%
1. 2%
1. 1%
1.2%
0.6%
16
2006 IRP
MWH
14,855,104
15,134,273
15,424,917
15,636,244
15,831,635
17
2008
2009
2010
2011
2012
18
19
20 Q.HOW DOES THE FORECASTED RESIDENTIAL LOAD IN THE
21 2008 UPDATED IRP COMPARE TO THE FORECASTED RESIDENTIAL
22 LOAD FOR THE FIRST SEVERAL YEARS OF THE PLANNING PERIOD?
23 A.Like the total system load, the forecasted
24 Residential load in the 2008 Updated IRP is greater than
25 in the 2006 IRP. During the next several years (when the
961 Yankel, DI 8Irrigators
1 need for Langley Gulch is claimed to develop),the two.2 IRP's contain the following forecasts for expected
3 Residential sales:
4
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9 /
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25 4 See 2006 IRP, Appendix 0, page 44.
962 Yankel,DI 8aIrrigators
.1 2008
Update
MWH
5,406,449
5,519,177
5,607,822
5,704,610
5,759,539
Change
2.5%
2.9%
2.6%
3.2%
3.6%
2
2006 IRP
MWH
5,273,003
5,364,603
5,464,619
5,525,263
5,561,958
3
2008
2009
2010
2011
2012
4
5
6
7 Q.WHEN WERE THE LOAD FORECASTS DEVELOPED FOR THE
8 2006 IRP AND THE 2008 UPDATED IRP?
9 A.October 12, 2006 is listed as the date the
10 revised 2006 IRP was issued. This is the date of the
11 2006 IRP publication itself, but not the specific date
12 when the forecast data was formulated that went into the
.13 entire IRP. In fact, the forecast load data for that IRP
14 was developed at least a year prior to that revision
15 date6.
16 Likewise, the 2008 Updated IRP was issued on June
17 25, 2008, but the customer projections and load
18 projections were updated in August 2007, almost a year
19 before the updated IRP was issued7. Thus, the load data
20 in each of these IRP's can be considered somewhat stale,
21 but usable in an environment that is not undergoing major
22 upheavals. However, under the circumstances that have
23 existed over the last year and a half, these historic
24 proj ections are essentially worthless..25
963 Yankel, 01 9Irrigators
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22
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9
10
11
12
13
23 5 IPCo's 2008 Integrated Resource Plan Update page 9.
6 The date provided in response to Staff Request 2 suggests that the
24 forecasted load data came from at least as far back as October 26,
2006.
7 See 2008 Integrated Resource Plan Upodate, page 9..25
964 Yankel, 01 9aIrrigators
.
.
.
1 CHAGE IN ECONOMIC OUTLOOK
2
3 Q.ALTHOUGH THERE MAY BE A HOST OF ANTIDOTAL
4 EVIDENCE THAT THE ECONOMY IS SLIPPING AND GROWTH ON THE
5 IDAHO POWER SYSTEM MAY BE GREATLY REDUCED, WHAT HARD
6 EVIDENCE IS THERE TO DEMONSTRATE A MAJOR ECONOMIC SHIFT
7 HAS AND is TAKING PLACE?
8 A.There are a couple of documents that quickly
9 put into perspective how severe the recent economic
10 downturn has been and how it has impacted Idaho Power's
11 customer count and loads. In the Company's response to
12 The Industrial Customers of Idaho Power's Request 19,
13 there is contained a listing of the Company's actual
14 customer count during 2007 and 2008. Although the 2006
15 IRP forecasted an increase during 2008 in its Residential
16 customer count of 10,4238, the Residential customer count
17 only increased 3,736 customers between 2007 and 2008.
18 The economic slowdown resulted in Idaho Power acquiring
19 6,687 fewer Residential customers compared to that
20 projected in the 2006 IRP. Only 35% of the forecasted
21 2008 growth in the Residential customer count actually
22 occurred.
23 That same data response contained the actual
24 Commercial customer count during 2007 and 2008. The
25 Commercial customer count only increased 1,360 customers
965 Yankel, DI 10Irrigators
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.
.
1 between 2007 and 2008. By contrast, the forecasted
2 increase in the Commercial customer count found in the
3 2006 IRP (based upon forecast data from 2005) predicted
4 an increase of 1,785 customers9. The economic slowdown
5 resulted in Idaho Power acquiring 425 fewer Commercial
6 customers compared to that projected in the 2006 IRP.
7
8 /
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14
15
16
17
18
19
20
21 8 See 2006 Integrated Resource Plan, Appendix A, page 26.
22
23
24
25
966 Yankel, 01 lOaIrrigators
.1 Q.WHAT is THE IMPACT OF THE REDUCTION IN LOAD
2 FROM THESE CUSTOMERS NOT COMING ON TO THE SYSTEM IN 2008?
3 A.The Company's 2006 IRP put the weather
4 normalized Residential usage for 2008 at 12,632 kWh per
5 customer. With 6,687 Residential customers not
6 materializing, this translates into 84,500 MWH that did
7 not need to be generated because of the impact upon the
8 Residential customer count in 2008 alone.
9 Likewise, the 2006 IRP put the weather
10 normalized Commercial usage for 2008 at 64,834 kWh per
.
.
11 customer. With 425 Commercial customers not
12 materializing, this translates into 28,000 MWH that did
13 not need to be generated because of the impact upon the
14 Commercial customer count in 2008 alone. When the loss
15 of both new Residential and new Commercial customers in
16 2008 are combined, approximately 100,000 MWH less
17 electrici ty needs to be generated over the year.
18
19 Q.WERE THE DECREASES IN CUSTOMER COUNT
20 PROJECTIONS BECAUSE OF THE PRESENT ECONOMIC CONDITIONS
21 FACTORED INTO THE 2008 UPDATED IRP?
22 No. As pointed out above, the actual customerA.
23 count and forecast information that went into the 2008
24 Updated IRP were actually from August 2007-before the
25 downturn began. Although the impact of the economic
967 Yankel, 01 11Irrigators
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.
1 downturn upon customer count and load was not factored
2 into the 2008 Updated IRP, there was a brief mention of a
3 downturn in the write-up itself. The 2008 Updated IRP
4 merely stated on page 10:
5 The recent cyclical slowdown in customer growth, as
indicated in the total number of customers for year
6 end 2007 is approximately three tenths of a percent
7 /
8
9 /
10
11 /
12
13
14
15
16
17
18
19
20
21
22
23
24
25 9 See 2006 Integrated Resource Plan, Appendix A, page 28.
968 Yankel, DI 11aIrrigators
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1
2
lower than forecast (0.3%). The effect of the
cyclical downturn on the longer term trend will be
evaluated for the 2009 IRP.
3 Thus, neither the forecast load data for the 2006 IRP nor
4 the 2008 Updated IRP reflect any major economic change.
5 As pointed out above, the 2008 Updated IRP even showed an
6 increase in usage over the first several years of the
7 planning horizon, which seemed to have still been the
8 Company's expectation regarding growth around the time
9 that the 2008 Updated IRP was issued. The obvious
10 concern here is the fact that the decision to build
11 Langley Gulch was predicated upon the 2006 IRP as well as
12 the 2008 Updated IRP-neither of which reflect the
13 significant downturn in the economy, new customer counts,
14 and ultimately Idaho Power's anticipated load.
15
16 Q.ARE THERE OTHER SOURCES OF DATA THAT
17 DEMONSTRATE HOW THE IMPACT OF THIS SIGNIFICANT ECONOMIC
18 DOWNTURN HAS OR IS EXPECTED TO IMPACT IDAHO POWER'S
19 FORECASTED NEW CUSTOMER GROWTH?
20 A.Yes, there is. The average number of customers
21 added annually to the Idaho Power system over the ten
22 year period 1998-2007 was 11,869. As pointed out above,
23 both the 2006 IRP and the 2008 Updated IRP (upon which
24 the Langley Gulch decision was based) projected increase
25 customer growth at 11,000-12,000 customers per year (at
969 Yankel, 01 12Irrigators
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13
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20
21
22
23
24
25
1 historic levels) in the case of the 2006 IRP, or at
2 12,500-13,000 customers per year (above historic levels)
3 in the case of the 2008 Updated IRP.
4 For comparative purposes, a publicly available
5 source of data that comes out quarterly is the Idaho
6 Economic Forecast issued by the State's Division of
7 Financial Management. This is the State of Idaho's
8 official economic forecast. This report contains both
9 historic as well as forecasted demographic data. The
10 report only contains demographic data for Idaho as a
11 whole, but the Idaho Power service area covers the major
12 part of the State and its demographics would
/
970 Yankel, DI 12aIrrigators
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1 generally not be that different than the State's
2 demographics as a whole. The Idaho Economic Forecast
3 contains data regarding housing starts, which is closely
4 akin to new Residential customer growth. I do not offer
5 this data as a replacement for the Idaho Power data, but
6 as a basis for demonstrating what may have happened, had
7 Idaho Power properly updated its forecast data with what
8 is now known to be a maj or economic downturn.
9 The average historic housing starts reported by the
10 Idaho Economic Forecast over the ten year period
11 1998-2007 was 14,956 units per year. In July 2007, the
12 Idaho Economic Forecast projected the following level of
13 future housing starts:
14 2008
2009
2010
16,608
17,350
18,31115
16 Essentially, the Idaho Economic Forecast in July 2007
17 proj ected over the next three years an average10 of 16.5%
18 more housing starts than the ten year historic
19 average-similar to the August 2007 forecast of an
20 increase in the rate of customer growth that was used by
21 Idaho Power in its 2008 Updated IRP. Generally speaking,
22 during the summer of 2007, both Idaho Power's forecast
23 data and the Idaho Economic Forecast were making similar
24 projections.
25
971 Yankel, DI 13Irrigators
.
.
20
21
22
23
1 Q.HOW DID IDAHO'S ECONOMY OUTLOOK CHANGE SINCE
2 JULY 2007?
3 A.According to the Idaho Economic Forecast, the
4 outlook for Idaho i s economy went into a downward spiral
5 after the summer of 2007. A few quotes from several of
6 these quarterly reports will give a flavor of what is
7 well known:
8 October 2007 Executive Summary: The Idaho economic
outlook has been ratcheted down slightly since this
9 summer. This adjustment reflects the third time
this year we have reduced our employment forecast.
10
11
12 /
13
14 /
15
16 /
17
18
19
24 10 The average housing starts for these three years is 17,423..25
972 Yankel, DI 13aIrrigators
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.
.
16
17
18
19
1
2
April 2008 Executive Summary: Idaho's economic
outlook has been scaled back compared to the January
2008 Idaho Economic Forecast. This change largely
resul ts from the anticipated weaker showing for the
national economy. There are about 7,800 fewer Idaho
jobs in 2008 in the current forecast compared to the
previous one. This gap grows each of the next three
years...
3
4
5
6
July 2 008 Executive Summary: The outlook for
Idaho's economy has been scaled back to reflect more
current Idaho historical data and the revised
national forecast. A review of new employment data
shows the state's economy grew slower during the
first part of this year than had been anticipated in
April 2008.
7
8
9
10
October 2008 Executive Summary: The next few years
will be even more challenging for the Idaho economy
than had been previously thought.
11
12
January 2009 Executive Summary: A review of Idaho's
economic performance last year shows why we are glad
it is behind us. The preponderance of evidence
shows it was one of the worst years in memory. ... The
bad news is this year is expected to be worse than
last year. ... The economy is expected to begin
moving forward in 2010, but the recovery will be
modest.
13
14
15
April 2009 Executive Summary: This Idaho Economic
Forecast lends credence to the adage that bad news
comes in threes. After several years of strong
growth, Idaho's economy shrank last year, and it is
expected to turn in disappointing performances in
both this year and next.
20 Unlike this publicly available forecast that is updated
21 every quarter (and that followed the downturn and the
22 degree of the downturn as it occurred), Idaho Power's
23 2006 IRP and its 2008 Updated IRP have not incorporated
24 any of the significant economic impacts of recent events.
25 Langley Gulch was conceived under a very different set of
973 Yankel, DI 14Irrigators
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13 /.14
15 /
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17
18
19
20
21
22
23
24.25
1 assumptions than exists today. Although we all hope for
2 a turnaround in the economy (that may require future
3 resources), the present timing of Langley Gulch is
4 out-of-sync with the present reality.
5
6 Q.CAN THE IDAHO ECONOMIC FORECAST BE USED TO
7 DEMONSTRATE HOW FAR OFF THE IDAHO POWER SUMMER OF 2007
8 FORECASTED LOAD GROWTH MAY BE FROM WHAT is OCCURRING
9 TODAY?
10
11 /
12
974 Yankel, DI 14aIrrigators
.
.
1 A.Both the Idaho Economic Forecast and the
2 forecast used by Idaho Power were in sync during the
3 summer of 2007. The only real difference is that the
4 Idaho Economic Forecast has been updated quarterly, while
5 the Company used the summer of 2007 load forecast
6 information as the basis for its decision to build a
7 natural gas-fired CCT located close to its Treasure
8 Valley load11. In order to demonstrate an order of
9 magnitude change in Idaho Power's proj ected growth, one
10 can simply look at the overall percentage of change in
11 the forecasted and actual results found in the Idaho
12 Economic Forecast.
13 As stated above, the average historic housing
14 starts reported by the Idaho Economic Forecast over the
15 ten year period 1998-2007 was 14,956 units per year.
16 Also as stated above, in July 2007, the Idaho Economic
17 Forecast proj ected that the housing starts in the State
18 would be 16.5% greater than this 10-year historic
19 average. Reality fell far below these proj ections for
20 2008 and the forecast for the future has been greatly
21 revised downward12:
.
22
23
24
25
2008
2009
2010
2011
2012
7,940 (actual)
5,713
8,445
10,274
13,070
The average housing start (actual or forecast) over this
975 Yankel, 01 15Irrigators
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17
18.
19
20
21
22
23
1 five year period is 9,088 per year, or only 61% of the
2 10-year historic period 1998-2007. This is a reduction
3 of 39% of the growth proj ections that were made during
4 the summer of 2007. As an order of magnitude estimate,
5 one could assume that Idaho Power's summer of 2007 growth
6 forecast fell by a similar amount.
7
8 Q.HOW CAN THIS ORDER OF MAGNITUDE REDUCTION BE
9 USED TO ESTIMATE THE IMPACT UPON IDAHO POWER'S LOAD
10 GROWTH PROJECTIONS?
11
12 /
13
14 /
15
16 /
24 11 See Response to Staff Request 2.
12 Idaho Economic Forecast April 2009, page 33.
25
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24.25
1 A.The Company's load levels in its 2008 Updated
2 IRP (upon which the decision to build Langley Gulch is
3 based) projected an increase in average usage between
4 2007 and 2012 of 187 average megawatts13. If 39% of this
5 growth does not take piàce (as in keeping with the
6 changed growth forecast in the Idaho Economic Forecast),
7 then approximately 73 aMW will not be required at the end
8 of 2012, when Langley Gulch is expected to begin
9 operation. This reduction in growth would place the load
10 requirement at 1,924 aMW, where the Company's 2008
11 Updated IRP places the load for 2009. The lack of
12 adjusting Idaho Power's IRP load forecasts for any of the
13 downturn in the state and national economies that has
14 taken place results in the the need for Langley Gulch
15 being postponed several years.
16
17 /
18
19 /
20
13 Page 11 of the Updated IRP list under the 70th Percentile
condition a 2012 load of 1,997 aMW and an actual 2007 load of 1,810
aMW for a difference of 187 aMW.
977 Yankel, DI 16Irrigators
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1 ADDITIONAL FORECAST UPDATES
2
3 Q.HAS IDAHO POWER UPDATED ITS LOAD FORECASTS
4 SINCE THE SUMMER OF 2007?
5 A.There was a load forecast prepared in September
6 2008 that served as the basis for what has been referred
7 to as the 2009 IRP. It should be noted that this 2009
8 IRP was never finalized by the Company or
9 approved/accepted by the Commission. In fact, the
10 Company is not planning to present to the Commission this
11 IRP, but a different one to be filed in December 2009.
12 In response to Request 20 of the Industrial Customers of
13 Idaho Power, it was indicated that the Company made
14 adj ustments to its load proj ections (prepared in
15 September 2008) in December 2008. Other than general
16 statements such as "the decision was made to adjust the
17 residential and commercial sectors to reflect a prolonged
18 slowdown in housing and consumer spending", the response
19 gave very little detail regarding this December 2008
20 adj ustment in the load forecast.
21 Presumably this lack of detail is based upon
22 the fact that the Company recognizes the need to further
23 update its forecast. The Response went on to state:
24 Currently, the load forecasting area is working
on developing a new load forecast that will be
available in late summer of 2009. The load25
978 Yankel, 01 17Irrigators
.1 forecast will be reflective of the most current
economic forecast drivers, the most recent
input from the Company's large power
representatives and their contracts, energy
efficiency impacts, and the latest forecast of
retail electricity prices.
2
3
4
5 According to the Company's response to Staff
6 Request 85, the Company "has prepared a number of updated
7 load forecasts since the 2006 IRP was published." Three
8 specific updates were mentioned in this data response
9 that the Company has chosen to share: 1) a September 2008
10 forecast that was used for the 2009 IRP; 2) a December
11 2008 update which addressed Residential and Commercial
12 loads; and 3) a May 2009 update that changed the forecast
13.
20
21
22
.
loads for special
14
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19 /
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24
25
979 Yankel, DI 17aIrrigators
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1 contract customers "as part of preparing the newest load
2 forecast, which is expected to be completed in late
3 summer 2009." (Emphasis Added)
4
5 Q .WAS THE DECISION TO BUILD LANGLEY GULCH BASED
6 UPON ANY OF THESE UPDATED FORECASTS?
7 A.No. As previously stated, the decision to
8 build Langley Gulch was based upon the 2006 IRP and the
9 2008 Updated IRP and not these updated load forecasts.
10 The December 2008 and May 2009 updated load forecasts
11 (which are still to be further updated) were first
12 mentioned with respect to this case in response to
13 Request 20 of the Industrial Customer of Idaho Power
14 (ICIP) that was issued on May 11, 2009. Upon further
15 questioning by Staff Requests 84 and 85 (in order to seek
16 more information regarding the Response to ICIP Request
17 20), the Company supplied more data, and more discussion
18 that included when the 2009 IRP forecast was developed,
19 and what the forecasted loads were in the 2009 IRP
20 (forecast in September 2008), the December 2008 update,
21 and the May 2009 update. Responses to Staff Requests 84
22 and 85 were sent out on June 4th and June 5th
23 respectively. Intervenor testimony was due two weeks
24 later. Basically, there has been very limited time for
25 peer review.
980 Yankel, DI 18Irrigators
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14
15
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21
22
23
24
25
1 Q.ARE THERE ANY GENERAL OBSERVATIONS YOU HAVE
2 MADE WITH RESPECT TO THE FORECAST VALUES FOUND IN THE
3 2006 IRP, THE 2008 UPDATED IRP, THE 2009 IRP, AND THE
4 DECEMBER 2008 AND MAY 2009 UPDATE?
5 A.As pointed out above, Idaho and the nation has
6 been in a severe economic downturn since the end of 2007
7 or the beginning of 2008. Even Idaho Power's 2008
8 Updated IRP recogni zed that there was a:
9
/
981 Yankel, 01 18aIrrigators
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1
2
recent cyclical slowdown in customer growth, as
indicated in the total number of customers for
year end 2007 ... The effect of the cyclical
downturn on the longer term trend will be
evaluated for the 2009 IRP.143
4 Because the economic downturn occurred after the forecast
5 loads were developed for the 2006 IRP (developed in
6 October 2005) and the 2008 Updated IRP (developed in
7 August 2007), one would not expect that these forecasts
8 would contain information that would reflect the economic
9 slowdown. However, the 2009 IRP (based upon a September
10 2008 forecast) as well as the December 2008 update,
11 should have shown these changes. Contrary to this
12 expectation, the table below demonstrates that the
13 Company's 2009 IRP (September 2008 forecast) and its
14 December 2008 update show additional growth in load
15 during several months, with basically only a minor
16 overall decrease in load (of only 18 aMW) between the
17 data generated in 2005 and that generated at the end of
18 2008:
19
20
21
22
23 /
24
25 /
982 Yankel, DI 19Irrigators
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.
1 forecasts, while contrary to any reasonable expectations,
2 some months have the forecasted load increase.
3 As pointed out above, the 2009 IRP was never
4 finalized by the Company nor submitted to the Commission.
5 It is not only a work in progress, but one that will be
6 abandoned for a new 2009 IRP to be filed in December
7 2009. Likewise, the December 2008 forecast (to my
8 knowledge) has just surfaced during the last two weeks.
9 I am addressing this data, not because of its validity
10 (which seems to be lacking), but simply because it is
11 data provided by the Company that is in addition to the
12 2006 IRP and the 2008 Updated IRP data that was used as
13 the basis to support the decision to pursue Langley
14 Gulch.
15 The drop in annual average load of only 18 aMW
16 between the 2006 IRP and the December 2008 forecast not
17 only greatly falls short of expectations (because of the
18 economic downturn), but the individual monthly changes
19 are very questionable. For example, the December 2008
20 forecast for December 2009 was 83 aMW above that
21 projected in the 2006 IRP or 4.3% greater (in spite of
22 all of the negative economic news). In the days of rapid
23 growth, a 4.3% increase in average load would equate to
24 three years of growth. Presumably this maj or change in
25 forecast is not related to heat load as there was a
984 Yankel, 01 20Irrigators
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21
22
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24.25
1 somewhat large increase in the November forecast, but
2 there were corresponding decreases in February and March.
3 In fact, in the December 2008 forecast the March 2009
4 load decreased by 107 aMW when compared to the 2006 IRP
5 or 6.5%. It is not readily apparent how between
6 forecasts that load in some months could increase 4.3%,
7 while decrease 6.5% in other months.
8 The increase in the December 2008 forecast for
9 July 2009 of 32 aMW (1.3%) over the 2006 IRP is equally
10 puzzling. Why would the forecast for July increase so
11 much during the economic downturn while June and August
12 showed slight decreases in load? Simply, the
13
14 /
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16 /
17
18 /
19
985 Yankel, 01 20aIrrigators
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1 Company's 2008 forecast creates a host of questions and
2 sheds no light on what changes have occurred to the
3 Company's load since the 2006 IRP upon which the Langley
4 Gulch decision was based. Presumably, that is why the
5 Company has announced that its late summer 2009 load
6 forecast (as yet to be completed) will serve as the basis
7 for its new 2009 IRP.
8 In addition to these questions that are raised,
9 the December 2008 forecast is contrary to the reduction
10 that the Company encountered in its growth projections
11 for 2008 alone. As pointed out above, the difference
12 between the 2006 IRP forecasted residential and
13 commercial customer count additions and the actual growth
14 in customer count that occurred in 2008 resulted in
15 approximately 100,000 MWH less sales in 2008 or 11.4 aMW.
16 This is 2/3rd the reduction that the December 2008
17 forecast suggests for 2009 in total. This 11.4 aMW does
18 not reflect reductions in usage by existing customers due
19 to price elasticity, reduction in personal income, and
20 reductions in the goods producing and non-goods producing
21 sectors of the economy. This reflects no change in
22 industrial load during 2008. And then there is 2009
23 where the economic conditions are getting worse, not
24 better. It is possible to explain twice the 18 aMW
25 reduction in the December 2008 forecast by simply the
986 Yankel, 01 21Irrigators
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24.25
1 cumulati ve effect of the reductions in new Residential
2 and Commercial hookups in 2008 and 2009 alone, let alone
3 all of the reductions that may be taking place for the
4 other approximately 98% of the customers that are
5 existing.
6
7 Q.HOW HAS THE OVERALL INCREASE IN RESIDENTIAL
8 CUSTOMER COUNT CHANGED SINCE THE FORECAST LOAD FOR THE
9 2006 IRP WAS DEVELOPED IN OCTOBER 2005?
987 Yankel, DI 21aIrrigators
.1 A.
2
Al though there was a continuation in the rise
of residential customers on an annual basis after the
3 October 2005 forecast was made, the trend started
4 downward in early 2006 and continues well into 2009.
10
11
12
13.14
5
6
7
8
9
16
17
18
19
20
21
22
23
24.25
1--'-'---"--,-
I Annual Increase In Res.identialI Customer Count
I
I
¡
i
¡
i
I
I
i
L
. _.....-._---_..
