20150715Hearing Transcript Volume IV.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
IN THE MATTER OF AVISTA
CORPORATION'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
IN THE MATTER OF ROCKY MOUNTAIN
POWER COMPANY'S PETITION TO
MODIFY TERMS AND CONDITIONS OF
PURPA PURCHASE AGREEMENTS
BEFORE
CASE NO. IPC-E-15-01
CASE NO. AVU-E-15-01
CASE NO. PAC-E-15-03
COMMISSIONER PAUL KJELLANDER (Presiding)
COMMISSIONER KRISTINE RAPER
PLACE:
DATE:
c r-a -l = Commission Hearing Room C-- CJ\
472 West Washington Street -lO <- c Boise, Idaho n r- 'n , .....
(') . � Ul j c > June 30, 2015 :it a
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VOLUME IV - Pages 762 - 1027
• ORIGINAL CSB REPORTING
Certified Shorthand Reporters
Post Office Box 9774
Boise, Idaho 83707
[e-mail]
Ph: 208-890-5198 Fax: [phone]
Reporter:
Constance Bucy,
CSR
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For the Staff:
A P P E A R A N C E S
Donald Howell, Esq.
and Daphne Huang, Esq.
Deputy Attorneys General
472 West Washington Street
Boise, Idaho 83720-0