16,000
14,000
12,000
10,000
8,000
6,000
4,000
2,000
..................~~..H_.a..._..~._...._...._....,.._.._..........._..............
~dddd~~~~~~~~&~~~~~~~~~~~~~~~ ~ .~ ,~ ~ ~ .~ ,~ ~ ~ .~ ,~ ~ ~~ ~'~ ~ ~ ~'~ ~ ~ ~' ~ ~ ~ ~',-0 "v Ii ') ..0 fiv Ii ') ..0 liv ~ ') ,-0 liv0(, \'b.Q~ ....')~ç .. 0(. \'b
.. . ... '. ......;..........~,.*'~~,,¡.;;~.&''''.~¡,
In fact, January and March of 2009 actually showed
decreases in the number of residential customers compared
to the previous month. Certainly none of the increases
that the Company i s December 2008 forecast shows can be
related to a Residential customer count that has
drastically dropped over the last few years.
Q. HOW HAS THE OVERALL INCREASE IN COMMERCIAL
CUSTOMER COUNT CHANGED SINCE THE FORECAST LOAD FOR THE
2006 IRP WAS DEVELOPED IN OCTOBER 2005?
988 Yankel, Dr 22Irrigators
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.
1 A.Like the growth in the Residential customer
2 count, there was a continuation in the rise of Commercial
3 customers on an annual basis after the October 2005
4 forecast was made. The trend started downward in October
5 2007 and continues well into 2009.
6 -_._----".._---.
l7
8
Annual 'ncrease In Commercial
Customer Count
9 3,000
2.50010
11
2,000
1.500
1,000
500
12
13
14
15
~~ ~~ ~~ ~~~ C: ~ C:,"V _\'V .~'V _,'V'2' ~"' f-'" ~..~ ~'l ",-a "v6 ""(;o \"
r; r; r; _r:'b r;'b ~'b ~'b d~C: C: ~ ~ ~ C: ~. C:.~'V _,'V ,'V --'V .~'V ..,'V ,'V --'Vi." ~.. '2.. ~ .. f." ~.. e; :\ "'",ç "V (F ~~ ~ "v(F ~~~ ~ l7 ""~o y
17
18
19
20
21
22
23
24.25
The growth in Residential and Commercial customer counts
has been falling for a long time. Certainly none of the
increases that the Company's December 2008 forecast shows
can be related to a Commercial customer count that has
drastically dropped over the last year and a half. The
Commission should dismiss the mere 18 aMW change in load
from the 2006 IRP found in the Company1s December 2008
forecast.It is simply contrary to the trends that have
989 Yankel, Dr 23
Irrigators
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13.14
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24.25
1 been taking place on the system for at least a year and a
2 half for Commercial customers and for the last three
3 years for the Residential customers. These are changes
4 that will have permanent impacts upon the Company's load.
5 Even if the economy instantly turns around, and the
6 Company starts today to add 12,500-13,000 customers per
7 year as predicted in its 2008 Updated IRP, the recent
8 loss of the new customers thus far will simply postpone
9 (shift) when the increase in customer level/load will
10 occur.
11
/
990 Yankel, 01 23aIrrigators
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24.25
1 Q.HOW HAS THE DECREASED GROWTH IN CUSTOMER COUNT
2 IMPACTED THE OVERALL ENERGY SOLD BY THE COMPANY?
3 A.In isolation, a decrease in the rate of growth
4 of the company's Residential and Commercial sector would
5 lead to a slowdown in the rate of growth of the overall
6 energy consumed on the system. Admittedly, there is a
7 lot more to the overall energy consumption on the system
8 than merely the customer count of the residential and
9 commercial customers. This would include such things as
10 usage per customer and usage of the Company's large,
11 special contract customers. As can be seen from the
12 graph below, growth in the total annual load has not just
13 slowed as the growth in the number of Residential and
14 Commercial customers has, but the overall consumption has
15 actually decreased since June 2008:
16
17 /
18
19 /
991 Yankel, DI 24Irrigators
1
e,.2
3
4
5
6
7
8
9
10
11
r--------_.__..._-
Total Annual MWH x 1000
15,000
14/000
14,500
13,500 ~"'~---'---_~'_"__~M~~~__'____~_____~,__",,,,,_
13,000 ...............-.................................................................................,........"........_............._.__.-......-.......,
12,500
12,000
""Ll Ll Ll Ll i.i.i.i.........00 00 00 00 0'0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0000000000000000000..J N N N N N N N N N N N N N N N N Nt-5 (l ..(l ..'-..(l i.i...(l ......§~c (l (l ~c Q)Q)u C (l ll ~..'-::....::......::....E r;--'"--E E ('..E E '"--E E r;(l ~~Cl Q)~(l Q)~(l (l ~u ã.u ã.u ã.u(l Q)(l llaCl(l a Q)a.u:V"
I....'.......__.,..~._....H...........N........---... -. ,...j.13
14
15 This is a permanent shift from the historic trends which
16 will take time to not only come up to previous levels,
17 but years to go past the previous levels and up to the
18 previous proj ections.
19
20 /
21
22 /
23
24 /.25
992 Yankel, Dr 24aIrrigators
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.14
1 Based upon the above, the Company's December 2008 load
2 forecast is out of step with the realities of the trends
3 in usage and number of customers. Contrary to the
4 demonstrated reduction in load that is actually taking
5 place, the Company's last several forecasts still show
6 increases, but at a very slightly reduced rate. The
7 forecast of decreased load (as opposed to increased
8 growth) would look much more reasonable.
9
10 Q.DOES THE COMPANY'S MAY 2009 LOAD FORECAST
11 RECTIFY THIS SITUATION?
12 A.No. The Company's May 2009 updated load
13 forecast is the first forecast since the 2006 IRP that
shows any meaningful reduction in load as would be
15 expected at this time. However, the May 2009 updated
16 load forecast is based upon only changes to the Company IS
17 special contract customers, while presumably maintaining
18 the data for the other customer groups from the December
19 2008 updated forecast. The Company's May 2009 updated
20 forecast does not give any detail as to what
21 circumstances may have brought about the changes to the
22 overall special contract load-these changes may have all
23 been related to Micron, or maybe Micron played a small
24 role in these changes. Based upon all of the unanswered.25 questions that are raised by the 2009 IRP load data, the
993 Yankel, 01 25Irrigators
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24
25
1 December 2008 update, and the May 2009 update, I agree
2 that the Company needs to completely revisit its
3 forecast. I look forward to reviewing the Company's new
4 load forecast that is supposed to be available late this
5 summer. The Commission should not use any of the
6 Company's recent forecasts as reflecting the need for
7 Langley Gulch.
8
9 /
994 Yankel, DI 25aIrrigators
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1 Q.BASED UPON THE ABOVE, WHAT is YOUR
2 RECOMMENDATION WITH RESPECT TO THE COMPANY'S DESIRE TO
3 RECEIVE A CERTIFICATE OF PUBLIC CONVENIENCE AND NECESSITY
4 FOR LANGLEY GULCH?
5 A.Based upon the use of stale load forecast data
6 that does not reflect today' s economic environment and
7 load growth, it is premature to issue such a certificate
8 at this time. I recommend that the Commission postpone
9 any such decision for at least 10 months as recommended
10 by the Joint Motion of the intervenors filed on May 29.
11 At the moment, the Company is asking that the Commission
12 pre-approve one of the costliest proj ects that Idaho
13 Power has ever undertaken. Such an approval should not
14 be given, based upon critical load growth information
15 that is clearly outdated and inappropriate. The Company
16 has indicated that it has already begun the process of
17 updating its load forecast to account for today' s
18 reali ties. A postponement of 10 months before a decision
19 is made regarding Langley Gulch is both prudent and wise.
20
21 Q.WILL THE POSTPONEMENT OF A DECISION ON THE
22 ISSUANCE OF A CERTIFICATE OF PUBLIC CONVENIENCE AND
23 NECESSITY BY 10 MONTHS HAVE AN ADVERSE IMPACT UPON THE
24 COMPANY'S ABILITY TO SERVE LOAD?
25 A.No. There are several things for the
995 Yankel, 01 26Irrigators
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20
21
22
23
24.25
1 Commission to consider in this regard. First, under the
2 same load forecast data that was developed in October
3 2005 and August 2007, the Company put out its 2012
4 Baseload RFP which sought proposals for dispatchable,
5 first call, non-recallable, physically delivered firm or
6 unit contingent energy that was to commence no later than
7 June 1, 2012. This date essentially coincides with the
8 beginning of the summer peak season for the Company. The
9 summer months are not only characteristic of the highest
10 peak (demand)
11
12 I
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16 /
17
18
19
996 Yankel, 01 26aIrrigators
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22
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24.25
1 loads, but the highest overall energy usage as well.
2 Since the selection of Langley Gulch as the resource of
3 choice, the Company has slipped that commercial operating
4 date six months, to December 1, 2012. However, because
5 the summer is the Company's peak period (demand and
6 energy), the postponement of Langley Gulch until December
7 1, 2012 is not that different than postponing it a full
8 12 months until June 1, 2013.
9 Second, as pointed out above, a good estimate
10 would be that the load growth that the Company projected
11 would be three years further out than originally planned.
12 A 10-month delay would be well within these limits and
13 thus would not have any implications regarding Idaho
14 Power meeting its properly revised load growth.
15 Third, Request 2 of the Industrial Customers of
16 Idaho Power sought information regarding how the Company
17 would meet its loads if, for one reason or another,
18 Langley Gulch was not built. The Company's response
19 stated in part:
n... the Company would attempt to meet its most
cri tical summertime loads through a combination
of the following: (1) short-term demand
management programs, (2) market purchases
delivered to the east side of Idaho Power's
system, (market purchases delivered at Mona or
Red Butte (both in Utah) and delivered to Idaho
Power's firm transmission rights from Red Butte
to Borah/Brady, (4) reductions in deliveries to
Hoku during the summer of 2012, or (5) purchase
delivered to Jim Bridger for loss repayment.
997 Yankel, DI 27Irrigators
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24.25
1 Clearly, the Company has available options other than
2 Langley Gulch. These options may not be preferred, and
3 they may not always be the least cost, but they are
4 options. Gi ven the downturn in the economy, Idaho Power
5 should not need to exercise the above options any more
6 than already planned if the request for a Certificate of
7 Public Convenience and Necessary were put on hold for 10
8 months.
9
10 /
11
/
998 Yankel, DI 27aIrrigators
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1 Q.WHAT CAPACITY FACTOR DOES THE COMPANY INDICATE
2 THAT IT WILL OPERATE LANGLEY GULCH AT DURING 2013 (ITS
3 PROPOSED FIRST YEAR OF OPERATION)?
4 A.The Company's 2009 IRP (which has never been
5 submitted to review or approval), as well as its December
6 2008 and May 2009 updated forecasts1S indicate that it
7 will operate Langley Gulch at a capacity factor of 84%
8 (251 aMW / 300 MW) every month.
9
10 Q.IS ALL OF THIS OUTPUT FROM LANGLEY GULCH NEEDED
11 TO SERVE THE RETAIL CUSTOMER LOAD?
12 A.No. As a matter of fact, most of this
13 generation would be used to serve surplus sales. Request
14 7 of the Idaho Irrigation Pumpers Association sought
15 information regarding the impact on net power supply
16 costs of scenarios with Langley Gulch and without Langley
17 Gulch16. The Company's Response indicated that Langley
18 Gulch would provide 998,432 MWh. It also indicated that
19 the generation from Langley Gulch would displace
20 purchased power by 249,717 MWh (25% of Langley Gulch's
21 output), while it would increase surplus sales by 726,673
22 MWh (73% of the generation from Langley Gulch). The
23 Response went on to state that there would be a net
24 reduction of $10.2 million in net power supply cost (not
25 including non-fuel costs) with Langley Gulch operating.
999 Yankel, DI 28Irrigators
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22
1 However, the reduction in net power supply costs would
2 not even offset the depreciation expense of $12.8 million
3 ($427.4 million time 3%), let alone a rate of return and
4 taxes on $427.4 million of additional rate base. No
5 matter how much surplus sales there are from Langley
6 Gulch, it will simply result in a major
7
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13
14
15
23 15 See Idaho Power Company's Response to Staff Request 1 for the 2009
IRP resource balance and Idaho Power Company 1 s Response to
24 Intervenors 1 Joint Motion to Stay dated June 12, 2009, Attachments 1
and 2 for the December 2008 and May 2009 updated resource balance.
25
1000 Yankel, DI 28aIrrigators
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1 overall rate increase to customers. Very simply, Langley
2 Gulch will cost all rate payers a great deal of money for
3 no real benefit over its first few years of operation. A
4 postponement of the decision as to when to build Langley
5 Gulch is highly warranted.
6
7 Q.is THE 84% CAPACITY FACTOR LISTED IN THE
8 COMPANY'S 2009 IRP, AS WELL AS ITS DECEMBER 2008 AND MAY
9 2009 FORECASTS THE SAME AS THE 998,432 MWH THAT RESULTED
10 FROM THE COMPANY'S RUN OF ITS NET POWER COST MODEL?
11 A.No. The generation of 998,432 MWH spread over
12 8, 760 hours in the year translates into 114 aMW. The
13 Company's 2009 IRP and subsequent updates list Langley
14 Gulch operating at 251 aMW in each month. Presumably, if
15 Langley Gulch operates at 251 aMW as is claimed in these
16 recent forecasts, then approximately 88% of all of its
17 output will be for surplus sales.
18
19 Q.is THE 2009 IRP AS WELL AS THE DECEMBER 2008
20 AND THE MAY 2009 FORECASTS INTERNALLY CONSISTENT WITH
21 RESPECT TO THE WAY THE RESOURCES WILL BE UTILIZED?
22 A.No. They all have a consistency problem with
23 respect to the way they treat off-system purchases, which
24 gives the appearance that Langley Gulch is required to
25 serve an "energy" requirement, when in fact it is not.
1001 Yankel, DI 29Irrigators
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20
21
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23
1 This problem did not exist in the 2006 IRP. All three of
2 the newer forecasts limit the amount of regional energy
3 purchases to 115 aMW each month of each year in order to
4 reflect the level of Network Set-
5
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24 16 Under the load and resource conditions specified by the Company
in its last general rate case No. IPC-E-08-10..25
1002 Yankel, 01 29aIrrigators
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1 Aside for Firm Purchases. This limitation is no more
2 than a "new" requirement/limitation placed upon the
3 Company i s resources solely for the purpose of justifying
4 Langley Gulch.
5 Contrary to this limitation, the Company's
6 three new forecasts have no such limitation placed upon
7 the amount of purchased power that can be brought in
8 during the monthly system peaks. These forecasts use the
9 following purchases for the 2013 monthly peak loads:
10 2013 Peak Purchases from Pacific NW
MW
441
536
504
402
395
365
310
493
416
234
665
670
11 Jan
Feb
Mar
Apr
May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
12
13
14
15
16
17
18 If the Company can plan to bring in hundreds of MW i S at
19 the peak hour of each month, the limitation to energy
20 purchases of only 115 aMW is only an artificial construct
21 that should not be used when the new/real 2009 IRP comes
22 out in December 2009.
23
24 Q.OTHER THAN THE FACT THAT THE COMPANY DID NOT
25 HAVE THIS ARTIFICIAL LIMITATION OF ONLY PURCHASING 115
1003 Yankel, DI 30Irrigators
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1 AMW DURING EACH MONTH IN ITS 2006 IRP AND ITS 2008
2 UPDATED IRP, ARE THERE OTHER AREAS WHERE THE COMPANY'S
3 DATA AND CALCULATIONS DO NOT HAVE THIS LIMITATION?
4 A.Yes, there are. The Company's power supply
5 cost model that calculates the overall cost of power
6 supply over 80 water years contains no such limitation.
7 For example, the
8
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1004 Yankel, DI 30aIrrigators
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1 Company's calculations shown in Exhibit 47 of its last
2 rate case No. IPC-E-08-10 under the June 1935 water
3 condi tion lists a total of market energy and contract
4 energy purchases of 151,238 MWh or 210 aMW. For the July
5 1935 water condition it lists a total of market energy
6 and contract energy purchases of 383,580 MWh or 516 aMW.
7 Basically, there is no limitation placed upon the
8 purchase of energy that would be greater than any
9 limi tation that is placed upon the purchase of demand at
10 the hour of the system peak. The 115 aMW limitation that
11 is used in the Company's three most recent forecasts
12 seems to be more of an artificial construct used to
13 justify the need for Langley Gulch.
14
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1005 Yankel, DI 31Irrigators
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1 IMPACT OF THE NE COMPANY-OPTION IRRIGATION PEA
2 REWAS PROGRA
3
4 Q.PREVIOUSLY YOU INDICATED THAT YOU WOULD ADDRESS
5 THE PEAKING REQUIREMENTS LISTED IN THE COMPANY'S 2006 IRP
6 AND ITS 2008 UPDATED IRP. DO YOU HAVE ANY ADDITIONAL
7 INFORMATION TO ADD, THAT IS BEYOND THAT FOUND IN THE
8 COMPANY'S 2006 IRP AND 2008 UPDATED IRP?
9 A.Yes. Both the 2006 IRP and the 2008 Updated
10 IRP contain estimates of the impact of the Company's then
11 existing demand response programs. At the time, only the
12 A/C Cool Credit program for Residential customers and the
13 Peak Rewards program for Irrigation customers were in
14 operation. The Company's proj ections were that these
15 demand response programs would reach a plateau starting
16 201017. Since the 2008 Updated IRP, there has been the
17 introduction of a demand response program for larger
18 commercial/industrial customers as well as a major change
19 in the Irrigation Peak Rewards program.
20 With respect to the Irrigation Peak Rewards
21 program, a new "Company Option" has been added that not
22 only greatly increases the ability of this program to
23 target peak loads, but has also greatly added to the
24 number of Irrigators that are participating as well as
25 the connected load that is involved. The Company's 2009
1006 Yankel, DI 32Irrigators
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11 /
12
13 /.14
15
16
17
18
20
21
22
.
1 IRP as well as its December 2008 and May 2009 forecast
2 include new values for the impact of the Irrigation peak
3 reduction programs. These Company documents show maj or
4 increases related to the Irrigation program with the
5 following impacts/reductions forecast:
6 2009
2010
2011
88 MW
132 MW
176 MW7
8
9 /
19
23
24 17 2006 Integrated Resource Plan, Appendix A, page 51.
25
1007 Yankel, 01 32aIrrigators
.
.
.
1 Q.is THIS ALL OF THE PEAK REDUCTION CAPABILITY
2 THAT SHOULD BE EXPECTED FROM THE IRRIGATION PEAK REWARDS
3 PROGRAM THIS YEAR AND INTO THE FUTURE?
4 A.No. These estimates that have been provided by
5 the Company were made long before the new "Company
6 Option" program was finalized or approved by the
7 Commission. The reception for the program has past the
8 Company's general expectations. For example, there was a
9 limitation of 1,000 placed upon the number of sites that
10 could be involved in the first year. It is my
11 understanding that over 1,200 requested to participate
12 this first year. There are additional locations that are
13 planning to apply next year. A similar program such as
14 this exists in the PacifiCorp service area of Idaho, and
15 it took a couple of years for customers to get use to the
16 idea and join the program. I assume that the same
17 learning curve will occur in the Idaho Power terri tory.
18 Although the peak reduction values that the Company
19 originally projected are very encouraging, it would
20 appear that the program may quickly exceed these
21 expectations. In such a case, Idaho Power will become
22 even less of a utili ty with a peaking limitation and more
23 of one with an energy limitation.
24 Q.DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
25 A.Yes.
1008 Yankel, DI 33Irrigators
.
10
11
12
13.14
15
1
2 open hearing.)
(The following proceedings were had in
COMMISSIONER KEMPTON: Mr. Richardson.
MR. RICHARDSON: No questions,
COMMISSIONER KEMPTON: Ms. Ackerman.
MS. ACKERMAN: No questions,
COMMISSIONER KEMPTON: Mr. Purdy.
MR. PURDY: None for me. Thank you.
COMMISSIONER KEMPTON: Mr. Miller.
MR. MILLER: No questions, sir.
COMMISSIONER KEMPTON: Ms. Bridge.
MS. BRIDGE: No questions, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Woodbury.
MR. WOODBURY: Staff has no questions.
COMMISSIONER KEMPTON: Ms. Nordstrom.
MR. KLINE: Me this time.
COMMISSIONER KEMPTON: Okay, you guys have
20 got to give a handshake.
.
3
4
5 Mr. Chairman.
6
7
8 Mr. Chairman.
9
16
17
18
19
21
22
23
24
25
MR. KLINE: I know.
COMMISSIONER KEMPTON: Mr. Kline.
MR. KLINE: Sorry about that.
CSB REPORTING
[phone]
1009 YANKELIrrigators
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.
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16
17
18
19
20
1 CROSS-EXAMINATION
2
3 BY MR. KLINE:
4 Q Mr. Yankel, in your testimony, you
5 conclude that Langley Gulch should be viewed as a
6 resource to supply energy rather than peak; is that
7 right?
8 A Primarily, yes , it does supply peak as
9 I've indicated, but primarily, I view it as an energy
10 resource.
11 Q Right. I don't believe you were in the
12 room when Mr.Mace testified;is that right?
A That is correct.
Q But have you read his testimony?
A Yes,I did.
Q Do you have it with you?
A Yes,I do.
Q Okay.On page
A Should I get it?
Q Well,let's see if you need it.I don't
13
14
15
21 know, maybe you can recall it.
22
23
A Okay.
Q On page 12 of his testimony, he discusses
24 the fact that energy consumption by the irrigation class
25 is increasing. Do you recall that part of his
CSB REPORTING
[phone]
1010 YANKEL (X)Irrigators
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.
.
1 testimony?
2 A Yes. I was surprised to see that, yes.
3 Q Wi th a growing energy load, wouldn't you
4 agree with me that it's risky for the irrigation class to
5 be urging postponement of a resource that you've
6 testified will be primarily providing energy?
7 A There's a couple of things with the word
8 "risky" that's associated with that. First of all, as I
9 indicated, I was surprised to see the fact that the
10 irrigation load was increasing so much, at least
11 according to his numbers. I've not seen anything like
12 that. I can't say that he's wrong, but I certainly have
13 not verified that. I just don't know what the reasons
14 are for the change that he's seeing. What I have seen
15 and I think throughout my testimony, I'm not looking at
16 just the irrigation load but the entire load, I do have a
17 graph in there that shows historically the entire system
18 load and that's actually decreasing on an overall basis,
19 so I don't believe risky would be appropriate for my
20 recommendation at this point in time. Again, I'm looking
21 for postponement. I'm not looking for a complete denial
22 and/ or whatever, but just at least a postponement.
23 Q Well, again, with a growing energy load on
24 the part of the irrigation class, would it be, maybe the
25 term, "inappropriate" for the irrigation class to be
CSB REPORTING
[phone]
1011 YANKEL (X)Irrigators
.
.
.
1 urging a postponement of a resource that's an energy
2 resource?
3 A Well, for the last 25 years or so there's
4 been a very flat load for the irrigators and I think I've
5 testified to that a number of times. The load in general
6 has grown tremendously over the last 25 years with the
7 irrigation load being basically flat. The irrigators
8 have never testified with the circumstances that were
9 going at that time that there should not be any increase
10 in generation because the irrigation was not growing.
11 This is the first time we've done that and pretty much
12 the reason is for the lack of evidence at this point in
13 time. The great change in the economy at this point in
14
15
16
time we think needs a second look at it.
MR. KLINE: That's all I've got.
COMMISSIONER REDFORD: No questions from
17 me.
18
19
20
21
22
23
24
25
COMMISSIONER SMITH: Nor I.
COMMISSIONER KEMPTON: Nor me. Redirect?
MR. OLSEN: Just one quick question.
CSB REPORTING
[phone]
1012 YANKEL (X)Irrigators
.
.
.
1 REDIRECT EXAMINATION
2
3 BY MR. OLSEN:
4 Q Mr. Yankel, what effect would increased
5 participation in the new demand response program have on
6 those numbers cited by Mr. Mace that the irrigation load
7 is increasing?
8 A If that's the case, it would certainly
9 help out on the peak rewards program, relatively
10 speaking. If there is some kind of an increase, again, I
11 don't understand where his numbers came from, but
12 relati vely speaking, if the irrigation load has jumped by
13 10 percent, one could expect at least a 10 percent
14 increase in the peak load response.
15 Q But if they participate more in the demand
16 response program, wouldn't that, I guess, level out any
17 growth that you'd be seeing if you had more
18 participation? I know this is catching you cold, but
19 it's just wi thin the scope of Mr. Kline's questioning.
20 A I think Mr. Kline's question with the
21 preliminary question really went to energy and I think
22 what he was really trying to say is the energy load would
23 be going up even though our peak load would be dropping,
24 we'd be helping out the system more. We certainly would
25 on a peak basis, but, again, I think the thrust of his
CSB REPORTING
[phone]
1013 YANKEL (Di)Irrigators
.
.
.
1 question was more on energy and as I've indicated, even
2 though the irrigation class may be increasing, again, I
3 just don't have a feel for that at this point, the
4 overall energy usage on the system is decreasing right
5 now.
6 MR. OLSEN: No further questions,
7 Mr. Chair.
8 COMMISSIONER KEMPTON: If there is no
9 obj ection, the witness may step down.
10 (The witness left the stand.)
11 COMMISSIONER KEMPTON: Commissioner
12 Woodbury, I think Staff is up.
13 MR. WOODBURY: Thank you. Staff's first
14 wi tness is Rick Sterling.
15
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20
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25
CSB REPORTING
[phone]
1014 YANKEL (Di)Irrigators
.
13.
1 RICK STERLING,
2 produced as a witness at the instance of the Staff,
3 having been first duly sworn, was examined and testified
4 as follows:
5
6 DIRECT EXAMINATION
7
8 BY MR. WOODBURY:
9 Q Mr. Sterling, will you please state your
10 full name and spell your last name?
11 A Rick Sterling, S-t-e-r-l-i-n-g.
12 Q And for whom do you work and in what
capacity?
14 A The Idaho Public Utili ties Commission as a
15 Staff engineer.
16
19
20
Q And in that capacity did you have occasion
17 to prefile testimony in this case consisting of 89 pages
18 and 15 exhibits, Exhibit Nos. 101 through 115?
A Yes, I did.
Q And have you had the opportunity to review
21 that testimony and those exhibits prior to this
22 hearing?
23
24.25
A Yes, I have.
Q And it's necessary to make -- there's two
substi tutions in exhibits and I believe that Staff by a
CSB REPORTING
[phone]
1015 STERLING (Di)Staff
.
.
.
1 letter dated July 9th to parties and the Commission
2 indicated that previous Exhibit No. 115 was labeled
3 confidential when it's not. It's just the Idaho Code
4 Section 61-541. If I can approach the Bench, I can
5 distribute.
6 COMMISSIONER KEMPTON: You can.
7 (Mr. Woodbury approached the Bench.)
8 MR. WOODBURY: And then the second exhibit
9 is Confidential Exhibit No. 109 and I've distributed this
10 to the parties that signed the confidential, whatever it
11 was, and I can distribute this revised exhibit and these
12 are the changes. It's just one number that changes and
13 flows through that exhibit.
14 COMMISSIONER KEMPTON: Okay, Mr. Woodbury,
15 again, as we get to this point, you're not suggesting at
16 that point in time that we go ahead and close the
17 hearing? You're suggesting that --
18 MR. WOODBURY: No, it's not necessary to
19 close the hearing to make these changes.
20 COMMISSIONER KEMPTON: Right.
21 Q BY MR. WOODBURY: Mr. Sterling, with
22 respect to Confidential Exhibit No. 109, I've distributed
23 it to the parties and it appears that there is a change
24 that occurs on line 21, air permitting, in the column
25 entitled "Soft Cap" and there was a number that was
CSB REPORTING
[phone]
1016 STERLING (Di)Staff
.1 excluded from the earlier filed and that has been
2 included now and that does change some totals through
3 that column, does it not?
4 A That's correct. The only real omission on
5 this was on line 21, but that affected totals in several
6 other places.
7 Q Okay, and then Exhibit No. 115 was in
8 error marked confidential and that is not confidential.
9 Have you -- you've read through your testimony, is it
10 necessary to make any other changes?
11
12
13.14
A Yes, there are a few.
Q And if you could lead us through those.
A On page 4, line 5, the number at the end
of the sentence is "347.0" should be changed to 347.4" to
15 conform with Exhibit 109. On page 6, line 25, it's just
16 a minor typo, the first word of the sentence or the first
17 word in the line "meeting" should be made plural,
18 "meetings. "
19 On page 8, line 13, that should read
20 "Section 61-541," and on page 87, line 8 --
21
.
COMMISSIONER KEMPTON: I'm sorry, which
22 page?
23 THE WITNESS: Page 87
24 COMMISSIONER KEMPTON: All right.
25 THE WITNESS: -- line 8, the number at the
CSB REPORTING
[phone]
1017 STERLING (Di)Staff
.
10
1 end of the sentence should be 347.4, again to conform
2 with Exhibit 109.
3 Q BY MR. WOODBURY: Okay. With those
4 corrections, if I were to ask you the questions set forth
5 in your testimony, would your answers be the same?
6 A Yes, they would.
7 MR. WOODBURY: Mr. Chairman, I would ask
8 that the testimony be spread on the record, the exhibits
9 identified and spread, also. Thank you.
COMMISSIONER KEMPTON: Without obj ection,
11 it is so ordered.
.
.
12 (The following prefiled direct testimony
13 of Mr. Rick Sterling is spread upon the record.)
14
15
16
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21
22
23
24
25
CSB REPORTING
[phone]
1018 STERLING (Di)Staff
.1 Q.Please state your name and business address for
2 the record.
3 A.My name is Rick Sterling. My business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utili ties
7 Commission as a Staff engineer.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science degree in
11 Civil Engineering from the University of Idaho in 1981
12 and a Master of Science degree in Civil Engineering from
13.14
the Uni versi ty of Idaho in 1983. I worked for the Idaho
Department of Water Resources from 1983 to 1994. In
15 1988, I received my Idaho license as a registered
16 professional Civil Engineer. I began working at the
17 Idaho Public Utilities Commission in 1994. My duties at
18 the Commission include analysis of a wide variety of
20
19 electric and large water utility applications.
Q.What is the purpose of your testimony in this
21 proceeding?
22 A.There are several primary purposes of my
23 testimony:
24.25
1 )To address whether Idaho Power has
demonstrated a sufficient need for a new
CASE NO. IPC-E-09-03
06/19/09 1019 STERLING, R (Di) 1
STAFF
.
10
11
12
.14
15
1 gas-fired base load plant,
2 2 )To address whether there are other, better
3 al ternati ves to meeting future load than
4 building a new generating plant,
5 3)To address whether Idaho Power conducted a
6 fair Request for Proposals (RFP) process
7 and chose the best proposal,
8 4 )To discuss the Company's Benchmark
9 Resource proposal and the costs Idaho
Power is requesting be approved as a
Commitment Estimate,
5 )To discuss the requirements of Idaho Code
13 § 61-541 and whether Idaho Power has met
those requirements, and
6)To make recommendations regarding recovery
16 of costs associated with the Langley Gulch
17 project.
18 Q.Please summarize your testimony.
19 A.My testimony begins by reviewing Idaho Power's
20 2006 Integrated Resource Plan (IRP), which is the
21 Company's basis for contending that it needs to acquire a
.
22 gas-fired base load plant. I also consider whether
23 changes in loads, resources, fuel prices and other
24 factors since the 2006 IRP still support a new gas-fired
25 base load plant. Based on my reviews, I conclude that a
CASE NO. IPC-E-09-03
06/19/09
1020 STERLING, R (Di) 2
STAFF
1 gas-fired base load resource is needed..2 Next, I discuss a variety of other options for
3 addressing Idaho Power's load requirements, including
4 non-Company-owned generation, conservation, demand
5 response, transmission upgrades and others. I conclude
6 that while these are viable alternatives, they cannot be
7 relied on exclusively, and should continue to be pursued
8 in conj unction with a new gas-fired base load plant.
9 Next, I review the RFP process followed by
10 Idaho Power. I discuss the method used to evaluate bids
11 and address the price and non-price differences between
12 the top-ranked proposals. Although I express concerns.13 that Idaho Power did not permit any build and transfer
14 proposals to be submitted, I conclude that the evaluation
15 of the proposals that were considered was fair. I
16 recommend that the Benchmark Resource proposal for the
17 Langley Gulch proj ect be accepted as the winning bid.
18 Next, I discuss the Company's Benchmark
19 Resource proposal and the costs Idaho Power is requesting
20 be approved as a Commitment Estimate. I identify
21 components of the Company's proposed Commitment Estimate
22 that I do not believe should be recoverable from
23 ratepayers. I also discuss the requirements of Idaho
24 Code § 61-541, and identify other components of the.25 proposed Commitment Estimate that I do not believe are
CASE NO. IPC-E-09-03
06/19/09
1021 STERLING, R (Di) 3
STAFF
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20
21
22
23
24
25
1 known with enough certainty to merit pre-approval under
2 the new legislation.
3 Finally, I make recommendations about those
4 portions of the expected proj ect costs that I believe
5 meri t pre-approval. I recommend that an amount of $347.4
6 million plus AFUDC be pre-approved for recovery under
7 Idaho Code § 61-541, and that all additional amounts
8 spent on the proj ect including transmission, up to a
9 maximum amount of $376.6 million plus AFUDC be subject to
10 future audit and prudence review once the costs are known
11 and the plant begins providing service.
12 Q.Because your testimony is lengthy, please
13 provide a table of contents for the aid of readers.
14 A.A table of contents is provided below:
15 Subject Page
16 BACKGROUND 5
17 APPROACH 6
18 NEED FOR POWER 9
19 OTHER RESOURCE ALTERNATIVES 23
OVERVIEW OF THE REQUEST FOR PROPOSAL PROCESS 30
Proposals .............39
Evaluation of Proposals .... .42
Short List Analysis ......49
Analysis of Final Candidate Proposals .50
LANGLEY GULCH PROJECT DESCRIPTION ....52
CASE NO. IPC-E-09-03
06/19/09 1022 STERLING, R (Di) 4
STAFF
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16
1 Operation .53
54
56
.57
57
59
.60
...60
2 Fuel Supply and Transportation
3 Water Supply. .
4 Electrical Interconnection
5 Project Permits
6 Project Risks. .
7 Proj ect Benefits
8 COMMITMENT ESTIMATE
9 IDAHO CODE § 61-541 78
10 TOTAL EXPECTED POWER COST . 82
11 FUEL COSTS . .. . . . . 85
12 STAFF CONCLUSIONS 86
13 BACKGROUN
14 Q.What is Idaho Power seeking in its Application
15 in this case?
A.On March 6, 2009, Idaho Power Company filed an
17 Application requesting a Certificate of Public
18 Convenience and Necessity (CPCN) authorizing Idaho Power
19 to construct, own, operate, and maintain the Langley
20 Gulch power plant (Langley Gulch or Project) and
21 authorizing inclusion of the Project in Idaho Power's
22 rate base. The Proj ect is a natural gas-fired combined
23 cycle combustion turbine (CCCT) generating plant with a
24 nameplate capacity of approximately 330 megawatts. The
25 Company proposes to construct the Proj ect on a parcel of
CASE NO. IPC-E-09-03
06/19/09 1023 STERLING, R (Di) 5
STAFF
.
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20
1 land on the south side of Interstate 84 in Payette County
2 approximately four miles south of the town of New
3 Plymouth, Idaho. Idaho Power commits to procure and
4 construct the Proj ect for an amount that will not exceed
5 $427,400,000 which it terms a "Commitment Estimate."
6 Idaho Power proposes that amounts incurred in excess of
7 the Commitment Estimate would be subject to a "Soft Cap,"
8 that is, excess costs could only be included in rates if
9 the Commission agreed the additional amounts expended
10 were prudent and should be included in fair, just, and
11 reasonable rates. As a part of this Application, the
12 Company is requesting that the Commission's Order issuing
13 the CPCN authorize Idaho Power to include the Proj ect ' s
14 prudently incurred costs for fuel, fuel storage, and fuel
15 transportation for recovery through the Company 's
16 existing Power Cost Adj ustment (PCA) mechanism.
17 APPROACH
18 Q.Please describe the approach you took in your
19 review of the Company's Application.
A.I began my review by considering whether Idaho
21 Power i s need for power was sufficient to justify a new
22 base load resource. I reviewed the Company's 2004 and
23 2006 Integrated Resource Plans (IRPs), its 2008 IRP
24 Update, and information I received during planning
25 meetings related to the 2009 IRP which will be submitted
CASE NO. IPC-E-09-03
06/19/09 1024 STERLING, R (Di) 6
STAFF
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1 in December. I also reviewed updated load forecasts and
2 load/ resources balances provided by the Company in
3 response to production requests. In my review, I also
4 considered whether a gas-fired base load resource was the
5 proper type of resource to pursue, and whether Idaho
6 Power had adequately considered other options for meeting
7 forecasted loads.
8 Next, I reviewed the RFP process conducted by
9 the Company. I thoroughly reviewed the RFP and the RFP
10 Evaluation Manual, including the price and non-price
11 cri teria used for scoring proposals. I reviewed each of
12 the proposals that were submitted and examined the scores
13
14
assigned by the Company's evaluation team. Both the
busbar analysis and the Aurora analysis used by the
15 Company to rank proposals and develop a short list were
16 carefully scrutinized. Transmission studies, air
17 emission studies, and various site analyses were also
18 reviewed.
19 Next, I reviewed the Company's Benchmark
20 Resource proposal. I examined contracts for purchase of
21 the steam and gas turbines, as well as purchase of water
22 rights needed for plant cooling. I reviewed the land
23 purchase option, assessed the site's permitting status,
24 and studied fuel storage, transport, and transportation
25 agreements.
CASE NO. IPC-E-09-03
06/19/09 1025 STERLING, R (Di) 7
STAFF
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1 Next, I carefully analyzed the Commitment
2 estimate proposed by Idaho Power. I checked whether
3 costs included in the Commitment Estimate matched costs
4 included in the Benchmark Resource proposal. I
5 considered whether any costs added to the Commitment
6 Estimate but not included in the Benchmark Resource bid
7 were proper. I reviewed all of the underlying bases for
8 each cost item in the Comri tment Estimate, and proposed
9 amounts to be included in either a "Hard Cap" or a "Soft
10 Cap" based primarily on the certainty with which each
11 cost item was known.
12 Finally, I reviewed the requirements of Idaho
13 Code § 61-541 and the rate making treatment requested by
14 Idaho Power. In addition, I considered the rate making
15 treatment for fuel that will be needed by the plant.
16 In my review of the Application, I examined
17 responses to 103 production requests of the Commission
18 Staff, as well as an additional 123 responses to requests
19 made by intervenors. Besides the numerous contracts,
20 studies and analysis mentioned earlier, I reviewed
21 presentation materials for the Board of Directors and
22 management, meeting notes, and a great deal of
23 correspondence related to the Langley Gulch proj ect. I
24 believe that Staff's review of Idaho Power's Application
25 was deliberate, thorough and fair.
CASE NO. IPC-E-09-03
06/19/09 1026 STERLING, R (Di) 8
STAFF
.
.
.
1 NEED FOR POWER
2 Q.What is the basis for Idaho Power's request to
3 construct a new base load generating plant?
4 A.The need for a new base load generating plant
5 can be traced back at least as far as the Company's 2004
6 IRP. That plan called for a 500 MW coal-fired resource
7 in 2011. Joint ownership was suggested because Idaho
8 Power's need was mostly seasonal. One al ternati ve
9 considered was a joint proj ect with PacifiCorp to add
10 another unit at the Bridger plant in Wyoming.
11 In its 2006 IRP, Idaho Power reassessed its
12 need for new resources. The plan included more DSM, more
13 purchases from PURPA proj ects and other renewables, and a
14 transmission upgrade in 2012. In addition, the plan
15 included a 250 MW pulverized coal base load resource in
16 2013 and a 250 MW advanced or clean coal-fired resource
17 (integrated gasification combined cycle; IGCC) in 2017.
18 Idaho Power and Avista went so far as to conduct a joint
19 study to investigate possible alternatives for new
20 coal-fired generation. In the meantime, however,
21 concerns about the effects of fossil-fueled generation on
22 climate change began to build. Public perceptions,
23 expectations about future C02 policy, and the reluctance
24 of the financial sector to support such a proj ect led to
25 a belief that new conventional coal-fired generation
CASE NO. IPC-E-09-03
06/19/09 STERLING, R (Di) 9
STAFF
1027
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.
.
1 would be too costly, too risky, or politically
2 infeasible. Avista was the first to abandon its
3 investigations into new coal generation options, followed
4 soon after by PacifiCorp and Idaho Power. Idaho Power's
5 focus then shifted to gas-fired generation to satisfy its
6 base load generation needs.
7 In 2008, Idaho Power updated its 2006 IRP.
8 Exhibi t No. 101 shows a comparison of the 2006 IRP
9 preferred portfolio and the 2008 updated portfolio (Table
10 11). The 2012 entry listed as "Southwest Idaho CCCT" was
11 the basis for the base load RFP in which Langley Gulch
12 was selected.
13 Q. Are there any other factors that helped support
14 the Company's need for base load generation in 2012?
15 A.Yes, there were several. Idaho Power had been
16 anticipating a considerable amount of new PURPA project
17 development coming online, both because numerous
18 contracts had already been signed and because
19 anticipation of higher avoided cost rates led to an
20 expectation of many additional contracts. In addition, a
21 significant amount of non-PURPA cogeneration development
22 was expected. None of that cogeneration materialized,
23 however, and the majority of PURPA projects with signed
24 contracts during this time frame have also failed to come
25
CASE NO. IPC-E-09-03
06/19/09 STERLING, R (Di) 10
STAFF
1028
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1 online. i
2 Another factor has been the Company's
3 difficul ty in adding planned amounts of geothermal to its
4 portfolio. In a 2006 Request for Proposals, a bid from
5 u. S. Geothermal was accepted to provide 45.5 MW and to
6 have facilities online between October 2007 and January
7 2011. So far, only 13 MW have been developed, and
8 contracts for the remaining amounts have not been
9 executed. In 2008, Idaho Power issued another RFP
10 seeking 50-100 MW of geothermal generation. Although
11 several bids were made, no contracts have emerged from
12 that RFP.
13 Another factor has been an anticipated shift in
14 flow augmentation releases with water from the federal
15 dams on the Snake River above Brownlee. As a consequence
16 of a Biological Opinion dated May 5, 2008, the Bureau of
17 Reclamation intends to shift its flow augmentation
18 releases from Milner and the Boise basin from summer to
19 spring. This shift in flow augmentation has been
20 incorporated in Idaho Power's stream flow forecasts,
21 Operating Plans, and its 2009 Integrated Resource
22 Planning studies. The effect of the planned shift in
23
24
25
i From 2005 to the present, PURPA QFs with a total capacity of
175.5 MW have signed contracts but have yet to come online. A
total of 21.6 MW of signed contracts have been terminated
during this same time period. Projects with a capacity of 107
MW have come online.
CASE NO. IPC-E-09-03
06/19/09 1029 STERLING, R (Di) 11
STAFF
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1 releases will be a loss of approximately 140 MWa of
2 summertime energy.
3 Finally, Idaho Power cites the expression of
4 interest from several possible new customers with large
5 loads to locate in the Company's service terri tory. All
6 of these factors, combined with the Company's most recent
7 load forecast led to the 2012 base load RFP initially
8 calling for between 250 and 600 MW of new generation, and
9 the acceleration of the online date for the base load
10 resource from 2013 to 2012.
11 Q. Has the Company prepared an updated
12 load-resource balance to show whether a new base load
13 resource is needed?
14 A.Yes, it has. Idaho Power uses two primary
15 cri teria in its planning to assess the need for new
16 resources - one is based on energy needs and the other is
17 based on capacity needs. The water and load conditions
18 used to determine the energy and capacity needs that
19 justified issuance of the 2012 Base Load RFP were 70th
20 percentile water and load for average energy, and 90th
21 percentile water and 95th percentile load for peak-hour
22 capaci ty needs. After the 2006 IRP was released, a
23 series of surplus/deficit spreadsheets were periodically
24 updated to reflect known or expected changes in resources
25 or loads and the associated impact on forecast
CASE NO. IPC-E-09-03
06/19/09 1030 STERLING, R (Di) 12
STAFF
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1 surplus/deficit position. Annual surplus/deficit
2 spreadsheets for energy and peak hour planning conditions
3 from March 2008 are included as Exhibit No. 102. The
4 load forecast used in these spreadsheets was from August
5 2007. Note that at the time these spreadsheets were
6 prepared, the Company was expecting both energy and
7 capaci ty deficits from 2008 onward.
8 Monthly average energy and peak hour
9 surplus/deficits are shown in Exhibit No. 103, both with
10 and without the Langley Gulch project included. Note
11 that with the Langley Gulch project assumed in 2012, the
12 Company still proj ects energy deficits in some summer
13 months. Peak hour deficits, however, are nearly
14 eliminated by Langley Gulch after 2012.
15 Q.Do you believe that a new base load plant is
16 justified?
17 A.Yes , it is justified based on the information
18 and analysis in Idaho Power's 2006 IRP and 2008 IRP
19 Update, the Company's load-resource balance under various
20 water and load conditions, and transmission constraints
21 that limit its ability to import power during critical
22 times of the year. However, significant changes have
23 occurred since the Company's last IRP was prepared.
.24
25
Q.What changes have occurred since the 2006 IRP
and the 2008 IRP Update were completed?
CASE NO. IPC-E-09-03
06/19/09 1031 STERLING, R (Di) 13
STAFF
.1 A.One of the most obvious changes has been the
2 economic recession. The economic conditions have likely
3 stalled load growth expectations in nearly all customer
4 sectors. In response to production requests, Idaho Power
5 stated that in December 2008 it adjusted the residential
6 and commercial sector load forecast to reflect a
7 prolonged slowdown in housing and consumer spending.
8 Residential new customer growth rates (initially forecast
9 to decline until the first quarter of 2009) were extended
10 by Idaho Power to continue the decline into 2010 and
11 later rebound to the point of the original new customer
12 forecast in 2011. On a total customer (new plus
.14
13 existing) basis, the Company's revised forecast returns
to the same value as the original forecast in 2016.
15 Commercial customer growth estimates were lowered
16 consistent with adj ustments made to the residential
17 class. Use-per-customer forecasts were not modified from
18 the original forecast.
19 In May 2009, the Company further revised its
20 load forecast to incorporate changes in special contract
21 forecasts. In addition, the Company updated the forecast
22 to include all DSM program impacts as of May 2009,
23 including new demand response programs for Irrigation,
24 Commercial, and Industrial customers proposed in the 2009.25 IRP process. The Company's most recent load resource
CASE NO. IPC-E-09-03
06/19/09
1032 STERLING, R (Di) 14
STAFF
.1 balance is shown in Exhibit No. 104. Page 1 of the
2 exhibi t shows the load resource balance based on energy
3 planning criteria. Page 2 of the exhibit shows the load
4 resource balance based on peak hour planning criteria.
5 Exhibit No. 105 shows the amounts by which the load
6 forecasts have been changed compared to forecasts
7 included in the Company's 2008 IRP Update.
8 Utilizing the May 2009 load forecast, along
9 with the forecast peak-hour DSM contributions and the
10 assumed level of purchases from the Pacific Northwest,
11 Idaho Power is still projecting peak-hour deficits during
12 July of 2009 through July of 2012 of 40 MW,21 MW,91 MW,.13
14
and 183 MW, respectively. From an average energy
perspective, using the May 2009 load forecast along with
15 the forecast DSM contributions to reduce average energy
16 requirements and the assumed level of purchases from the
17 Pacific Northwest, Idaho Power is still projecting
18 9verage energy deficits during July of 2009 through July
1 9 0 f 2 0 12 0 f 3 97 MW, 4 18 MW, 4 65 MW, and 535 MW,
20 respectively.
21 Idaho Power is reportedly working on developing
22 a new load forecast, but does not expect it to be
23 available until late summer of 2009. The Company states
.24 that the revised load forecast will be reflective of the
25 most current economic forecast drivers, the most recent
CASE NO. IPC-E-09-03
06/19/09
1033 STERLING, R (Di) 15
STAFF
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1 input from the Company's large power representatives and
2 their contacts, energy efficiency impacts, and the latest
3 forecast of retail electricity prices.
4 Q.Are there any other recent changes you are
5 aware of that would affect Idaho Power's loads and
6 resources?
7 A.Yes, there are a few. This section of Staff's
8 direct testimony contains confidential infor.ation
9 subject to protective agreement. In addition, on May 28,
10 2009 the Company made a filing to delay the start of the
11 Hoku contract in 2009. As part of the agreement to delay
12 the contract start, Idaho Power is requiring Hoku to
13 reduce its July and August 2012 loads by 40 MW below the
14 original limits in the contract. Idaho Power has also
15 recently modified its Irrigation Peak Rewards Program to
16 encourage greater participation. As a result of the
17 program modifications, a much greater reduction in
18 summertime loads is expected than was originally
19 anticipated. Finally, the 2012 scheduled completion date
20 of the Boardman to Hemingway project that is expected to
21 add 255 MW of additional transmission capacity to the
22 Northwest has been pushed back to 2015. These changes
23 are reflected in Exhibit No. 104.
24
25
Q.Wi th so much economic uncertainty right now,
how can the Commission be certain that the proposed
CASE NO. IPC-E-09-03
06/19/09 1034 STERLING, R (Di) 16
STAFF
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1 Langley Gulch project is still needed?
2 A.Wi th so much uncertainty, the Commission cannot
3 be certain that the proj ect will be necessary at exactly
4 the online date planned by the Company. For projects
5 wi th relatively long lead times, there will always be at
6 least some uncertainty about whether the planned online
7 date will exactly match the load growth forecasts. Load
8 will almost always occur at a faster or slower rate than
9 planned.
10 Q.What would be the consequences if it turned out
11 that the online date of the Langley Gulch proj ect could
12 be delayed due to prolonged effects of the current
13 recession or other factors?
14 A.If the planned online date of the plant was
15 delayed, there would likely be costs, benefits and risks
16 that should all be considered and weighed against each
17 other. First, delaying the online date would likely
18 cause Siemens to either charge cancellation fees
19 (approximately $8.7 million for the gas and steam
20 turbines), or negotiate contract extensions wherein Idaho
21 Power would be responsible for increased costs. In
22 addi tion, the Engineering, Procurement and Construction
23 (EPC) contractor would likely increase its costs for
24 labor, materials and other services due to inflation.
25 The six month delay in online date already planned by
CASE NO. IPC-E-09-03
06/19/09 1035 STERLING, R (Di) 17
STAFF
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15
1 Idaho Power is estimated to cost $6.8 million in the
2 Corni tment Estimate. In addition to cancellation fees,
3 penal ties and inflationary increases, delaying
4 construction could cause Idaho Power to incur higher
5 costs to purchase replacement power, and would also
6 likely cause Idaho Power to forego any revenues from
7 surplus sales that the plant might be able to make if it
8 were available.
9 On the other hand, delaying the online date
10 would also cause some savings. Delaying a $427 million
11 investment by one year reduces the proj ect 's net present
12 value by roughly $23 million.
13 Q.Would there be risks in delaying construction
14 if it were possible?
A.Absolutely. If the planned online date was
16 delayed and it turned out that the plant was actually
17 needed sooner, it could be just a cost risk if
18 replacement power could be found. However, because Idaho
19 Power is transmission constrained under high load
20 condi tions during certain times of the year, it may not
21 be able to obtain replacement power at any price.
22 Ul timately, the risk could be mandatory curtailments.
23 By comparison, the risks of bringing the plant
24 online sooner than needed are completely financial. In
25 fact, bringing the plant online earlier than needed could
CASE NO. IPC-E-09-03
06/19/09 1036 STERLING, R (Di) 18
STAFF
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20
1 even be beneficial if certain load and market pricing
2 condi tions were to occur. In my opinion, the risks of an
3 early online date versus a late online date are not
4 symetric. The costs and risks of bringing the plant
5 online too late far outweigh the costs of bringing the
6 plant online too soon.
7 Nevertheless, while there is no assurance that
8 the plant will come online at precisely the optimum time,
9 I do believe that the plant will still be needed in
10 approximately the time frame planned. If normal load
11 growth resumes and load forecasts return to pre-recession
12 levels, there is some risk that the plant would not be
13 available in time if construction were to be delayed now
14 based on current load growth rates. Because construction
15 of a CCCT has approximately a three-year lead time, the
16 Company does not have the luxury of waiting to see how a
17 recovery from the recession will unfold before making a
18 decision when to proceed on development of a new
19 generating resource.
Q.But given the uniquely high degree of
21 uncertainty Idaho Power is currently faced with, do you
22 think it is wise to make a decision now on such a maj or
23 resource addition?
.24
25
A.Ideally, Idaho Power would only have to make
resource decisions when all factors are known.
CASE NO. IPC-E-09-03
06/19/09 1037 STERLING, R (Di) 19
STAFF
.1 Unfortunately, that is just not realistic. There will
2 always be uncertainty, but perhaps current economic
3 condi tions make the uncertainty seem greater than it has
4 been in the past. Doing nothing until there is more
5 certainty is very risky and simply not an option in my
6 opinion.
7 Q.In the 2012 Base Load RFP issued on April 1,
8 2008, Idaho Power was seeking proposals for between 250
9 and 600 MW of dispatchable energy. On June 25, 2008, the
10 RFP was revised to request 300 MW. Why did Idaho Power
11 revise the RFP to request a much smaller amount?
.12
13
14
A.At the time the RFP was being prepared, Idaho
Power was discussing plans with two potential new
customers that could have added over 400 MW of new load
15 to Idaho Power's system. If these customers' proj ects
16 proceeded as anticipated, or if any other new customers
17 with significant electrical loads decided to move into
18 Idaho Power's service territory, Idaho Power was going to
19 need more resources to serve the new load. With this in
20 mind, the RFP was initially released with a quantity
21 range indicating that Idaho Power anticipated acquiring
22 between approximately 250 MW and 600 MW of dispatchable
23 energy. Although discussion with the two companies
24 continued, no final agreement was reached. Ultimately,.25 Idaho Power elected to set the RFP quantity at
CASE NO. IPC-E-09-03
06/19/09 1038 STERLING, R (Di) 20
STAFF
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1 approximately 300 MW due to uncertainty about the size
2 and likelihood of potential new large loads.
3 After the release of the RFP, the economy
4 continued its steep downturn. In hindsight, the decision
5 to reduce the size of the RFP was probably a good one.
6 The smaller size of the RFP significantly reduces the
7 risk that loads will not recover enough in time to fully
8 utilize the full capacity of the plant, and lessens the
9 cost and risk if the plant's online date turns out to be
10 earlier than needed.
11 Q.As proposed and evaluated in the RFP process,
12 qualifying proposals were required to be capable of
13 commencement of energy deliveries not later than June 1,
14 2012, yet the proposed Langley Gulch facility has an
15 expected online date of December 1, 2012. Why is the
16 proj ect being delayed?
17 A.Idaho Power has explained that after the
18 Benchmark Resource proposal was recommended as the
19 winning bid, the Company's senior management questioned,
20 given the current financial crisis, whether the proj ect
21 could be financed. The Company believed that the
22 Benchmark Resource proposal would provide substantial
23 cost savings for customers; consequently, management felt
24 that the best way to preserve those cost savings was to
25 defer the online date to see if the Commission was
CASE NO. IPC-E-09-03
06/19/09
1039 STERLING, R (Di) 21
STAFF
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1 willing to provide ratemaking assurances that would
2 enable the Company to finance the proj ect in a way that
3 would preserve the significant cost savings for
4 customers.
5 Q.Do you believe it was a wise decision to delay
6 the required online date of the proj ect?
7 A.I was aware of the Company's concerns that it
8 would not be able to finance a self-build proj ect without
9 certain ratemaking assurances from the Commission.
10 Absent those assurances, I believe the Company thought it
11 might not be able to obtain financing for the proj ect. I
12 also believe that the Company strongly wanted the
13 Commission to be able to consider approval of a CPCN
14 under legislation that was still pending at the time. It
15 makes sense that the Company would want to wait until it
16 was confident that the legislation would be passed before
17 deciding whether to proceed with the self-build proposal.
18 On the other hand, all other bidders were willing and
19 able to meet the online date required by the RFP.
20 Presumably they were confident they could finance their
21 proposals without a delay in the online date. The need
22 to delay the project i s online date appears to only have
23 been an issue for the Company's Benchmark Resource
24 proposal.
25
CASE NO. IPC-E-09-03
06/19/09 1040 STERLING, R (Di) 22
STAFF
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1 OTHER RESOURCE ALTERNATIVES
2 Q.Do you believe that Idaho Power has adequately
3 considered other alternatives to adding a new base load
4 plant?
5 A.Yes, I do. As discussed previously, Idaho
6 Power prepares an Integrated Resource Plan every two
7 years as required by the Commission. Because of the
8 plan's complexity, integrated resources planning has
9 become an almost ongoing process. In the planning
10 process, all new resource options are considered,
11 including renewable resources such as wind, geothermal,
12 and solar. Upgrades to existing hydro plants are also
13 considered. New gas-fired thermal generation options,
14 both simple cycle and combined cycle, are also on the
15 menu of possible choices, as are clean coal options such
16 as integrated gasification combined cycle (IGCC) and
17 supercri tical pulverized coal. Nuclear options are also
18 considered for the outer years of the planning period.
19 Finally, a wide variety of demand-side options are also
20 considered.
21 Idaho Power's preferred resource portfolio
22 already includes some of these generating resource
23 options in addition to a base load gas-fired resource in
24 2012. An RFP for additional geothermal resources was
25 issued in 2008 and an RFP for up to 150 MW of additional
CASE NO. IPC-E-09-03
06/19/09 1041 STERLING, R (Di) 23
STAFF
1 wind generation was issued on May 18, 2009, just one.2 month ago. Clearly, Idaho Power is pursuing a variety of
3 other generating resource options besides just gas-fired
4 generation.
5 Q.Do you believe that PURPA proj ects (QFs) are a
6 viable means of meeting future base load needs of Idaho
7 Power?
8 A.No, I do not believe they can be planned on as
9 a reliable option for meeting base load needs. Nearly
10 all of the recent PURPA development has been small wind
11 proj ects. It is unknown how much additional capacity
12 might be developed and when such development might occur.
.13 The maj ori ty of proj ects for which contracts have been
14 signed in recent years have yet to come online and have
15 had their contractual online dates extended. The recent
16 substantial increase in avoided cost rates for PURPA
17 proj ects will likely stimulate some new development, but
18 the amount and timing of new projects is unknown. The
19 timing and pace of PURPA development is not within Idaho
20 Power's control and is not dictated by the Company's need
21 for new generation.
22 Furthermore, because nearly all new QFs are
23 wind proj ects, it is unlikely that they could prove to be
24 an acceptable substitute for a new base load resource.25 even if they could be timely developed. Because wind
CASE NO. IPC-E-09-03
06/19/09 1042 STERLING, R (Di) 24
STAFF
.1 generation is intermittent, there is no guarantee that
2 the generation would be available during all of the hours
3 when it would be needed.
4 Q.Are market purchases a reasonable alternative
5 for meeting future base load requirements?
6 A.Long-term market purchases or bilateral
7 contracts with other utili ties can be good options in
8 some cases, but they require that transmission be
9 available to import the energy. It might be possible to
10 purchase a product from a marketer or another utility in
11 the Northwest, but such a purchase would require
12 transmission from Mid-C across one or more of the
.13
14
Bonneville Power, PacifiCorp, Avista or NorthWestern
transmission systems, in conj unction with transmission
15 across Idaho Power's transmission system from the Hells
16 Canyon Complex to its load center. Because one or more
17 of these paths are frequently subject to congestion,
18 energy purchased at Mid-C cannot be used at all times to
19 meet the load requirements of Idaho Power.
20 Another alternative would be to make firm
21 wholesale purchases and to acquire the necessary
22 transmission to deliver the energy to the east side of
23 Idaho Power's system. Although such purchases may be
24 available from time to time, long term reliance on.25 east-side transmission capacity is probably not feasible
CASE NO. IPC-E-09-03
06/19/09 1043 STERLING, R (Di) 25
STAFF
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1 at least until completion of the planned Gateway West
2 proj ect (a 500 kV transmission line across southern Idaho
3 and Wyoming). I do not believe it would be wise to rely
4 on east-side purchases indefinitely to meet either base
5 load or peak hour needs, especially during a time when
6 surplus generation may be in short supply. Moreover,
7 firm wholesale purchases delivered to the east side of
8 Idaho Power's system would use an increment of import
9 capacity that, because it is being used for a purchase,
10 would be unavailable in the event of a system emergency.
11 Q.If Idaho Power could, do you believe it would
12 be wise for the Company to rely on the market to meet its
13 base load needs?
14 A.Even if Idaho Power could rely on the regional
15 power market as an alternative to building new
16 generation, I believe that relying on the market carries
17 greater risk. Over the long term, the market could
18 arguably be the least cost source for new supply.
19 However, most customers are unable or unwilling to
20 tolerate the price volatility that comes with significant
21 exposure to the market. Moreover, besides its effect on
22 customers, the risk of over-reliance on the market can
23 potentially weaken the financial strength of utili ties if
24 extreme price excursions occur.
25 Q.Idaho Power has contended that the primary
CASE NO. IPC-E-09-03
06/19/09 1044 STERLING, R (Di) 26
STAFF
1 reason for needing new generation to be located near its.2 load center is because of transmission constraints on
3 imports from the Northwest. Are transmission upgrades a
4 viable al ternati ve to a new base load power plant?
5 A.I would characterize transmission upgrades as a
6 necessary component, rather than an al ternati ve, in Idaho
7 Power's plans to meet future load requirements. The
8 Company has been upgrading portions of its transmission
9 system to reduce constraints. The Brownlee to Oxbow
10 project was completed in late 2003. It increased the
11 Brownlee East capacity by approximately 100 MW. Idaho
12 Power also completed an upgrade of the Borah-West path in
.13 May 2007. This upgrade increased the Borah-West
14 transmission capacity by 250 MW. The increased
15 transmission capacity is available to serve Idaho Power's
16 native load requirements with new generating resources
17 located east of the Borah-West constraint (eastern
18 Idaho). Even with these improvements, however, Idaho
19 Power's transmission system is still constrained at
20 certain times for imports of energy from the Pacific
21 Northwest.
22 In its 2006 IRP and 2008 IRP Update, Idaho
23 Power has expanded its analysis of possible transmission
24 proj ects, associated costs, and potential risks. Based.25 on its analysis, the preferred portfolio incorporates a
CASE NO. IPC-E-09-03
06/19/09 1045 STERLING, R (Di) 27
STAFF
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1 transmission upgrade from northeast Oregon to southwest
2 Idaho. Called the Boardman to Hemingway project, the 500
3 kilovolt (kV) transmission line would increase
4 transmission capacity from the Northwest by 225 MW. In
5 addi tion, Idaho Power and PacifiCorp are proceeding with
6 the Gateway West project, a plan to build more than 1, 000
7 miles of 500-kV transmission lines across Wyoming and
8 southern Idaho.
9 Q.Do you believe that conservation is a viable
10 al ternati ve to adding a new generating resource?
11 A.A diverse resource portfolio should include
12 cost effective energy conservation. Conservation is part
13 of Idaho Power's resource planning strategy. The Company
14 has several DSM programs that have been underway for many
15 years. Other programs have been recently expanded or
16 modified, while a few new programs are just now being
17 introduced. The programs are aimed at both energy
18 savings as well as peak demand reduction. Programs are
19 available for all customer classes.
20 For long-term planning of energy conservation
21 and demand response programs Idaho Power relies on the
22 IRP process, consultation wi th its Energy Efficiency
23 Advisory Group and participation in regional energy
24 efficiency organizations. The goal of the processes is
25
CASE NO. IPC-E-09-03
06/19/09 1046 STERLING, R (Di) 28
STAFF
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.
.
1 to identify opportunities, evaluate them, and pursue all
2 of those that are cost-effective.
3 Staff believes that Idaho Power has
4 strengthened its commitment to achieving all
5 cost-effecti ve energy efficiency and demand response
6 potential. The Company primarily uses the tariff
7 Schedule 91 Energy Efficiency Rider (Rider) to fund DSM
8 programs. Recently, the Commission in Case No.
9 IPC-E-09-05, Order No. 30814 increased the Idaho Rider
10 from 2.5 percent of base rate revenues to 4. 75 percent.
11 The increase is intended to fund new and expanded energy
12 efficiency and demand response programs as well as
13 address a negative balance in the Rider account.
14 Conservation programs of the past, as well as
15 programs planned and underway now, have certainly proven
16 that energy usage can be reduced cost effectively.
17 However, even the most successful conservation programs
18 have historically been unable to keep pace with the
19 increasing load growth that must be met. In my opinion,
20 conservation programs by themselves cannot achieve enough
21 demand reduction to realistically satisfy the Company's
22 immediate need to meet growing loads.
23 Q.Do you believe that the other resource
24 alternatives that you just discussed can collectively
25 substi tute for a new base load plant?
CASE NO. IPC-E-09-03
06/19/09 1047 STERLING, R (Di) 29
STAFF
.
.
.
1 A.No, I do not. While I believe each of these
2 other al ternati ves is important, all of them are either
3 already being pursued and are a part of the Company's
4 plan going forward, or they cannot be counted on with
5 certainty. There may be some opportunities for increased
6 efforts as more options become cost effective,
7 particularly with regard to conservation and demand
8 response, but I believe a new base load resource is still
9 necessary.
10 OVERVIEW OF THE REQUEST FOR PROPOSAL PROCESS
11 Q.Please provide a brief overview of the request
12 for proposals (RFP) issued by Idaho Power.
13 A.As called for in its 2006 IRP, Idaho Power
14 issued the RFP on April 1, 2008. The RFP sought
15 proposals for between 250 and 600 MW of dispatchable
16 energy. The RFP specified that only power purchase
17 agreements (PPAs) or tolling agreements (TAs) to supply
18 firm or unit contingent energy would be considered.
19 Projects were required to commence energy deliveries not
20 later than June 1, 2012. At a minimum, proposals were
21 required to include a 15-year term with at least one
22 5-year contract renewal option; however, different
23 contract terms and options were encouraged.
24 Q.What did the RFP say with regard to
25 participation by Idaho Power or its affiliates?
CASE NO. IPC-E-09-03
06/19/09 1048 STERLING, R (Di) 30
STAFF
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.
.
1 A.The RFP specified that proposals from any Idaho
2 Power affiliates would not be accepted. However, it also
3 clearly stated that Idaho Power would submit and evaluate
4 a natural gas-fired combined cycle combustion turbine
5 (CCCT) to be constructed by Idaho Power as one of the
6 resource al ternati ves. This proposal was designated as
7 the Benchmark Resource.
8 Q.Did the RFP specify the types of generating
9 resources that would be considered?
10 A.No, it required only that proposals use
11 commercially viable dispatchable technology.
12 Nevertheless, I think it was quite clear that the Company
13 was seeking proposals for gas-fired CCCTs. First, the
14 RFP was designated as a "base load RFP." It also
15 referred to the 2006 IRP' s initial identification of the
16 need for coal-fired base load generation and the
17 Company's subsequent decision to pursue the development
18 of a gas-fired CCCT instead. The requirement that the
19 proj ect be dispatchable eliminated just about all
20 technologies except gas-fired generation.
21 Q.Did the RFP specify where proposed projects
22 must be located?
23 A.No, but it did make clear that the preferred
24 point of deli very was a direct connection with Idaho
25 Power's transmission system near the Treasure Valley load
CASE NO. IPC-E-09-03
06/19/09 1049 STERLING, R (Di) 31
STAFF
.1 center.
2 Q.Why did Idaho Power amend its RFP from an
3 ini tial request of from 250 to 600 MW down to a request
4 of up to 300 MW?
5 A.Al though the RFP initially stated that Idaho
6 Power anticipated acquiring between approximately 250 MW
7 to 600 MW, it made clear that the higher amount would be
8 used to serve potential new load and that a final
9 decision on the quantity sought would be made later. On
10 June 25, 2008, Idaho Power issued an addendum reducing
11 the RFP requested quantity to approximately 300 MW. The
12 Company indicated that the lower amount was based on a
.13 revised assessment of its needs and its discussions with
14
15
companies proposing new large loads.
Q.What is a tolling agreement (TA)? How does it
16 differ from a power purchase agreement (PPA)?
17 A.In the electric industry, a tolling agreement
18 is an arrangement in which fuel is purchased by the
19 utility and delivered to anon-utility owned plant, then
20 burned or "converted" to generate electricity in exchange
21 for a pre-established tolling charge. The utility may be
22 responsible for procuring the fuel and arranging for its
23 delivery, and is required to assume all price risk
24 associated with its purchase. The power plant owner must.25 own and maintain the plant, and operate according to a
CASE NO. IPC-E-09-03
06/19/09 1050 STERLING, R (Di) 32
STAFF
.
.14
1 schedule determined by the utility.
2 In a power purchase agreement, the utility does
3 not own the plant and is not responsible for purchasing
4 the fuel or arranging for its delivery. All fuel price
5 risk is normally assumed by the plant owner. The utility
6 is able to dispatch the plant, and energy is purchased at
7 an agreed upon price.
8 Q.The RFP stated that all bids would be compared
9 to a "Benchmark Resource" proposal. What was the
10 Benchmark Resource proposal?
11 A.The Benchmark Resource was a proposal made by a
12 team of Idaho Power's own employees for a CCCT to be
13 constructed by the Company. The RFP did not divulge any
details of the Benchmark Resource, including its size,
15 where it would be located, or the exact type of equipment
16 it would use. At the time the RFP was issued, it was my
17 understanding that although development of the Benchmark
18 Resource proposal was already underway, it was still a
19 work in progress. Because the Benchmark Resource
20 proposal was ultimately selected as the winning proposal,
21 I will discuss it in much more detail later in my
22 testimony.
23 Q.Do you believe utili ties should permit
24 self-build proposals to be made in RFPs?.25 A.Yes, in most cases. As long as the utility has
CASE NO. IPC-E-09-03
06/19/09 1051 STERLING, R (Di) 33
STAFF
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1 the resources and experience to carry out its proposal, I
2 believe it should be allowed to compete with other
3 bidders. In some cases the utility may be able to make a
4 proposal that is less costly and better suited to meeting
5 the needs of its customers. To prohibit self-build
6 proposals would be to deny ratepayers an opportunity for
7 possibly the best proj ect at the lowest cost.
8 If self-build proposals are allowed in RFPs,
9 however, I also believe that safeguards should be in
10 place to guard against impropriety. The RFP process
11 should insure that the utility does not have an unfair
12 advantage and that all proposals are evaluated fairly.
13 Q. Why was the RFP restricted to only power
14 purchase agreements and tolling agreements? Why were
15 build-and-transfer proposals not allowed?
16 A.The Company's reasons for not allowing
17 build-and-transfer proposals are discussed in the direct
18 testimony of Idaho Power witness Bokenkamp. In short,
19 the Company believed that it would have needed detailed
20 design specifications in order to eliminate significant
21 design differences between proposals and to avoid a
22 complicated and subj ecti ve evaluation process. The
23 Company believed that, due to its earlier decision to
24 accelerate the online date from 2013 to 2012 and the
25 lead-time required for obtaining major equipment, the
CASE NO. IPC-E-09-03
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1052
.1 Company did not have enough time to prepare a detailed
2 design specification and release the RFP in time to meet
3 the 2012 online date.
4 Q.Do you believe Idaho Power's rationale for not
5 allowing build and transfer proposals is reasonable?
6 A.I understand the Company's concerns about
7 needing detailed design specifications in order to insure
8 that the Company would receive quality equipment, exactly
9 the design features it wanted, and that the facility was
10 easy to operate and maintain. I also understand the
11 advantages of having direct control over proj ect design
12 and construction, and the possible difficulties that.13
14
might be encountered in proposal evaluation if proposals
contained design differences. Nevertheless, by not
15 allowing build-and transfer proposals, Idaho Power may
16 have locked potential bidders out of the process and
17 ul timately denied ratepayers of the possibility of a high
18 quality, lower cost plant.
19 Al though I understand the timing difficulties
20 explained by Idaho Power, I think the excuse of not
21 having time to prepare detailed design specifications is
22 a weak one. Construction of a new base load plant has
23 been anticipated for many years, and it was no surprise
24 that a project of this size and type would have a long.25 planning and construction lead time. The proj ect has a
CASE NO. IPC-E-09-03
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1053 STERLING, R (Di) 35
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1 20-year net present value of roughly $2. 7 billion and
2 will be expected to be in service for 35 years. Given
3 the magnitude of the project, I do not think it would
4 have been unreasonable for Idaho Power to have built
5 several additional months into its RFP schedule for
6 detailed design specifications to be prepared so they
7 could be used as the basis for build-and transfer
8 proposals. Much of the time Idaho Power may have "saved"
9 during the RFP stage by not preparing a detailed proj ect
10 design will be made up later when detailed design work
11 must be done before construction begins. Moreover, the
12 Company ultimately delayed the proj ect online date for
13 other reasons.
14 Q.Do you believe that build-and-transfer
15 proposals would have been submitted if the RFP would have
16 allowed them?
17 A.Yes, I do. I was personally contacted by two
18 potential bidders who expressed concern and frustration
19 that the RFP was not allowing build-and-transfer
20 proposals to be submitted. Other Staff were contacted by
21 two additional bidders expressing similar concerns. The
22 potential bidders stated that their business is building
23 new power plants, not owning and operating them. Unless
24 they could partner with another entity willing to own and.25 operate the plant, they could not participate in the RFP.
CASE NO. IPC-E-09-03
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20
1 Rather than seeking a partner, they indicated that they
2 would probably choose to not even submit a bid. It is
3 difficult to be reassured that the winning proposal in
4 the RFP is the best proposal if some interested bidders
5 chose to not submit bids because they were shut out of
6 the process by the Company.
7 Q.Do you know of any other concerns that
8 potential bidders may have had that caused them not to
9 participate?
10 A.Yes, one potential bidder who contacted me was
11 concerned that Idaho Power was allowing a self-build
12 proposal to be submitted. Their concern was that the RFP
13 process might be a sham just to satisfy Commission
14 requirements, and that in the end, Idaho Power would
15 select its own self-build proposal regardless of any
16 other bids that might be submitted.
17 Q.Do you know for sure whether any of the bidders
18 who contacted Commission Staff ultimately decided not to
19 submit bids?
A.No, I do not. In fact, Staff never asked any
21 of the potential bidders who expressed concerns to
22 identify themselves, so it would have been impossible to
23 know whether they submitted a bid. I do know, however,
24 that not all of the potential bidders who attended the
25 Pre-Bid conference submitted bids.
CASE NO. IPC-E-09-03
06/19/09 1055 STERLING, R (Di) 37
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20
21
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24.25
1 Q.Idaho Power stated that it hired RW Beck as an
2 independent consultant to assist with the RFP. What role
3 did the consultant play?
4 A.The RFP informed bidders that Idaho Power
5 planned to use RW Beck Inc. as an independent consultant
6 to help ensure that the RFP was conducted fairly and
7 properly and that all offers were treated obj ecti vely and
8 consistently. Possible tasks of the independent
9 consul tant were listed as follows:
10 Consult with Idaho Power in preparing the RFP
11 and evaluation criteria.
12 Consul t with Idaho Power on evaluation of
13 proposals;
14 Independently score all or a sample of the
15 proposals to determine whether the selection of
16 the short-list is consistent with the scoring
17 criteria.
18 Compare the results of the independent
19 consul tant' s scoring with Idaho Power's scoring
and work with Idaho Power to attempt to
reconcile and resolve scoring differences.
Prepare reports as requested by Idaho Power
including reports to the Idaho and Oregon
Commissions as requested by Idaho Power.
Q.Did the independent consultant perform all of
CASE NO. IPC-E-09-03
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1 the possible tasks that were identified?
2 A.No, R. W. Beck was only used to assist in
3 preparing the RFP and evaluation criteria, and to provide
4 guidance to the evaluation team. R. W. Beck was not asked
5 to independently score any of the proposals because of
6 cost considerations and the likelihood in the Company's
7 estimation that it would simply duplicate the scores of
8 Idaho Power.
9 Proposals
10 Q.Please summarize the response Idaho Power
11 received to its RFP.
12 A.Idaho Power received proposals from six bidders
13 by the October 17, 2008 RFP deadline. One proposal was
14 immediately rej ected because the bidder failed to submit
15 a Notice of Intent to Bid as required by the RFP. The
16 remaining five bidders proposed 13 alternative proj ects,
17 differing primarily by generating technology, equipment,
18 proj ect configuration and location. All of the proposals
19 were for either gas-fired simple or combined cycle
20 proj ects. Obviously, one of the bids was the Benchmark
21 Resource proposal. Only one of the al ternati ves was for
22 a PPA. That proposal was eliminated during the initial
23 screening stage, however, for not meeting the requirement
24 to deliver energy and capacity to Idaho Power's system.
25 Except for the Benchmark Resource proposal, all of the
CASE NO. IPC-E-09-03
06/19/09 1057 STERLING, R (Di) 39
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17
18
1 remaining proposals were for tolling agreements. Each
2 proj ect proposed, by itself, would have satisfied Idaho
3 Power's need for approximately 300 MW, and none would
4 have needed to be combined with other proj ects or
5 proposals.
6 Q.Do you believe that the number and variety of
7 proposals received was sufficient to give reasonable
8 assurance that all realistic options could be considered
9 and that a competitive price could be obtained?
10 A.As I stated earlier, I have concerns that some
11 potential bidders may have chosen to not participate
12 because the RFP did not solicit build-and-transfer
13 proposals or because of concerns that all proposals would
14 not be evaluated fairly. This section of Staff's direct
15 testimony contains confidential information subject to
16 protective agreement.
I would have
19 certainly li ked to see more bidders participate. There
20 were fewer bids received in this RFP than in previous
21 RFPs for the Bennett Mountain and Danskin projects.
22 Obviously, more bids would have increased the chances
23 that a proposal superior to the Company's Benchmark
24 Resource proposal would have been selected.
25 The fact that only one PPA proposal was
CASE NO. IPC-E-09-03
06/19/09 1058 STERLING, R (Di) 40
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1 submi tted is neither surprising or of much concern to me.
2 Few developers are willing to take all of the gas price
3 risk for such fuel intensive proj ects, especially given
4 the length of the proposed agreement and the historical
5 volatility of natural gas prices.
6 Of the bids that were submitted, however, all
7 of them were made by qualified developers. Furthermore,
8 in my opinion, all of the bids that made it to the final
9 round of screening were extremely competitive.
10 Q.Do you believe that Idaho Power's Benchmark
11 Resource proposal had an advantage over other proposals?
12 A.I do not believe that it had an actual
13 advantage, but I definitely believe there was a
14 perception amongst some prospective bidders that it did
15 have an advantage. At the Pre-Bid Conference, some
16 bidders expressed concern that Idaho Power's Benchmark
17 Resource proposal had an advantage over other potential
18 bids because the Company had already made reservation
19 agreements with Siemens for gas and steam turbines. The
20 reservation agreements required a deposit of $8.7 million
21 to Siemens that would be forfeited if Idaho Power
22 canceled the equipment reservation or did not assign the
23 equipment to someone else. Idaho Power informed
24 potential bidders that it would not be willing to allow
25 another bidder to purchase the equipment from the Company
CASE NO. IPC-E-09-03
06/19/09 1059 STERLING, R (Di) 41
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1 if that other bidder's proposal was selected in the RFP.
2 By locking up equipment before the RFP was issued, Idaho
3 Power was taking a risk that it would lose its deposit if
4 it was not the winning bidder. Other potential bidders
5 were not willing to make such a large potentially
6 nonrefundable deposit. Some felt that they would be at
7 greater ris k of losing an equipment deposit because Idaho
8 Power could argue that the deposits were necessary
9 regardless of whether they made the winning bid and that
10 the Company could seek recovery of lost deposits through
11 the Commission.
12 I do not believe that the potential bidders'
13 concerns were warranted because Idaho Power did not
14 obtain any cost advantage by reserving equipment early,
15 nor were any points awarded in the proposal scoring for
16 having reserved equipment. Nevertheles s, I think some
17 other potential bidders had a perception that Idaho
18 Power's self-build proposal had an advantage from the
19 start, which may have deterred some of them from
20 participating.
21 Evaluation of Proposals
22 Q.Please briefly describe the bid evaluation
23 process used by Idaho Power.
24 A.To review and score proposals, Idaho Power
25 assembled an evaluation team consisting of eight
CASE NO. IPC-E-09-03
06/19/09 1060 STERLING, R (Di) 42
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1 employees from various business units of the Company,
2 including-power Production, Planning, Operations,
3 Finance, River Engineering, and Pricing and Regulatory
4 Services.In addition, advisors from the Company's Legal
5 Department and R. W. Beck, a third party consultant,
6 provided guidance to the evaluation team.
7 The evaluation team ranked the proposals using
8 the procedures and criteria outlined in an Evaluation
9 Manual prepared prior to the receipt of bids. Idaho
10 Power prepared the Evaluation Manual with the assistance
11 of R. W. Beck, its consultant. The Eval ua tion Manual
12 identified the criteria upon which the proposals would be
13 scored, assigned a maximum number of points to each
14 criterion, and provided a scoring guide to be used in
15 determining how points would be awarded for each
16 criterion.
17 Idaho Power used a three-stage screening
18 process in evaluating bids. In the first stage,
19 proposals were examined for responsiveness and to verify
20 that all minimum requirements set forth in the RFP had
21 been adequately addressed. This section of Staff's
22 direct testimony contains confidential information
23 subject to protective agreement.
24 In the second stage, proposals were compared
25 and ranked strictly on a cost basis to determine if any
CASE NO. IPC-E-09-03
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1 were substantially more expensive than the others. The
2 obj ecti ve at this stage was not to provide a precise
3 indication of the potential value of the proposals, but
4 rather to provide a good relative comparison of the
5 proposals to each other. Cost comparisons were made
6 between proposals based on the information provided in
7 the bids and on other costs deemed by Idaho Power to be
8 assignable to each proposal. Both fixed and variable
9 costs were included, and costs were calculated at various
10 assumed capacity factors. This section of Staff's direct
11 testimony contains confidential inforiation subject to
12 protective agreement.
13
14 At the Stage 3 screening level, price and
15 non-price factors were scored for each proposal using a
16 weighted scoring system. The factors along with the
17 maximum scores allocated to each category are summarized
18 below:
19 PRICE CRITERIA (60 POINTS)
20 This section of Staff's direct testLmony contains
21 confidential inforiation subject to protective agreement.
22
23 Total 60 points
24 NON-PRICE CRITERIA (40 POINTS)
25 A.Proj ect Development 8 points
CASE NO. IPC-E-09-03
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18
19
20
21
22
23
24
25
1 B.Proj ect Characteristics 8 points
2 C.Product Characteristics 8 points
3 D.Project Locations 8 points
4 E.Environmental 8 points
5 F. Credi t Factors & Financial Strength 8 points
6 Total 40 points
7 This section of Staff's direct testimony
8 contains confidential information subject to protective
9 agreemen t .
10
11
12
13
14
15
16
Q.How were non-price scores determined?
A.To evaluate the bids based on non-price
CASE NO. IPC-E-09-03
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16
1 cri teria, Idaho Power's evaluation team reviewed the
2 proposals and each member of the team awarded a score to
3 each proposal in each non-price category. All team
4 members' scores for all factors were then averaged for
5 each bid. The process was repeated following face-to-
6 face meetings between the team members and the bidders.
7 Q.Do you believe that the non-price criteria used
8 in the evaluation were reasonable?
9 A.I believe the evaluation criteria were
10 reasonable and not intended to favor one proposal over
11 another. The criteria were established prior to the
12 receipt of bids with the guidance and assistance of a
13 third-party consultant. Some of the non-price criteria
14 required subj ecti ve judgment in point factoring, but that
15 is difficult to avoid.
Q.Were all of the exact evaluation criteria and
17 the points associated with each made known to bidders in
18 advance?
19 A.Yes, I believe they were made very clear. The
20 RFP informed prospective bidders that price factors would
21 comprise 60 percent of the evaluation criteria and
22 non-price would comprise 40 percent. In addition, the
23 RFP included a list of all of the non-price factors that
24 would be considered. Exhibit No. 106 is a copy of the
25 scoring criteria that was included in the RFP.
CASE NO. IPC-E-09-03
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1 In some cases, additional explanations and
2 cautions were provided to inform potential bidders of
3 special concerns. For example, the RFP included the
4 following warnings: "Idaho Power is concerned about the
5 impact of degradation of air quality in the Treasure
6 Valley on the long-term availability of energy from
7 generation projects developed in the Treasure Valley.
8 Proposals using generation resources, located in Ada or
9 Canyon Counties, will be stringently scrutinized and may
10 not receive full points for this category. The Company
11 will also consider whether community opposition to a
12 proposed generation facility will delay the completion of
13 necessary facilities."
14 Q. Were transmission costs considered in
15 evaluating bids?
16 A.Yes, transmission costs were considered when
17 evaluating all bids. The transmission cost estimates
18 were based on studies performed by Idaho Power's
19 Transmission business unit for each bid that was
20 submitted.
21 Q.Did the RFP inform bidders of the likely
22 transmission constraints that might be encountered based
23 on where proj ects might be located?
24 A.Al though no specific transmission cost
25 information was included, the RFP did inform bidders that
CASE NO. IPC-E-09-03
06/19/09 1065 STERLING, R (Di) 47
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1 the preferred point of delivery for power is a direct
2 interconnection with Idaho Power's transmission system,
3 located near the Treasure Valley load center. In
4 addi tion, the RFP made clear that most of Idaho Power's
5 long-term rights to transmission are already dedicated to
6 existing resources. Respondents were directed to assume
7 that Idaho Power has no un-utilized, long-term firm
8 transmission rights that are available to be re-directed
9 to transmit proposed resources to Idaho Power's service
10 territory.
11 Q.What natural gas price was used in performing
12 the price analysis?
13 A.Idaho Power initially proposed to use the 2007
14 median forecast of the Northwest Power and Conservation
15 Council. However, believing that the forecast was low
16 compared to prices at the time, Idaho Power revised the
17 forecast to include substantially higher prices. A copy
18 of the revised forecast, was available to all prospective
19 bidders as an addendum to the RFP. Gas prices were
20 assumed to be $9.39 per MMBtu in 2012 and were escalated
21 to $14.29 in 2030. In its sensitivity analysis of
22 short- listed proposals, Idaho Power used a high gas
23 forecast in which prices were assumed to be 150 percent
24 of expected, and a low forecast in which prices were 50
25 percent of expected.
CASE NO. IPC-E-09-03
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1 Q.Were the gas prices assumed in the cost
2 analysis critical to the results?
3 A.Because the same gas price was utilized for all
4 proj ect proposals, proj ects with lower guaranteed heat
5 rates (i. e. higher efficiencies) had lower fuel costs on
6 a cost per MWh basis. In the Aurora analysis, more
7 efficient units were dispatched more often than less
8 efficient ones under all gas price scenarios.
9 Consequently, more efficient units were also able to
10 generate more energy for surplus sales to the regional
11 market, and thus had lower overall costs at both high and
12 low gas prices. As a result, the price ranking of the
13
14
short-listed proposals remained the same under all price
assumptions.
15 Short List Analysis
16 Q.Please describe how Idaho Power developed a
17 short list of proj ects and completed further analysis of
18 the short list proposals.
19 A.After the Stage 2 screening was completed, the
20 top proposals from two bidders and the Benchmark Resource
21 team were short-listed and meetings with representatives
22 of the short-listed entities were held in January 2009.
23 Through these meeting and follow-up phone calls and
24 correspondence, Idaho Power was able to clarify bids,
25 such as defini ti vely determining what things were or were
CASE NO. IPC-E-09-03
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19
20
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22
23
24
25
1 not included in the bid. All short-listed bidders were
2 permi tted to refresh their bids following meetings with
3 Idaho Power's evaluation team. Final negotiations were
4 pursued with all three of the short-listed bidders.
5 Analysis of Final Candidate Proposals
6 Q.Please briefly describe the proj ects that made
7 the final short list.
8 A.This section of Staff's direct testimony
9 contains confidential infor.ation subject to protective
10 agreemen t.
11
12
13
14
15
16
17
CASE NO. IPC-E-09-03
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1
2 Idaho Power's Benchmark Resource proposal was
3 also one of the short-listed finalists. I will discuss
4 that proposal in more detail later in my testimony.
5 Q.How did the overall scores compare for the two
6 top-ranked proposals?
7 A.This section of Staff's direct testimony
8 contains confidential information subject to protective
9 agreeien t .
10
11
12
13
14
15 Q.Please explain the top half of Exhibit No. 107.
16 A.This section of Staff's direct testimony
17 contains confidential information subject to protective
18 agreeien t .
19
20
21
22
23
24
25
CASE NO. IPC-E-09-03
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18
19
20
21
22
23
1
2 Q.This section of Staff's direct testimony
3 contains confidential infor.ation subject to protective
4 agreemen t.
5
6
7
8
9
10
11
12
13
14
15
16
17
24 LAGLEY GULCH PROJECT DESCRIPTION
25 Q.Please describe the Benchmark Resource plant.
CASE NO. IPC-E-09-03
06/19/09 1070 STERLING, R (Di) 52
STAFF
1 A.The proposed Langley Gulch plant would be a.2 natural gas-fired CCCT plant with a nameplate capacity of
3 approximately 330 MWs. The facility would be located on
4 the south side of Interstate 84 approximately four miles
5 south of New Plymouth. The proposed proj ect 's combustion
6 turbine is a single Siemens SGT6-5000F. The plant would
7 also include a Siemens SST-900 steam turbine. The plant
8 would be water-cooled and be equipped with
9 state-of-the-art emission control equipment.
10 Operation
11 Q.Please describe the expected operation of the
12 proposed Langley Gulch plant.
13 A.If approved, the Langley Gulch plant will be.14 operated as a base load facility to serve Idaho Power's
15 load. However, when it is not needed to meet the
16 Company's own load, it would be economically dispatched
17 to make surplus sales whenever it could do so profitably.
18 The opportunity for sales of surplus energy will depend
19 on the difference between the market price of power and
20 the Langley Gulch plant's cost of production. Because
21 Langley Gulch is a very efficient state-of-the-art
22 combined cycle plant, its dispatch cost is lower than
23 many combined cycle plants in the region; consequently,
24 it may frequently be cost effective to operate the plant.25 to make off-system sales. In the Aurora analysis of the
CASE NO. IPC-E-09-03
06/19/09 1071 STERLING, R (Di) 53
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1 proposal, annual capacity factors ranging from 50 percent
2 in 2013 to 75 percent in 2031 have been computed. The
3 plant is currently scheduled to be online in December of
4 2012.
5 Fuel Supply and Transportation
6 Q.As a part of this Application, Idaho Power is
7 requesting that it be allowed to include the proj ect' s
8 cost of fuel, fuel storage and fuel transportation for
9 recovery through the existing Power Cost Adjustment (PCA)
10 mechanism prior to full inclusion in base rates. Do you
11 agree that this is appropriate?
12 A.A maj or component of the operating costs of a
13 combustion turbine generating plant is the cost of
14 natural gas fuel. Staff agrees that reasonable fuel
15 expenses should be approved for PCA recovery prior to
16 full review of normal operational costs in a general
17 revenue requirement case. Operation of the plant will
18 displace other more costly power supplies to the benefit
19 of Idaho Power customers; therefore, costs should be
20 included in the PCA. This is consistent with the manner
21 in which fuel costs were handled for the Bennett Mountain
22 and Danskin plants prior to full inclusion in base rates.
23 After normalized fuel-related costs are included in base
24 rates, only extraordinary fuel costs will flow through
25 the PCA.
CASE NO. IPC-E-09-03
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21
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23
1 Q.How will natural gas be delivered to the plant?
2 A.The location of the proposed Langley Gulch
3 project is approximately three-fourths of a mile from the
4 Williams Northwest Pipeline. A short interconnection
5 pipeline will be constructed as part of the proj ect.
6 Idaho Power has not yet negotiated or entered into any
7 agreements for the purchase of natural gas fuel supplies
8 for the proposed plant.
9 Q.Does Idaho Power have adequate fuel
10 transportation rights on the Williams Pipeline to
11 accommodate the proposed plant?
12 A.Idaho Power already has several gas
13 transportation and storage agreements in order to provide
14 gas to its other gas-fired plants. This section of
15 Staff's direct testimony contains confidential
16 information subject to protective agreement.
17
18
19
Q.How does Idaho Power plan to manage the risk
24 associated with purchasing natural gas for fuel?
25 A.Idaho Power has an Energy Risk Management
CASE NO. IPC-E-09-03
06/19/09 1073 STERLING, R (Di) 55
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1 Policy and natural gas is listed as a permitted
2 commodi ty; however, the policy does not specifically
3 address acquisition of natural gas. An internal Risk
4 Management Committee regularly quantifies, assesses, and
5 manages the Company's risk in accordance with its Risk
6 Management Policy.
7 Idaho Power also has gas hedging guidelines for
8 its existing gas-fired plants (Evander Andrews/Danskin
9 and Bennett Mountain). If the new Langley Gulch plant is
10 approved, I would expect the Company to develop its fuel
11 procurement strategy for both natural gas and
12 transportation capacity as well as expanded hedging
13 guidelines and risk management strategies for all of its
14 gas-fired plants. This section of Staff's direct
15 testimony contains confidential information subject to
16 protective agreement.
17
18 Because it is a base load plant that is
19 expected to operate at a relatively high capacity factor,
20 fuel costs for the Langley Gulch plant will be
21 substantial. A well-planned and executed hedging
22 strategy and risk management plan will be crucial to
23 managing fuel price risk in the future.
24 Wa ter Supply
25 Q.What is Idaho Power's plan for water supply?
CASE NO. IPC-E-09-03
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1 A.Water would be used by the plant primarily for
2 evaporative cooling, which is normally only required in
3 the summer months. Water would be supplied with water
4 from the Snake River. This will require a pumping
5 station and an 8-mile pipeline. Idaho Power has already
6 paid $2.2 million to purchase a water right to secure
7 water for the plant. Construction of the pipeline has
8 been estimated to cost $8.1 million.
9 Electrical Interconnection
10 Q.What transmission work would have to be done in
11 order to interconnect the proposed plant?
12 A.The site is relatively close to existing
13 transmission facilities. As planned, the Langley Gulch
14 plant would be connected to the existing Ontario-Caldwell
15 230 kV line located 2.5 miles away. It would also be
16 looped to connect to a tap approximately three miles from
17 Caldwell via construction of a new 18 mile 138 kV line.
18 The total cost for the transmission work is estimated at
19 $22.1 million. At this point, costs are estimated based
20 on a system impact study and are considered accurate to
21 within plus or minus 20 percent. Detailed costs would be
22 developed in a Design Study.
23 Project Per.its
24
25
Q.Please discuss the air quality permit that will
be required for the proposed plant.
CASE NO. IPC-E-O 9-03
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1 A.One of the most critical permits needed by the
2 proj ect is an air quali ty permit ( Permit to Construct)
3 issued by the Idaho Department of Environmental Quality
4 (DEQ). Idaho Power has reported that the Permit to
5 Construct application is in draft preparation and is
6 expected to be submitted in June 2009.
7 Idaho Power i s air quality consultant has
8 modeled air quality impacts for the Langley Gulch site
9 This section of Staff's direct testimony contains
10 confidential information subject to protective agreement.
11
12
13
14
15
16
17
18
19 Q.Will other permits be required?
A.Yes, other maj or permits include a
21 Comprehensive Plan change from Payette County, a
22 Right-Of-Way permit from BLM for transmission and water
23 lines, a Stream Alteration permit and a Water Quality
24 Certification from the Corps of Engineers, a Groundwater
25 Inj ection permit from the Idaho Department of Water
CASE NO. IPC-E-09-03
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1 Resources, and miscellaneous construction permits. There
2 do not appear to be any insurmountable obstacles in
3 obtaining permits to construct and operate the plant.
4 Project Risks
5 Q.What are some of the risks associated with the
6 Langley Gulch proj ect?
7 A.One risk is simply the risk associated with
8 using natural gas for fuel. As evidenced by the past
9 year, gas prices can be extremely volatile. The proj ect
10 would increase the amount of gas-fired generation in
11 Idaho Power's fleet to over 700 MW. Nevertheless,
12 whether Idaho Power chose the Benchmark Resource proposal
13 or one of the tolling agreements submitted in the RFP, it
14 would face the same risk.
15 However, by choosing the Benchmark Resource
16 proposal, Idaho Power will face some risks that it would
17 have avoided with a tolling agreement. First, by being
18 the owner and operator of the plant, Idaho Power will be
19 responsible for any ongoing capital investment that may
20 be required to keep the plant operational, and for any
21 O&M costs that exceed proj ect estimates. Second, there
22 are potential construction-related risks, perhaps due to
23 delays or liquidated damages, that Idaho Power could be
24 responsible for by constructing the plant itself. Third,
25 by being the proj ect owner, the Company may be liable for
CASE NO. IPC-E-09-03
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1 that will be required during start-testing and
2 commissioning of the plant. Line 45 is an estimate of
3 the cost of transmission upgrades that have been
4 recommended to improve the transmission system but that
5 are not required to integrate the Langley Gulch plant.
6 Line 46 is a 20 percent contingency for transmission
7 costs. The transmission estimate included in the
8 Benchmark Resource bid was deemed to be accurate to
9 within plus or minus 20 percent, so the 20 percent
10 contingency was not included in the original bid. The
11 "sub-synchronous resonance" ( SSR) Study/Implementation
12 cost of $1 million included on line 47 refers to analysis
13 Idaho Power believes it will need to do to determine
14 whether the Langley Gulch facility will cause potentially
15 harmful interactions with other parts of the Company's
16 transmission system.
17 Q.Please discuss the "Soft Cap" proposed by Idaho
18 Power.
19 A.The Company has proposed that the Commitment
20 Estimate be treated as a "Soft Cap." Idaho Power
21 proposes that all costs up to the $427 million Commitment
22 Estimate be pre-approved under Idaho Code § 61-541 and
23 that any costs above this amount be brought before the
24 Commission for specific approval.
25 Q.Do you believe the Commission should allow in
.
CASE NO. IPC-E-09-03
06/19/09 1081 STERLING, R (Di) 63
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1 the Commitment Estimate all of the costs requested by
2 Idaho Power?
3 A.No, I do not.
4 Q.What guidelines do you believe the Commission
5 should follow in determining an appropriate Commitment
6 Estimate amount?
7 A.I believe that only those costs that are known
8 wi th reasonable certainty and based on a competi ti ve
9 procurement process be approved for recovery under Idaho
10 Code § 61-541. Approximately three fourths of the cost
11 items in the Commitment Estimate are known with certainty
12 and competitively procured. Contracts have been signed
13 wi th Siemens Power Equipment for the gas and steam
14 turbines, and an EPC contract has also already been
15 signed for a specific amount. Other amounts included in
16 the Commitment Estimate are based on estimates and
17 contingencies, and are not known with enough certainty to
18 be included in a Commitment Estimate. While some of the
19 estimated costs will almost certainly be incurred, I do
20 not believe they should be subject to pre-approval under
21 Idaho Code § 61-541. Estimated costs and contingencies
22 should be subj ect to the usual rigorous prudence
23 standards to which other utility investments are held.
24 Q.Do you believe that a Soft Cap, regardless of
25 the amount, offers sufficient protection to ratepayers
CASE NO. IPC-E-09-03
06/19/09 1082 STERLING, R (Di) 64
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1 that costs will be controlled?
2 A.No, I think it is also necessary to establish
3 an absolute "not to exceed" amount, or Hard Cap, to
4 protect ratepayers in the event extreme costs must be
5 incurred to complete the plant and make it operational.
6 If unforeseen circumstances were to occur and costs were
7 to balloon out of control, Idaho Power should not be
8 allowed to present an endless parade of cost approval
9 requests to the Commission claiming that unless the
10 additional investment is made, the plant cannot come
11 online and all investment up to that point is wasted.
12 A Hard Cap will provide incentives for the Company to
13 contain costs and manage the proj ect efficiently.
14 Q.How do you propose to establish a "not to
15 exceed" or Hard Cap limit?
16 A.I propose that a Hard Cap be established that
17 is equal to the expected proj ect cost plus a reasonable
18 contingency for those portions of the project cost that
19 were based on estimates.
20 Q.Please discuss how you propose to determine an
21 appropriate Commitment Estimate amount. Please
22 specifically identify any amounts you propose not to
23 include in the Commitment Estimate and explain why you
24 propose to exclude them..25 A.My recommended Commitment Estimate amount is
CASE NO. IPC-E-09-03
06/19/09 1083 STERLING, R (Di) 65
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1.2
3
4
5
6
7
8
9
10
\11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
shown on Exhibit No. 109. On the right side of the
exhibi t, I have shown three primary columns. In the
leftmost column, I have simply reproduced the Commitment
Estimate proposed by Idaho Power. The middle column
labeled "Soft Cap" shows my recommendations for a
commi tment estimate. The right hand column labeled "Hard
Cap" is my "not to exceed" recommendation.
Within each primary column for the Soft Cap and
the Hard Cap, I show a percentage amount that I recommend
should be allowed. For example, I recommend that 100
percent of the gas turbine, steam turbine and EPC
contract amounts be included in the Soft Cap and Hard Cap
because there is a signed contract and these amounts are
known with certainty. Similarly, any other amounts that
are known with certainty I recommend be included at 100
percent. This would include site procurement on line 18,
NEPA permitting on line 20, Air Permitting on line 21,
Transmission/Network study costs on line 27. Capitalized
property tax is included on line 30 as it is a certain
expendi ture but the actual amounts will vary based on
property valuations and levy rates. I have included
water right costs on line 19 at the exact contract amount
I was able to verify, which is slightly less than the
amount Idaho Power included in its Commitment Estimate
amount.
CASE NO. IPC-E-09-03
06/19/09 1084 STERLING, R (Di) 66
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18
19
20
21
22
23
24
25
1 In the Soft Cap column, I have included many
2 items at only SO percent of the amount estimated by Idaho
3 Power. I am assuming that the accuracy of the estimates
4 for these items is plus or minus 50 percent. For
5 example, the engineer's report used as a basis for the
6 water line construction shown on line 22 states the
7 following:
8 This section of Staff's direct testimony contains
9 confidential infor.ation subject to protective agreement.
10
11
12
13
14
15
16
17
CASE NO. IPC-E-09-03
06/19/09 1085 STERLING, R (Di) 67
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1 Q.It appears that some of the costs included in
2 the Company's Commitment Estimate amount are due to
3 delaying the project's planned online date from June 2009
4 to December 2009. Please explain these costs.
5 A.Idaho Power has added amounts it labeled
6 "Commi tment Estimate Contingencies" to its Commitment
7 Estimate. These are the amounts shown on lines 36-38 of
8 Exhibit No. 109 that I described previously.
9 Q.Do you believe that any of these costs should
10 be recoverable?
11 A.First, we cannot be certain that any of these
12 costs will actually be incurred. However, if they are,
13 because these costs were solely due to Idaho Power
14 delaying the proj ect 's online date by six months, I do
15 not believe they should entirely be the responsibility of
16 ratepayers. All bidders were expected to be able to meet
17 a June 1, 2009 online date, and as far as I know, all of
18 them were willing and able to meet that date. Concerns
19 about financing was the reason given by Idaho Power for
20 the delay, yet this appears to only have been an issue
21 wi th the Company's Benchmark Resource proposal. As a
22 resul t, I do not believe these costs should be included
23 in either the Soft Cap or the Hard Cap.
24 Q.Do you believe that "RFP Team Expenses" (line
25 4 3) should be included in the Commitment Estimate?
CASE NO. IPC-E-09-03
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1086 STERLING, R (Di) 68
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1 A.The team that prepared the Company's Benchmark
2 Resource proposal undoubtedly has incurred costs and will
3 likely continue to incur additional costs, although I
4 cannot confirm the amounts. In any case, this is a cost
5 that should not be included in either the Soft Cap or the
6 Hard Cap. Other bidders would have had to include these
7 costs in their bid amount, so it would be unfair for
8 Idaho Power to exclude them from the Benchmark Resource
9 bid during the evaluation process, but add the costs to
10 its Commitment Estimate after it determined that the
11 Benchmark Resource was the winning bid.
12 Q.What is your recommendation regarding start-up
13 test fuel shown on line 44 of Exhibit No. 109?
14 A.I recommend that none of the costs of start-up
15 test fuel be included in either the Soft Cap or the Hard
16 Cap. Idaho Power's reason for including them is that it
17 believes that because it would have been required to
18 supply fuel for ongoing operations under any of the
19 tolling agreements, it would logically have to also
20 supply any fuel needed for start-up testing. I do not
21 believe this would necessarily be the case, however.
22 Because no final tolling agreements were ever
23 negotiated, we can only speculate about what the terms
24 might have been. However, the draft tolling agreement
25 included with the RFP and provided to all prospective
CASE NO. IPC-E-09-03
06/19/09 1087 STERLING, R (Di) 69
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18
19
20
21
22
23
24
25
1 bidders clearly indicates that bidders, not Idaho Power,
2 would be responsible for the cost of start-up testing
3 fuel. Section 6.5.3.5 of the draft tolling agreement
4 states as follows: "Seller shall reimburse Idaho Power
5 for supplying and delivering the Fuel required during
6 Start-Up Testing to reach the minimum load of the
7 Facility. "
8 This section of Staff's direct testimony
9 contains confidential infor.ation subject to protective
10 agreemen t.
11
12
13
14
15
16
17
CASE NO. IPC-E-09-03
06/19/09 1088 STERLING, R (Di) 70
STAFF
1.2 Q.What is your recommendation regarding
3 transmission upgrades shown on line 45 of Exhibit No.
4 109?
5 A.I recommend that none of the costs of
6 transmission upgrades be included in either the Soft Cap
7 or the Hard Cap.I am not suggesting that upgrades are
8 unnecessary or unwise, or that their cost should be
9 unrecoverable. Instead, because these upgrades are not
10 required as part of the Langley Gulch project, I am
11 recommending that Idaho Power be required to demonstrate
12 the prudence of the investments in a future general rate
.13 case just like it would other new investments in
14 transmission.
15 Q.What is your recommendation regarding the 20
16 percent transmission contingency shown on line 46 of
17 Exhibit No. 109?
18 A.The transmission study conducted by the
19 Company's transmission group included a cost estimate
20 believed accurate to within plus or minus 20 percent.
21 The estimate transmission cost was used in preparing the
22 Benchmark Resource proposal and was also used in
23 comparing and scoring bids; however, Idaho Power
24 recognizes that actual costs could exceed or be less than.25 the estimate.
CASE NO. IPC-E-09-03
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I agree that the transmission contingency might.1
2 be incurred, but I do not agree that the contingency
3 should be allowed as part of the pre-approved Commitment
4 Estimate. Consequently, I recommend that the
5 transmission contingency not be included in the Soft Cap,
6 but included in the Hard Cap.
7 Q.What is your recommendation regarding the SSR
8 ("sub-synchronous resonance") study shown on line 47 of
9 Exhibi t No. 109?
10 A.I recommend that 50 percent of the estimated
11 cost be included in the Soft Cap and 150 percent be
12 included in the Hard Cap. The Company seems to be quite.13 uncertain about what the study may show, and the scope of
14 possible remedies if SSR problems are identified in the
15 study.
16 Q.What is your recommendation regarding the
17 transmission costs shown on line 51 of Exhibit No. 109?
18 A.I recommend that 80 percent of the estimated
19 costs be included in the Soft Cap and 120 percent be
20 included in the Hard Cap. Idaho Power has stated that
21 the transmission cost estimate has an accuracy of plus or
22 minus 20 percent; therefore, actual costs could be as low
23 as 80 percent of the estimate included in the Benchmark
24 Resource bid or as high as 120 percent of the estimate..25 All other projects considered in the bid analysis
CASE NO. IPC-E-09-03
06/19/09
1090 STERLING, R (Di) 72
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1 included transmission cost estimates with the same degree
2 of accuracy; consequently, I would have proposed the same
3 treatment of transmission contingencies had one of them
4 been the winning bidder.
5 Q.What is your recommendation regarding AFUDC
6 costs shown on line 55 of Exhibit No. 109?
7 A.Details of Staff's recommendations are
8 addressed in the testimony of Staff witness Harms.
9 However, in summary, AFUDC will be accrued based on the
10 actual amounts, timing, and borrowing rate for funds
11 needed to construct the plant. Thus, the exact amount of
12 AFUDC incurred can be computed and audited after the
13 plant is completed. Therefore, Staff recommends that the
14 actual amount of AFUDC incurred be recoverable, but that
15 it be considered an addition to both the Soft Cap and the
16 Hard Cap amounts.
17 Q.What are some of the factors you believe the
18 Commission should consider when deciding whether to
19 approve costs above the Commitment Estimate if the
20 Commission decides that those costs should be subject to
21 prudence review and Commission approval?
22 A.Some of the factors which I believe the
23 Commission should consider are the following:
24 the reasonableness of cost;
25 the necessity of the expenditure;
CASE NO. IPC-E-09-03
06/19/09 1091 STERLING, R (Di) 73
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1 the consistency with proj ect plans;
2 the method of selection of contractors,
3 materials, equipment, and vendors;
4 whether the cost is based on competi ti ve
5 procurement of equipment, materials or
6 services,
7 the nature of expense;
8 whether the work is completed on time;
9 whether any costs are penal ties or liquidated
10 damages, and
11 whether costs are consistent with
12 pre-construction estimates.
13 I do not believe that any additional costs
14 caused by Idaho Power's delay or negligence should be
15 recoverable.
16 Q.Are there any additional costs that Idaho Power
17 may incur because of its decision to delay the proj ect i s
18 online date by six months?
19 A.This section of Staff's direct testLmony
20 contains confidential infor,ation subject to protective
21 agreement.
22
23
24
25
CASE NO. IPC-E-09-03
06/19/09 1092 STERLING, R (Di) 74
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1
2
3
4
5
6 On May 28, 2009, Idaho Power notified the
7 Commission of changes to the Company's contract with Hoku
8 Materials, Inc. One of the changes to the contract was a
9 40 MW required reduction in Hoku' s summertime load in
10 2012. I cannot be certain whether Hoku voluntarily
11 agreed to reduce its load during this period or whether
12 Idaho Power required the reduction as a condition of Hoku
13 delaying the start of its contract in the summer of 2009.
14 Nevertheless, Idaho Power presumably would have been able
15 to serve the load if Langley Gulch were available when
16 originally scheduled. Now, with the delayed online date,
17 Idaho Power will lose the revenue it would have otherwise
18 recei ved from Hoku. Depending on the cost Idaho Power
19 would have incurred to serve Hoku during these months,
20 Idaho Power could either make money or lose it due to
21 Hoku' s reduced load.
22 Q.Earlier you discussed the Commitment Estimate
23 and all of the cost elements that compose it. Were all
24 of the cost elements that are included in Idaho Power's
25 proposed Corni tment Estimate included in the Benchmark
CASE NO. IPC-E-09-03
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10
1 Resource proposal that was scored by the Evaluation Team?
2 A. No, not all of the costs were included.
3 Please describe how the Commitment Estimate isQ.
4 different than the Benchmark Resource proposal cost.
5 The Commitment Estimate includes several costsA.
6 and contingencies that were added after the Benchmark
7 Resource proposal was selected. Generally, those costs
8 that were added are the items listed on lines 36-38 and
9 lines 41-47 of Exhibit No. 108.
Q.Do you believe it was appropriate to add costs
11 to the Commitment Estimate that were not included in the
12 Benchmark Resource bid after the Benchmark Resource
13
14
proposal was chosen as the winning bid?
A. In some cases it was appropriate because it was
15 clear that some costs that were Idaho Power's
16 responsibility would be added to every bid if chosen.
17 However, in other cases, while I believe the costs are
18 likely to be incurred, I think they should have been
19 included in the Benchmark Resource proposal cost that was
20 actually considered in scoring the proposals.
21 Did Idaho Power reevaluate the costs of the topQ.
22 proposals and revise bid price scores based on the costs
23 included in the Commitment Estimate?
24 Yes, in response to a production request, IdahoA.
25 Power did compute revised price scores based on the
CASE NO. IPC-E-09-03
06/19/09
1094 STERLING, R (Di) 76
STAFF
1 Commitment Estimate amount.The results of that.2 re-scoring are shown on Exhibit No.113.This section of
3 Staff's direct testimony contains confidential
4 information subject to protective agreement.
5
6
7
8
9
10
11
12
13.14
15
16
17
18
19
20
21
22
23
24.25
CASE NO.I PC-E-O 9-03 1095 STERLING,R (Di)7706/19/09 STAFF
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6
7
8
9
10
11
12
13 Idaho Code § 61-541
14 Q.Idaho Power has requested approval of the
15 proposed Langley Gulch project under Idaho Code § 61-541.
16 Please discuss the requirements of this new legislation.
17 A.For reference purposes, I have included a copy
18 of Idaho Code § 61-541 as Exhibit No. 115. Idaho Code
19 § 61-541 provides that utilities may file an application
20 with the Commission for an order specifying in advance
21 the ratemaking treatments that shall apply when the costs
22 of the proposed facility are included in the utility's
23 revenue requirements. Among the ratemaking treatments
24 the Commission may apply are to specify the maximum
25 amount of costs that will be included in rates at the
CASE NO. IPC-E-09-03
06/19/09 1096 STERLING, R (Di) 78
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1 time without the utility having the burden of moving
2 forward with additional evidence of the prudence and
3 reasonableness of such costs . Effectively, this means
4 that the Commission may pre-approve some portion of the
5 proj ect 's expected costs.
6 How would approval under Idaho Code § 61-541Q.
7 differ from approval that has been given to prior new
8 generation proj ects?
9 Idaho Code § 61-541 provides that all amountsA.
10 approved under the legislation not be subject to further
11 prudence review. This is really no different than the
12 process recently used in approving Idaho Power's Evander
13
14
Andrews/Danskin and Bennett Mountain plants because a
CPCN for those plants was granted, along with a
15 commitment estimate, prior to proj ect construction. Any
16 costs in excess of the commitment estimates approved in
17 those cases were required to be submitted to the
18 Commission for later approval.
19 Q.Do you believe Idaho Power has met the
20 requirements of Idaho Code § 61-541 with its filing in
21 this case?
22 A.Idaho Code § 61-541 requires the Commission in
23 reviewing the application to determine whether:
24 (i) The public utility has in effect a
25 commission-accepted integrated resource plan;
CASE NO. IPC-E-09-03
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1 (ii) The services and operations resulting
2 from the facility are in the public interest and will not
3 be detrimental to the provision of adequate and reliable
4 electric service;
5 (iii) The public utility has demonstrated that
6 it has considered other sources for long-term electric
7 supply or transmission;
8 (i v) The addition of the facility is
9 reasonable when compared to energy efficiency,
10 demand-side management and other feasible al ternati ve
11 sources of supply or transmission; and
12 (v) The public utility participates in a
13 regional transmission planning process.
14 Assuming the Commission makes a ruling in this
15 case addressing whether the proposed proj ect is in the
16 public interest, I believe all of these requirements will
17 have been satisfied. Idaho Power does have an
18 acknowledged integrated resource plan on file with the
19 Commission. In the IRP, the utility considers other
20 sources of supply, including transmission, energy
21 efficiency and demand-side management. Idaho Power also
22 participates in multiple regional transmission planning
23 processes.
24 Q.If the Commission wishes to approve the
25 Company i S request to construct Langley Gulch, must it do
CASE NO. IPC-E-09-03
06/19/09 1098 STERLING, R (Di) 80
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1 so under Idaho Code § 61-541?
2 A.No, although Idaho Power has requested approval
3 under Idaho Code § 61-541, the Commission may accept,
4 deny of modify the proposed ratemaking treatment proposed
5 by the utility. In addition, the Commission may
6 determine the maximum amount of cost to be pre-approved
7 for inclusion in rates without the utility having the
8 burden of moving forward with additional evidence of the
9 prudence and reasonableness of such costs. The
10 Commission can require that amounts above the maximum be
11 subj ect to the usual requirements of demonstration of
12 prudence and reasonableness after the actual expenditures
13 have been made and the utility seeks to recover them in
14 rates.
15 Q.Do you believe preapproval of the Langley Gulch
16 proj ect is warranted in this case?
17 A.Because it is likely that preapproval is
18 necessary in order for Idaho Power to obtain financing, I
19 believe that those portions of the estimated project cost
20 that are known with a high degree of certainty be
21 preapproved under Idaho Code § 61-541. However, as I
22 explained earlier, I believe that some portions of the
23 proj ect 's estimated costs are not known with high enough
24 certainty to merit preapproval. Regardless, issuance of
25 CPCNs in the recent past have effectively provided
CASE NO. IPC-E-09-03
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1 preapproval anyway.
2 TOTAL EXPECTED POWER COST
3 Q.What is the total expected power cost for the
4 proposed Langley Gulch plant?
5 A.This section of Staff's direct testimony
6 contains confidential information subject to protective
7 agreemen t .
8
9
10
11
12 It is also extremely important to recognize
13 that the power cost computed for analysis purposes is
14 highly dependent on the cost of gas that is assumed in
15 the analysis. Idaho Power's analysis assumed a starting
16 gas price of $9.39 per MMBtu in 2012, increasing to
17 $15.55 per MMBtu in 2036. These estimates seem high
18 based on recent gas prices and forecasts, but prices
19 could turn out to be much different than assumed in the
20 analysis or that are forecasted today. It should also be
21 pointed out that the actual cost will ultimately also
22 depend on the actual capacity factor. The actual
23 capaci ty factor will vary from year to year and will be
24 dri ven by loads, weather, and gas and electric market.25 condi tions. Higher capacity factors would lower the cost
CASE NO. IPC-E-09-03
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1 estimate while lower capacity factors would increase it.
2 The cost estimate I have included here is only intended
3 to be a rough indication of the total cost of energy
4 produced by the plant.
5 Q.Are avoided cost rates for PURPA contracts a
6 fair comparison to expected costs of the Langley Gulch
7 plant?
8 A.I do not believe avoided cost rates used for
9 PURPA QF contracts are a fair comparison to the cost
10 Idaho Power will pay for power produced by the Langley
11 Gulch plant. Although avoided cost rates are computed
12 based on a surrogate combined cycle combustion turbine
13
14
(SAR) very similar to Langley Gulch, assumptions about
how the SAR and the Langley Gulch plant would be operated
15 are much different. Avoided cost rate computations
16 assume that the SAR plant is not economically dispatched
17 and is instead operated at nearly its maximum achievable
18 capaci ty factor. This is consistent with PURPA QFs that
19 are not dispatchable and operate at as high a capacity
20 factor as they can. The Langley Gulch plant clearly will
21 be dispatchable, and will be operated only when it is
22 cost effective to meet load or make surplus sales.
23 Unlike the assumptions for the SAR or PURPA QFs, it will
24 not be operated when it is not needed or when it is not
25 profi table. Langley Gulch will almost certainly have a
CASE NO. IPC-E-09-03
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1 capaci ty factor less than the capacity factor assumed for
2 the SAR. Consequently, there will be fewer hours over
3 which to spread fixed costs, resulting in a higher cost
4 per kWh than the PURPA avoided cost rate.
5 Q.How does the capital cost of the Langley Gulch
6 proj ect compare to other CCCT al ternati ves?
7 A.Based on the $427 million Commitment Estimate
8 proposed by Idaho Power and Langley Gulch's 330 MW
9 nameplate capacity, the capital cost is $1,294 per kW.
10 By comparison, the current surrogate CCCT cost (which is
11 based on current costs as reported by the Northwest Power
12 and Conservation Council) used to establish the Idaho
13
14
published avoided cost rate is $1,313/kW. Idaho Power's
2009 IRP proposes to use approximately $1,350 per kW for
15 its assumption of new CCCT costs. PacifiCorp' s just
16 filed 2008 IRP shows new cost ranging from $1,180 to
17 $1,491/kW for comparable plants, and Avista' s nearly
18 completed 2009 IRP shows new CCCT capital costs of
19 approximately $1,050/kW. All cost listed here include an
20 assumed amount for AFUDC. A 2008 RFP issued by
21 PacifiCorp returned CCCT capital costs in the range of
22 $1,000 to $1,300/kW.
23 Comparisons could also be made to recent
24 transactions by Avista and PacifiCorp. In Avista' s
25 current general rate case, Avista is seeking approval of
CASE NO. IPC-E-09-03
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1102 STERLING, R (Di) 84
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a tolling agreement for the Lancaster CCCT plant in.1
2 Northern Idaho. Avista and i ts consultant separately
3 performed net present value and DCF analysis to compare
4 the Lancaster tolling agreement to other theoretical
5 tolling agreements based on capital construction costs of
6 existing regional CCCT resources. The analysis also
7 compared the agreement to expected costs to construct a
8 new CCCT in the region. The analyses show that the
9 tolling agreement is essentially equivalent to a Company
10 owned greenfield plant with a capital cost of about
11 $530/kW. Further analysis shows that the value of the
12 tolling agreement is equivalent to paying up to $677 /kW..13 Another recent example of a comparable CCCT transaction
14 was the purchase by PacifiCorp of the existing 500 MW
15 Chehalis CCCT at a cost of approximately $610/kW. It
16 should be pointed out, however, that both the Lancaster
17 plant and the Chehalis plants were built several years
18 ago, so their costs may not be directly comparable to a
19 new plant built today like Langley Gulch.
20 FUL COSTS
21 Q.Idaho Power is requesting that the Project's
22 prudently incurred costs for fuel, fuel storage, and fuel
23 transportation for recovery through the Company's
24 existing Power Cost Adjustment ("PCA") mechanism. Do you.25 agree that this would be appropriate?
CASE NO. IPC-E-09-03
06/19/09
1103 STERLING, R (Di) 85
STAFF
.
.
.
1 A.Yes, I do believe it would be appropriate to
2 include these costs in the PCA until the Company's next
3 general rate case when these costs can be normalized and
4 included in base rates. Once these costs are included in
5 base rates, only deviations from the normalized amounts
6 of these costs would be included in the PCA, subject to
7 the currently-approved 95-5 sharing percentages.
8 STAFF CONCLUSIONS
9 Q.Are you convinced that Idaho Power has
10 demonstrated a genuine need for the Langleý Gulch plant?
11 A.Yes, I am convinced that a new base load power
12 plant is needed by Idaho Power beginning in 2012 and is
13 in the public interest. The proj ect is consistent with
14 the Company's acknowledged IRPs. Under the right set of
15 weather, load and hydro conditions, it could turn out
16 that the plant may not actually be needed as soon as
17 planned, but I believe it would be unacceptably risky to
18 delay the plant. I do not believe Idaho Power could have
19 pursued enough other al ternati ves that collectively could
20 eliminate or be an acceptable substitute for the Langley
21 Gulch plant.
22 Q.Do you believe that the request for proposals,
23 the criteria used by Idaho Power to evaluate bids, and
24 analysis of the bids was fair to all proposals?
25 A.I believe that the RFP was fair and that the
CASE NO. IPC-E-09-03
06/19/09 1104 STERLING, R (Di) 86
STAFF
.
.
.
1 evaluation criteria were reasonable for those proposals
2 that were submitted. However, I think Idaho Power should
3 have allowed build and transfer bids to be submitted.
4 Q.Do you recommend that the Commission issue to
5 Idaho Power a Certificate of Public Convenience and
6 Necessi ty to construct the Langley Gulch plant?
7 A.Yes, with reservations. I recommend that the
8 Commission approve a Commitment Estimate of $ 34 7.4
9 million plus actual AFUDC under Idaho Code § 61-541, and
10 that any costs incurred above this commitment estimate be
11 subject to review and approval by the Commission, with a
12 "Not to Exceed limit" of $376.6 million plus actual
13 AFUDC. If the Commission approves a Certificate of
14 Convenience and Necessity for the proj ect, I recommend
15 that Idaho Power be ordered to provide the Commission
16 with periodic progress reports during the construction
17 phase. The progress reports should cover proj ect costs,
18 construction progress, permitting milestones, legal
19 issues, problems encountered, or any other issues that
20 should be brought to the attention of the Commission.
21 Q.Do you have any additional comments?
22 A.Yes, I would like to comment on the timing in
23 this case. The need for a base load power plant has been
24 a primary element in the Company's IRPs for many years.
25 Even though the type of resource has changed since the
CASE NO. IPC-E-09-03
06/19/09
1105 STERLING, R (Di) 87
STAFF
.1 need for new base load resource was first identified and
2 it's exact timing has been a little uncertain, Idaho
3 Power has had ample time to prepare for the addition of a
4 new base load resource. Nevertheless, the Company in
5 this case has stated that it did not have time to prepare
6 detailed plans and specifications that would have been
7 needed in order to accept build and transfer proposals.
8 The Company has already signed agreements to purchase
9 maj or equipment and has signed an EPC contract for work
10 to commence in September, immediately following a
11 Commission order in this case. Work must begin in
12 September, according to the Company, in order to meet an.13
14
online date of December 2012.
By filing its application when it did and by
15 requiring such a tight schedule for initiation and
16 proj ect completion, Idaho Power has handcuffed the
17 Commission in its decision making. Idaho Power's urgency
18 has foreclosed the Commission from some decisions it
19 might otherwise wish to make. There are few or no
20 realistic al ternati ves that can be considered at this
.
21 point that will not lead to higher costs. Unless the
22 Commission approves the Company's requests in this case,
23 any other decisions would likely cause additional costly
24 delays. Staff does not believe that either ratepayers or
25 the Commission should be held hostage because of the
CASE NO. IPC-E-09-03
06/19/09
STERLING, R (Di) 88
STAFF
1106
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.
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12
20
21
1 Company's inability to plan and acquire resources in a
2 less time constrained manner.
3 Q.Does this conclude your direct testimony in
4 this proceeding?
5 A.Yes, it does.
6
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CASE NO. IPC-E-09-03
06/19/09
1107 STERLING, R (Di) 89
STAFF
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.
1 (The following proceedings were had in
2 open hearing.)
3 MR. WOODBURY: And I would present
4 Mr. Sterling for cross-examination.
5 COMMISSIONER KEMPTON: Mr. Kline.
6 MR. KLINE: Thank you, Mr. Chairman. I am
7 going to refer to his revised Exhibit 109, not right
8 away, but as soon as we get there, we'll probably have to
9 have folks leave.
10
11 CROSS-EXAMINATION
12
13 BY MR. KLINE:
14 Q On page 22 of your testimony,
15 Mr. Sterling, you discuss the Company's decision to delay
16 the on-line date of the Langley Gulch project to make
17 time for the Commission to determine if it was willing to
18 provide ratemaking assurances authorized by Idaho law.
19 Do you recall that testimony?
20 A Yes, I do.
21 Q And on line 21, you indicate -- starting
22 on Line 21 and down through line 24, you express the
23 opinion that the need to delay the on-line date was only
24 an issue with the Benchmark resource. Do you see that?
25 A Yes, I do.
CSB REPORTING
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1108 STERLING (X)Staff
.1 Q All right, but we really don't know if
2 that's true, do we, Mr. Sterling?
3 None of the information that I reviewedA
4 submitted by any other bidder indicated any difficulty in
5 being able to meet the originally proposed on-line
6 date.
7 But realistically, Mr. Sterling, a bidderQ
8 that's competing for a contract isn't going to tell you
9 before the bid award date that they may have trouble
10 financing the project, are they? They're not going to
11 tell you that?
.
.
12 A Not likely, no.
13 Q In fact, we have an actual example of
14 where that occurred and what I need to do is refer you to
15 page 11 of your testimony where you talk about the U. S.
16 Geothermal bid in the geothermal RFP. Do you recall
17 that?
18 A Yes, I do.
19 And isn't it true that in that instanceQ
20 the reason that we don't have -- well, let me back up.
21 Isn't it true that U.S. Geothermal won that bid and
22 offered to provide the Company 45 megawatts?
23 Yes, that's my understanding.A
24 And at this point we only have a contractQ
25 for the 13 megawatts that had originally been a PURPA
CSB REPORTING
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1109 STERLING (X)Staff
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1 proj ect; is that correct?
2 A That's true.
3 Q All right, and isn't it true that the
4 reason we don't have a contract for the resource above 13
5 is that u. S. Geothermal could not finance without price
6 increases and, therefore, couldn't honor the prices in
7 its bid?
8 A I couldn't really address that. I don't
9 know the reasons why U. S. Geothermal is not able to honor
10 it. I've not been involved in any conversations with
11 them or Idaho Power regarding that.
12 Q Well, certainly, before they made the bid
13 and the bid was accepted, to your knowledge, was there
14 any discussion about how they might not be able to
15 finance it or that they were having trouble?
16 A Not that I recall.
17 Q In your testimony you are critical of the
18 Company's decision not to allow bidders to propose build
19 and transfer arrangements in this RFP; correct?
20 A Yes, I am.
21 Q And were you here when Mr. Porter
22 testified today?
23 A Yes, I was.
24 Q And have you read Mr. Porter's rebuttal
25 testimony?
CSB REPORTING
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1110 STERLING (X)Staff
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10
1 A Yes.
2 Q Now, focusing on that portion of his
3 rebuttal testimony where he describes the problems the
4 Company had with its own build and transfer projects and
5 also the problems the Company has observed with other
6 companies' build and transfer proj ects, would you agree
7 he raised some legitimate concerns?
8 Yes, I think some of those are legitimateA
9 concerns.
Q Would it be your recommendation that the
11 Company -- that the Commission require the Company to
12 accept build and transfer proposals in future RFP' seven.
.
13 though the Company has expressed some real reservations
14 about those kinds of arrangements?
15 A You said require them?
16 Q Right, you think that would be a good
17 thing for the Commission to do?
18 Yes, I do, actually, require them alongA
19 wi th other types of bids that might be made because I
20 think by not allowing them, you eliminate a segment of
21 potential bidders that may possibly be able to make the
22 best bid.
23 But wouldn't that put the Commission in aQ
24 difficult position, Mr. Sterling? Say in the case of the
25 Bennett Mountain proj ect that Mr. Porter talked about
CSB REPORTING
[phone]
1111 STERLING (X)Staff
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.
.
1 today, the developer provided, I'll say, a less than an
2 optimum proj ect that cost an awful lot of money as a
3 resul t of that problem, wouldn't that put the Commission
4 in a difficult position if it had ordered Idaho Power to
5 take those kinds of bids even though it didn't want to?
6 A Well, first, I think you're presuming that
7 those sorts of problems occur as a result of the
8 contracting mechanism and I'm not convinced that you can
9 attribute those sorts of problems in all cases to the
10 type of contract that that project was built under. I
11 think that sort of problem could have occurred whether it
12 was a build and transfer, whether it was a self-build
13 proj ect, whether it was a tolling agreement. I think it
14 could have occurred under anyone of those circumstances
15 and I don't think it was necessarily caused by or
16 exacerbated by the fact that it was a build and transfer
17 type of an arrangement.
18 Q Well, Mr. Porter talked about -- his
19 concern was the disconnect between the developer in the
20 build and transfer situation whose incentive is to get
21 the thing built and get it to the utility and let them
22 start operating it and that disconnect was a problem for
23 him, don't you think that's a legitimate concern?
24 A I think it can be somewhat of a concern,
25 but I think there a lot of ways around those sorts of
CSB REPORTING
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1112 STERLING (X)Staff
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.
.
1 problems. I think that to characterize it as if the
2 Company has no control or no influence over the design or
3 construction or the final product, I think, is a
4 mischaracterization. I think the ultimate owner of the
5 proj ect, I think, can structure the construction of the
6 proj ect, the design of the proj ect and participate in
7 every stage of the process to a large degree. I don't
8 think they're completely disconnected from that proj ect
9 or from that involvement with a third-party developer.
10 Contracts can be structured in -- attorneys can structure
11 contracts in many, many different ways and so I think a
12 lot of those perceptions that you just don't have any
13 control over the final product, I just don't think that
14 is the case.
15 Q Have you ever seen a contract that would
16 carryall the attributes that you've just described?
17 A In my position here at the Commission I
18 only review contracts that utilities bring to us and
19 that's not a lot of contracts.
20 Q On page 37 of your testimony, on lines 24
21 and 25, you discuss the concerns that bidders expressed
22 to the Staff about the structure of the RFP process, that
23 it might be a sham process and in that portion of your
24 testimony, you go on to acknowledge that you have no idea
25 if this expressed concern actually prevented anyone from
CSB REPORTING
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1113 STERLING (X)Staff
.
.
.
1 bidding; is that correct?
2 A Yes, that is my testimony.I guess I
3 would simply add to that, though, that information that
4 was submitted by one of the other intervenors in the case
5 has supported my suspicion that there was a problem. It
6 was information that I didn't have access to when I filed
7 my testimony.
8 Q Well, I'm specifically referring to your
9 testimony on line 23 through 25 where you say, "I do
10 know, however, that not all of the potential bidders who
11 attended the pre-bid conference submitted bids," and you
12 present that as support for the proposition that maybe
13 somebody didn't bid because they thought it was a sham.
14 Is that a fair characterization?
15 A Yes.
16 All right, but there's lots of reasons whyQ
17 people who attended a pre-bid meeting wouldn't
18 subsequently submit a bid, aren't there?
19 A There are and I guess I would add that
20 part of the basis for the statement that you referred to
21 in my testimony were phone calls that we, the Staff, got
22 from potential bidders.
23 Q Right, I understand, but I mean, the
24 testimony that just because they didn't bid after they
25 went to the pre-bid meeting doesn't really indicate
CSB REPORTING
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1114 STERLING (X)Staff
.
.
.
1 anything, does it?
2 A No, not necessarily.
3 MR. KLINE: At this point I do want to
4 talk about the revised Exhibit No. 109 and in enough
5 detail that we have to have people leave.
6 COMMISSIONER KEMPTON: Okay, if you
7 haven 1 t signed the contract agreement with Idaho Power,
8 you'll have to clear the room until we can invite you
9 back in, and Mr. Kline, you'll need to survey the room
10 and make sure we've accomplished our task to the best of
11 your knowledge.
12 MR. KLINE: I'll do my best, thank you.
13 (Pause in proceedings.)
14 MR. KLINE: It looks like the suspects are
15 all here.
16 **********BEGINNING OF CONFIDENTIAL INFORMTION**********
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CSB REPORTING
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1115 STERLING (X)Staff
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1116 STERLING (X)Staff
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CSB REPORTING 1117 STERLING (X)
(208 )890-5198 Staff
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CSB REPORTING
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1118 STERLING (X)Staff
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CSB REPORTING 1119 STERLING (X)
(208 )890-5198 Staff
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CSB REPORTING
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1120 STERLING (X)Staff
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CSB REPORTING
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1121 STERLING (X)
Staff
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CSB REPORTING
[phone]
1122 STERLING (X)Staff
.1 COMMISSIONER KEMPTON: That was Marsha's
2 term, so I just coined it back.
3 (Pause in proceedings.)
4 COMMISSIONER KEMPTON: Mr. Richardson.
5 MR. RI CHARDSON : Than k you,
6 Mr. Chairman.
7
8 CROSS-EXAMINATION
9
10 BY MR. RI CHARD SON :
.
.
11 Q Good afternoon, Mr. Sterling.
12 A Good afternoon.
13 Q I want to start at the end of your
14 testimony on page 88 beginning on line 24. On that line
15 you state that Staff does not believe that either the
16 ratepayers or the Commission should be held hostage
17 because of the Company's inability to plan and acquire
18 resources in a less time constrained manner. Do you see
19 that?
20 A Yes, I do.
21 Q Focusing on your phrase "because of the
22 Company's inability to plan," is it your position that
23 Idaho Power's incapable of planning a responsible time
24 line for resource acquisitions?
25 A No.
CSB REPORTING
[phone]
1123 STERLING (X)Staff
.
.
.
1 Q So you believe that the Company's capable
2 of doing so, aren i t you?
3 A Yes.
4 Q So if the Company is capable of proper
5 planning and didn i t do so, then aren't your
6 recommendations actually rewarding the Company's poor
7 planning?
8 A No, I wouldn't necessarily conclude
9 that.
10 Q Nevertheless, you do think that by
11 approving do you think that by approving the Company's
12 application now that we are rewarding the Company's
13 inabili ty to plan and that we can therefore expect to see
14 this approach to planning repeated in the future?
15 A I wouldn't characterize it that way, no.
16 Q Well, are you aware of other instances
17 where the Company purchased or made substantial down
18 payments on new generating equipment before it had a
19 certificate of convenience and necessity to start
20 construction?
21
22
A No, I'm not aware of any.
Q Were you in the room today when
23 Commissioner Smith was inquiring about the Pioneer
24 proj ect?
25 A Yes, I was.
CSB REPORTING
[phone]
1124 STERLING (X)Staff
.
.
1 Q Then still on page 88, at line 8 you note
2 that the Company has already signed agreements to
3 purchase maj or equipment and has signed an EPC contract
4 for work to commence in September, immediately following
5 a Commission order in this case. Do you see that?
6 A Yes, I do.
7 Q And as a result, you conclude thô-t..-t-he---------
8 Company has handcuffed the Commission in its decision
9 making; correct? And that would be at line 16 on page
10 88.
11 A Well, I conclude that for a variety of
12 reasons besides just one sentence that you referred to.
13 Q But you have concluded that Idaho Power
14 has handcuffed the Commission in its decision making?
15 A Yes.
16 Q So isn't it true, then, that it is Idaho
17 Power and not this PUC that is deciding whether Langley
18 Gulch is going to be built?
19 A No, I think the Commission ultimately
20 still has that decision. I think part of the quote
21 handcuffing that I was referring to and furthermore, the
22 Commission can decide for themselves whether they feel
23 handcuffed, it's not for me to make that judgment, but
24 whatever the Commission decides in this case, whether to.25 delay the start of the proj ect, to not issue an CPCN, to
CSB REPORTING
[phone]
1125 STERLING (X)Staff
.
.
.
1 redo the RFP process, all of those things cost money.
2 There is no ideal alternate choice that you can make at
3 this point that doesn't have some consequences to it, and
4 that's part of what I was referring to by the
5 handcuffing. There's no zero cost way out of this now
6 that we've got this far.
7 Q I appreciate that. Have you given any
8 thought to the question of whether hiring an EPC
9 contractor and putting money down on new turbines and
10 steam generators rises to the level of commencement of
11 construction?
12 A No, I have not given thought to that.
13 Q Going back to page 19 of your testimony,
14 on line 9 you state that you still believe that the plant
15 will be needed in approximately the time frame planned.
16 Are you familiar with the concept of elasticity of
17 demand?
18 A Yes.
19 Q And would you accept that, subj ect to
20 check, the rates for the industrial class on Idaho
21 Power's system went up by 25 percent this year?
22 A Yes, subj ect to check.
23 Q Have you considered factoring elasticity
24 of demand into your analysis of whether this plant will
25 still be needed in 2012?
CSB REPORTING
[phone]
1126 STERLING (X)Staff
.
.
.
1 A No.
2 Q Do you know whether or not the J. R.
3 Simplot Company owns potato processing plants outside of
4 Idaho Power's service terri tory served by electric
5 utili ties with rates lower than Idaho Power's?
6 A I know that they have plants outside of
7 Idaho Power's service terri tory, but I don't know what
8 rates they payor whether they' rehigher or lower than
9 Idaho Power's rates.
10 Q And I'd ask you the same question relative
11 to the Hewlett-Packard Company, do you know if they have
12 facilities outside of Idaho Power's service territory
13 that are served by electric utili ties with rates that are
14 lower than Idaho Power's?
15 A And my answer would be the same for HP as
16 it would be for Simplot. I know they have plants outside
17 the service terri tory, but I don't know what their rates
18 are.
19 Q Fair enough. Would you agree that
20 elasticity of demand can take the form of a company's
21 decision to shift production from one facility to another
22 in addition to simply reducing load?
23
24
25
A Certainly a possibility.
Q And then I i II go to a spot where Mr. Kline
inquired. On page 22, you are asked the question whether
CSB REPORTING
[phone]
1127 STERLING (X)Staff
.
.
.
1 it was a wise decision on Idaho Power's part to delay the
2 on-line date of the project from the summer of 2012 to
3 December of 2012. Do you see that?
4 A What line was it on page 22?
5 Q That would be line 5, the question on line
6 5.
7 A Okay, would you repeat your question?
8 Q Certainly. You're asked the question of
9 whether it was a wise decision on Idaho Power's part to
10 delay the on-line date of the project from the summer of
11 2012 to December 2012. That's the delay you're referring
12 to there, is it not?
13 A Yes, it is.
14 Q And by your use of the word "wise," do you
15 mean prudent?
16 A No, I mean wise.
17 Q In the first two-thirds of your answer, it
18 appears that you agree that it was a wise decision
19 because" It makes sense that the Company would want to
20 wait" to see if the regulatory preapproval legislation
21 was passed by the legislature, but then in the last three
22 sentences in your answer it seems you reach the opposite
23 conclusion by noting that the delay was only an issue for
24 the Company's Benchmark resource -proposal, so if you had
25 to reach a single conclusion, would you say the delay was
CSB REPORTING
[phone]
1128 STERLING (X)Staff
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.
.
1 wise or unwise?
2 I don't necessarily agree that the lastA
3 part of that section that you referred to draws the
4 conclusion that you suggest that it does.
5 So you still believe that the decision toQ
6 delay was a wise decision?
7 Well, for that matter, I didn't actuallyA
8 say that I agree or disagree or that I thought it was
Q wise or not wise. Despite what.. the question- may say, T
10 said I understood why the Company did it and whether
11 that's wise or not is a bit difficult for me to answer
12 because I'm not a finance expert and that was one of the
13 reasons or the primary reason that Idaho Power chose to
14 delay the proj ect. That's not my area of expertise and
15 that's why I really stopped short of answering my own
16 question, quite frankly.
17 So it's more of a rhetorical question, IQ
18 guess.
19 You could call it that, yeah.A
20 And at least twice in your testimony youQ
21 state that potential bidders had a perception that the
22 bidding process was biased to favor Idaho Power's
23 self-build option; is that correct?
24 I know that I stated it in my testimony.A
25 And were you concerned that some of theQ
CSB REPORTING
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1129 STERLING (X)Staff
.
.
.
1 potential bidders may not have participated for that very
2 reason?
3 A Yes, that was a concern.
4 Q And in fact, we now know that to be true,
5 don't we, if you reference Dr. Reading's Exhibit 205?
6 A I would conclude that from that exhibit,
7 yes.
8 Q And on page 35 you observe that Idaho
9 Power only had a weak excuse for excluding the build and
10 transfer option; correct?
11 A Yes, I did use those terms.
12 Q And you state that by excluding the build
13 and transfer option that Idaho Power may have locked out
14 potential bidders; correct?
15 A Yes.
16 Q Then on page 37 you conclude that it is
17 difficul t to be reassured that the winning proposal is
18 the best proposal if some interested bidders chose not to
19 submi t bids because they were shut out of the process; is
20 that correct?
21 A Yes.
22 Q And then you add that you were personally
23 aware that potential bidders had concerns about the
24 self-build option that may have caused them not to
25 participate; correct?
CSB REPORTING
[phone]
1130 STERLING (X)Staff
.
.
.
1 A Yes.
2 Q And you also testified that you are
3 personally aware that potential bidders had concerns and
4 may have in fact refused to participate because of the
5 lack of a build and transfer option; correct?
6 A Yes.
7 Q In fact, you and other members of the
8 Commission Staff were contacted by potential bidders who
9 were frustrated that the RFP did not allow a build and
10 transfer option; correct?
11 A Yes.
12 Q Would you agree that Idaho Power had a
13 monetary motivation to select the self-build option?
14 A No, I don't necessarily believe that's
15 true.
16 Q You do know that they prepaid for -- they
17 put down a nonrefundable payment on the turbine and
18 generator equipment?
19 A Yes, I do know that.
20 Q That would have been forfeited potentially
21 if they had not selected the self-build option?
22 A Yes, they would have potentially forfeited
23 that, but there's also the potential that someone else
24 could have more than made up the difference with a lower
25 bid, so...
CSB REPORTING
[phone]
1131 STERLING (X)Staff
.
.
1 Q And given all of your concerns that I i ve
2 gone over in the last couple of minutes, would you agree
3 with me that there was a perception among the potential
4 bidders that the process was biased in favor of Idaho
5 Power?
6 A Well, some of the bidders felt that way.
7 I can't say that all of them did. I don't know how all
8 0 f them f e 1 t .
9 Q Yeah, and I didn't use the word "all."
10 A I would like to use the word "some."
11 Q Okay, fair. Given that conclusion, is it
12 possible, then, that the optimal proj ect was not selected
13 because it was not bid into the RFP?
14 A Yes.
15 Q On page 39, you state that R. W. Beck was
16 only asked to assist in evaluation criteria and to
17 provide guidance to the evaluation team because of cost
18 considerations. Would you agree with me that when one is
19 considering a $427 million plant with a present value of
20 $2.7 billion that having a consultant helping throughout
21 the process would be money well spent?
22 A I guess I need to back up and ask you
23 where in that paragraph I said anything about cost
24 considerations. Oh, I see it now. Cost considerations I.25 don't think was the only reason that I mention, but it
CSB REPORTING
[phone]
1132 STERLING (X)Staff
1 was one of them, but as far as your question goes, I.2 think it's really a question of what would you get for
3 the amount of money that you would spend. It would be
4 foolish to spend money on something that wouldn't add any
5 value to the process. On the other hand, if you did gain
6 some value through that sort of an evaluation, it
7 probably would be fairly minor compared to the total cost
8 of the proj ect.
9 Q And assuming the consultant would be able
10 to assist the Company in solving for some of those issues
11 we've been talking about relative to the bidding process,
12 then I would assume you would conclude that that would be
13 money well spent?.14 A Yeah, it certainly could be.
15 Q You discuss the soft cap in your testimony
16 and you relate it to the new Idaho Code section dealing
17 with regulatory preapproval. Does Staff have a position
18 on whether or not regulatory preapproval is good
19 ratemaking in a generic sense?
20 A I'm really not prepared to speak on policy
21 issues on behalf of the Staff. I don't know that we have
22 developed any policy position on that.
23 Q Well, given your personal background and
24 the many years in the regulatory arena, do you have an.25 opinion on whether or not regulatory preapproval is good
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1133 STERLING (X)Staff
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1 ratemaking?
2 A Personally under normal circumstances I 1m
3 not in favor of it. I think there may be some
4 circumstances, though, where it might be justifiable.
5 Q And is it your proposal that any
6 expendi tures below your recommended soft cap be
7 automatically recovered by the Company?
8 A If the Commission were to approve a CPCN
9 under that legislation, I think they would be -- the
10 Commission would have to accept the costs under that
11 cap.
12 Q But is it your understanding that the
13 Commission is required by the legislation to approve the
14 expenditures under that regulatory preapproval
15 mechanism?
16 A Well, I think the Commission has the
17 discretion to establish a cap at whatever point they want
18 and decide how much should be considered under that
19 legislation and how much should be considered outside of
20 it.
21 Q And assume with me a scenario under which
22 the plant is built, but turns out for whatever reason not
23 to be used and useful and it was approved with the
24 regulatory preapproval methodology, would the ratepayers
25 still be obligated to pay for the uneeded plant?
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1134 STERLING (X)Staff
.1 A It's my understanding that under this
2 legislation they would be.
5
7
8
9
10
11
12
13
14
15
16
17
18
19 BY MR. MILLER:
20 Q
3 MR. RICHARDSON: Thank you, Mr. Sterling.
4 Mr. Chairman, that's all I have.
COMMISSIONER KEMPTON: Thank you,
6 Mr. Richardson. Ms. Ackerman.
.
MS. ACKERMAN: No, Mr. Chairman.
COMMISSIONER KEMPTON: I'm sorry?
MS. ACKERMAN: No cross-exam.
COMMISSIONER KEMPTON: Okay, Mr. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KEMPTON: Mr. Purdy.
MR. PURDY: I have none. Thank you.
COMMISSIONER KEMPTON: Mr. Miller.
MR. MILLER: Just one, Mr. Chairman.
CROSS-EXAMINATION
Mr. Sterling, the cost of the delay, the
21 six-month cost of the delay, should it occur is on the
22 order of $ 6.8 million. Do you have an opinion as to
23 whether that cost should be borne by the shareholders or
24 by the ratepayers?.25 A You're referring to costs associated with
1135 STERLING (X)StaffCSB REPORTING
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1 delaying the on-line date from June to December?
2 Q Yes, sir.
3 A My position is, as I think I expressed in
4 my testimony, that any costs that are strictly a result
5 of that delay should not be recoverable from ratepayers
6 and part of the basis for that is I don't believe that
7 other short-listed bids would have been allowed to incur
8 addi tional costs and delay their proj ects, so I don't
9 think Idaho Power should be able to recover costs as a
10 result of delaying its proj ect.
11 MR. MILLER: Thank you very much and
12 that's the only question I have.
13 MS. BRIDGE: I have no questions, Mr.
14 Chairman.
15 COMMISSIONER KEMPTON: Commissioner
16 Redford.
17 COMMISSIONER REDFORD: Thank you,
18 Mr. Chairman.
19
20 EXAMINATION
21
22 BY COMMISSIONER REDFORD:
23 Q I believe you made the statement, I
24 believe, under Mr. Kline's cross-examination about
25 front-end loading a contract. Do you recall that?
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1136 STERLING (Com)Staff
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1 A Well, I think that conversation related to
2 the net present value analysis that was performed as part
3 of the evaluation of the bids.
4 Q So are you suggesting that Idaho Power
5 front-end loaded its bid?
6 A No, I think where the concept of front
7 loading comes in, and I don't want to get too technical
8 here, but under a tolling agreement, you only pay for the
9 energy and capacity that's delivered. You don't pay to
10 build the proj ect and so there is no front-end capital
11 cost like you would have with a self-build proj ect or a
12 build and transfer for that matter, but there are fuel
13 costs that will occur over the 20-year term of the
14 agreement.
15 Q Fuel costs did you say?
16 A Fuel costs, fixed and variable O&M, other
17 sorts of ongoing operational costs and it's when those
18 costs occur that influences your net present value
19 calculations, so if you only look at the first five years
20 of a 20-year period, you capture construction costs for a
21 build and transfer or a self-build that are presumably
22 spread out over a 20-year period for a tolling agreement
23 and so different types of bids will perform differently
24 depending upon the time period that you choose for the
25 analysis and so the more that those costs occur towards
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1137 STERLING (Com)Staff
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1 the front of the 20-year period the higher those net
2 present values will be in a shorter analysis.
3 Q The traditional front-end loading
4 definition is where a contractor in an effort to be paid
5 more front-end loads the costs that occur early on in the
6 proj ect, would you agree to that?
7 A Yes, and I don't think -- the front
8 loading term was Mr. Kline's term and not mine and I
9 don't think that's the type of front loading that he was
10 referring to, at least that is not what I understood his
11 question to be.
12 Q Okay. Were you aware that the RFP called
13 for 15-year PPA' sand TA' s with an option for five
14 addi tional years?
15 A Yes, it required a 15-year period, plus a
16 mandatory five-year option; in other words, they had to
17 present an option for an additional five years.
18 Q Well, on the option, would that be for
19 another negotiated power -- PPA?
20 A No, the option I think was strictly
21 intended to give Idaho Power the choice of signing a
22 15-year contract if it chose to or a 20-year contract if
2 3 it chose to if it chose a PPA or a tolling agreement.
24 Q Okay. Throughout your testimony you have
25 been critical of Idaho Power's method of procurement for
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STERLING (Com)Staff1138
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1 addi tional generation; right?
2 A Well, some aspects of the process I was
3 critical of.
4 Q Okay, and you stated notwithstanding all
5 the difficulties that the procurement process was fair?
6 A Well, I think I would characterize my
7 posi tion or summari ze it as for the bids that were
8 submi tted, I believe all the bids were treated fairly.
9 Where I have some problem, though, is the exclusion of
10 build and transfer bids and the bids that were not
11 submi tted, I think, caused a problem. That's where I
12 have some difficulties.
13 Q So what Idaho Power did was on the basis
14 of looking at one plant, they made the determination that
15 build and transfer was bad generally; is that what they
16 did?
17 A Well, I think it was my understanding that
18 Idaho Power looked at multiple plants.
19 Q Okay, but after their view of those
20 plants, they determined that build and transfer was
21 bad?
22 A I think it was a combination of looking at
23 other plants, plus the experience that they had on the
24 Bennett Mountain proj ect.
25 Q Okay, how could a PPA or a TA bidder
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1139 STERLING (Com)Staff
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1 expect to compete when the evaluation took into
2 consideration the net present value? I mean, how could
3 that be fair?
4 A Well, I think there's some
5 misunderstanding, I guess, about the net present value
6 and what that analysis really is and furthermore, about
7 what a self-build bid looks like versus a tolling
8 agreement. Under a self-build, you actually bid a price
9 to build the proj ect, the construction costs and all the
10 costs associated with it. Under a tolling agreement,
11 really all the bid consists of is here's our price per
12 kilowatt-hour to deliver energy and here's our price for
13
14
capacity. Those two things are the only price factors
that are submitted in those bids. They don't submit a
15 bid on here's how much it's going to cost us to build the
16 plant, here's how much all the parts and pieces are going
17 to cost, here's how much the turbines are going to cost.
18 None of that information is even submitted under a
19 tolling agreement, so you have to have a way of comparing
20 a cost of building a plant versus the cost of buying
21 capaci ty and energy from someone else, so the net present
22 value analysis is just simply a method that is commonly
23 used to compare two different cost streams on a
24 comparable basis.
25 Q You've been in the Hearing Room for most
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1140 STERLING (Com)Staff
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1 of the hearing, haven't you?
2 A Yes.
3 Q And you've heard testimony from the
4 Company witnesses that there was a $ 95 million spread
5 when you take into consideration net present value, so if
6 all you're doing is providing a tear-open bid to see what
7 the kilowatt-hours are going to be, I don't understand.
8 A Maybe I could explain it this way: Let's
9 say you are considering buying a new car and you have a
10 choice of this car that costs more but gets better gas
11 mileage or you can buy a cheaper car that doesn't get as
12 good of gas mileage. You really can't just compare the
13
14
purchase price of the car, you have to compare the cost
over the time period that you expect to own it and that's
15 the sort of analysis that a net present value analysis
16 enables you to do. I also would probably add that it's
17 been stated, I think, a number of times in this hearing
18 that bidders didn't know that a net present value
19 analysis was going to be used. I don't believe that
20 that's completely true.
21 In the RFP document, it does say that a
22 present worth analysis will be used and furthermore, it's
23 a very common method for comparing the costs of various
24 projects and so I would think any bidder would have an
25 expectation that that sort of an analysis would be
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1141 STERLING (Com)Staff
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10
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1 conducted, so the fact that if it wasn't even known, I
2 don't even view that as necessarily a problem if bidders
3 weren't aware that that was going to be used.
4 Other than the fact that they'd beQ
5 excluded based upon net present value.
6 I guess I would disagree that it excludesA
7 them from anything. It's simply an analysis method. It
8 doesn't exclude any bidder. It's just a mechanism that's
9 used to compare costs.
Q Well, you've heard, I believe, Ms. Smith
11 for the Company state that that if they wanted to compete
12 on the basis of a net present value all they had to do
13 was reduce their price.
14 A Well, if they wanted to compete no matter
15 what sort of analysis would be used they would have to
16 reduce their price. I think -- I don't think you need to
17 get hung up on the net present value sort of analysis.
18 All it means and the $ 95 million that has been referred
19 to in the hearing, it means that when you examine the
20 cash flows of this project compared to the next best
21 project, over the 20-year period in today's dollars this
22 proposal was $ 95 million less expensive than the other
23 proposal.
24 Well, I guess I would agree with you ifQ
25 you were bidding on apples and apples or oranges and
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1142 STERLING (Com)Staff
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1 oranges, because the bidders simply provided a
2 kilowatt-hour price for 20 years and then the testimony
3 of Idaho Power is replete with references that uh-oh, $ 95
4 million would be saved by the Company or earned by the
5 Company and therefore, we're not going to -- we're going
6 to exclude power purchase agreements and TA' s.
7 A No, that wasn't the reason that they
8 excluded power purchase agreements and tolling
9 agreements. There's no connection between the net
10 present value analysis and the fact that they excluded
11 those types of bids.
12 Q Is net present value a consideration in
13 other types of construction?
14 A I believe that it is and furthermore, all
15 of the other bidders even if they bid a tolling
16 agreement, they would have had to do that sort of
17 analysis themselves in order to come up with a price that
18 they were comfortable bidding. They would have to look
19 at how much is it going to cost us to build this plant,
20 how much is our labor cost going to be, how much is our
21 fixed O&M cost going to be, how much is the equipment
22 going to cost. They would have to do that sort of an
23 analysis even to prepare their bid and so everybody would
24 have to do that.
25 Q Well, I disagree with you, Mr. Sterling.
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1143 STERLING (Com)Staff
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1 The owners of construction proj ects or buildings, for
2 instance, generally have a target price in mind, an
3 engineer's estimate, and I've looked at a lot of bids and
4 I've never seen the issue of net present value included
5 in the bid evaluation.
6 A Well, I guess I would just offer this for
7 consideration, too.If we look at just the Langley Gulch
8 proj ect, the Benchmark proj ect, the estimated cost to
9 build the proj ect is $427 million, but there's going to
10 be a very substantial fuel cost every year that that
11 plant is going to operate and over the 20-year term that
12 this plant was considered for, the net present value is
13 something li ke 2.8 or $ 9 billion.
14 Q Billion?
15 A Billion, so the construction cost is
16 really only, it's actually a smaller piece than the fuel
17 cost, so you can't just consider the cost to build the
18 project and make a fair comparison amongst the bids.
19 Q So there wasn't a fair comparison?
20 A No, there was a fair comparison in my
21 opinion.It kind of goes back to the example I gave of
22 an automobile. You can't just consider the cost to
23 purchase the automobile. If you're concerned about gas
24 mileage, you want to consider the fuel costs, too.
25 Q Well, when the PPA bidders did their bid
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1144 STERLING (Com)Staff
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1 calculations, they took into account the construction
2 cost and all the other elements and then put on ita
3 profi t amount; is that correct?
4 I would assume that they did. The tollingA
5 agrèements would have added all those things in preparing
6 their bids, but all of those parts and pieces wouldn't
7 have been included as part of the bid.
8 One of the criteria in the legislation wasQ
9 that a company or the Commission had accepted the IRP, an
10 IRP; is that right?
11 A Yes.
12 When you discussed that, you used the wordQ
13 "acknowledged. " Was there some distinction about
14 acceptance or acknowledge?
15 Well, this Commission has been veryA
16 careful over the years in what terminology it uses in
17 consideration of IRPs and historically, this Commission
18 has tended to use the word "acknowledge" rather than the
19 word" accept," I believe, because the word "accept" kind
20 of has a connotation that you accept or approve all of
21 the things that are in it; whereas, if you just
22 acknowledge it, you're simply saying yes, the Commission
23 or the Company did plan, the Company did go through all
24 the necessary steps. We don't necessarily approve
25 everything that's in it. If there are new proj ects
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1145 STERLING (Com)Staff
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1 proposed, we'll consider those as they occur, but we
2 don't give blanket approval just because it's contained
3 in a plan.
4 Q Have you checked in Webster's Dictionary
5 by any chance about the word "accept"?
6 A Not any time recently, no.
7 Q Well, subject to check, I believe accept
8 means approval, can mean approval and my question --
9 A I'm just saying in the 16 years that I've
10 been here and I've been involved all that time in Idaho
11 Power and the other utili ties' IRPs, we've been very,
12 very careful not to use the word "accept" and so the fact
13 that it happens to appear in this legislation, I guess,
14 leaves its interpretation open to question how that
15 relates to the acknowledged term that we have
16 historically used.
17 Q Well, you --
18 A I would also say I think all of it -- none
19 of the IRPs that I've ever worked on have technically
20 been accepted by the Commission. That language has never
21 been used in all the years that I've been here.
22 Q But the legislature used it.
23 A Yes, the legislature did use it, so it's,
24 I guess, up to us to determine what they meant by that.
25 Q But the common usage of the term has a
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1146 STERLING (Com)Staff
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10
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12
1 different connotation.
2 A I'm not the one using those terms. That's
3 the term the legislature used and acknowledged is the
4 term that the Commission has used. I didn't invent or
5 propose either one. I'm just stating that's historically
6 what the Commission has used and the legislation uses a
7 different word.
8 COMMISSIONER REDFORD: Okay, thank you,
9 Mr. Sterling. I don't have any further questions.
COMMISSIONER KEMPTON: Commissioner Smith.
EXAMINATION
13
14 BY COMMISSIONER SMITH:
15 Q Thank you. Mr. Sterling, are you aware of
16 circumstances where the Commission accepts for filing
17 maybe tariffs, maybe contracts, maybe any number of
18 things, that does not mean we approve them or endorse
19 them?
20 A Yes,I am aware of those.
Q So accept doesn't necessarily mean approve
in these kinds of circumstances,does it?
A Again,I don't know what the legislature
intended using the word accept.
21
22
23
24
25 Q Well, and maybe I guess we'll have to
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1147 STERLING (Com)Staff
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1 address what maybe they intended and perhaps the drafters
2 of the legislation should have talked to the Staff and
3 used a different word, but I don't think we can make an
4 assumption that accept means approve. Based on our
5 current practice of accepting any number of things, that
6 doesn't mean we approve them and that's not a question.
7 COMMISSIONER REDFORD: I have one more
8 question, then.
9 COMMISSIONER KEMPTON: Commissioner
10 Redford.
11
12 EXAMINATION
13
14 BY COMMISSIONER REDFORD:
15 Q Does the legislation state accept for
16 filing?
17 A No, I believe it just says accepts.
18 COMMISSIONER REDFORD: Okay, thank you. I
19 have no further questions.
20
21
,
22
23
24
25
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1148 STERLING (Com)Staff
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1 EXAMINATION
2
3 BY COMMISSIONER KEMPTON:
4 Q Mr. Sterling, would you agree, subject to
5 check, that the 2006 IRP has been accepted for filing by
6 the Commission?
7 A I think if you went back and looked at the
8 Order, I think my guess, and this is just a guess, the
9 Order probably used the word "acknowledged," the
10 Commission acknowledges Idaho Power's 2006 IRP. It's one
11 of those words that has kind of taken on a specific
12 meaning over the years that maybe goes beyond the
13 definition that you might see in a dictionary. It has a
14 certain connotation. We've been very careful to use that
15 word and to not use the word accept because of the
16 possible things that it might imply.
17 Q The Chair would only note that the Chair
18 was giving the witness an option that was a pretty good
19 option. Page 13, if you would please, Mr. Sterling.
20 I'll give you a line here in just a minute. On line 15,
21 the question is asked, "Do you believe that a new
22 baseload plant is justified?" You give four reasons in
23 there which I won't go through because everybody has
24 access to that and you condition the statement which is
25 in favor of -- which is justified in your mind, first of
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1149 STERLING (Com)Staff
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1 all; is that correct?
2 A Yes, I think that's a reasonable
3 interpretation of that.
4 Q And you condition that on things that have
5 happened and most of those relate to the environment and
6 other issues that all of us have talked about here today,
7 so let's, if we could, go to page 87 and the question is,
8 "Do you recommend that the Commission issue to Idaho
9 Power a certificate of public convenience and necessity
10 to construct the Langley Gulch plant?" And you answer,
11 "Yes, with reservations." Is that your position today,
12 that with the discussions that we've had so far in
13 hearing that your position is yes, with reservations?
14 A Yes, it is and the reservations that I
15 refer to are what are explained in the following
16 sentences.
17 Q Yes. As a part of those conditions, you
18 stipulate that there be additional progress reports
19 during the construction phase covering such things as
20 construction progress, legal issues, problems encountered
21 and other issues that should be brought to the attention
22 of the Commission. You would stand by that as one of the
23 condi tions in your answer of yes that the CPCN should be
24 provided?
25 A Yes, I recommend that those things be a
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1150 STERLING (Com)Staff
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1 condi tion.
2 Q Page 81, on line 15 the question is, "Do
3 you believe preapproval of the Langley Gulch is warranted
4 in this case?" You stipulate that you believe that it's
5 likely that preapproval is necessary in order for Idaho
6 Power to obtain financing, I believe that those portions
7 of the estimated proj ect cost that are known with a high
8 degree of certainty be pre approved under Idaho Code
9 61-541. In connection with that condition, would the
10 break-out that you have constructed in terms of the soft
11 and hard cap satisfy that conditiön?
12 A Yes, I believe that it would.
13 Q The only other questions I have I think,
14 Mr. Sterling, that I would get you tangled up in issues
15 relating to -- well, let me ask you a question. In terms
16 of the condition that we just talked about here in terms
17 of the estimated proj ect cost known with a high degree of
18 certainty would be conditionally satisfactory for
19 preapproval, Mr. Richardson asked a question about the
20 extent to which the ratepayers are held at risk on
21 different conditions that could happen during the time
22 that a preapproval process was in place and they could
23 range all the way to abandonment and the cost to the
24 ratepayer. Is the ability of Idaho Power to achieve
25 financing a balancing consideration when you consider the
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1151 STERLING (Com)Staff
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21
1 risk due to ratepayers in cost overruns or other issues
2 that might develop in a preapproval process?
3 A Yes, I think it's something that deserves
4 consideration.
5 COMMISSIONER KEMPTON: I have no further
6 questions. Mr. Woodbury.
7 MR. WOODBURY: Just a couple of questions.
8 COMMISSIONER KEMPTON: Before you start
9 redirect, Mr. Woodbury, I'd like to ask where everybody
10 is on this. It's 10 minutes until 6: 00. Would you
11 prefer to go forward on this and finish this up or would
12 you like to -- I mean, this testimony, at least, or would
13 you like to begin this tomorrow mornîng?
14 COMMISSIONER SMITH: You mean the
15 redirect?
16 COMMISSIONER KEMPTON: Yeah, just stop
17 right here where we are before we go into redirect.
18 COMMISSIONER SMITH: How many questions do
19 you have?
MR. WOODBURY: Two.
COMMISSIONER KEMPTON: Let's go that far
22 and then we'll see.
23
24.25
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1152 STERLING (Com)Staff
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1 REDIRECT EXAMINATION
2
3 BY MR. WOODBURY:
4 Q Mr. Sterling, would it be fair to state
5 from your testimony that Staff believes a resource
6 similar to the Benchmark proposal is needed in June of
7 2012?
8 A Yes.
9 Q And would you agree that the -- would it
10 be your position, also, that the lead time required for
11 permitting and construction of such a resource requires
12 that the process commence in September or soon thereafter
13 and not be delayed?
14 A Yes, I believe that is the case.
15 Q And is it for this reason that Staff
16 believes the Commission is handcuffed?
A Yes, that is one of the reasons, also.
Q There was a discussion of the
19 out-of-warranty expense incurred by the Company in
20 Bennett Mountain. Just by way of clarification, detailed
21 design specs were not provided as part of the RFP in that
22 Bennett Mountain --
23
24
A No, they were not.
Q -- proposal? And if those design,
25 detailed design, specs were part of that, do you think
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1153 STERLING (Com)
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1 that some of the problems the Company experienced could
2 have been perhaps mitigated or alleviated?
3 A I don't think that particular problem that
4 was referred to could have been prevented.
5 Q I think it was your testimony you thought
6 that problem could have occurred no matter what the type
7 or who the owner was.
8 A Yes, that's true.
9 MR. WOODBURY: Okay, Mr. Chairman, Staff
10 has no further redirect. Thank you. I would ask that
11 Mr. Sterling be released.
12 COMMISSIONER KEMPTON: Okay, if there is
13 no objection,the witness may step down.
(The witness left the stand. )
COMMISSIONER KEMPTON:So what we have
left are two more witnesses;is that correct?
MR.WOODBURY:Staff has two witnesses,
15
16
17
18 Patricia Harms and Terri Carlock.
19 COMMISSIONER KEMPTON: And then we have
20 the possibility of some witnesses to be called back by
21 applicant.
22
23
MR. WOODBURY: Yes.
24 we'd like to do that if we could.
MR. KLINE: It's more than a possibility,
25.COMMISSIONER KEMPTON: Then I would
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1154 STERLING (Com)
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19
20
21
22
23
24
25
1 suggest that we go ahead and fold our tent for the day
2 and come back in tomorrow morning. Do we want to come
3 back earlier do you think? 9:00 o'clock is okay with me,
4 but on the other hand, we may want to push this. Is
5 there any obj ection to being here at 8: 00 0' clock
6 tomorrow morning?
7 COMMISSIONER REDFORD: Yes.
8 MR. KLINE: Yes.
9 COMMISSIONER KEMPTON: Did I hear
10 objection? All right, let's try 8:30.
11 COMMISSIONER REDFORD: How about 9: OO?
12 COMMISSIONER KEMPTON: Okay, 9:00 o'clock
13 tomorrow morning. The hearing is in recess.
14 (The Hearing recessed at 6: 00 p. m. )
15
16
17
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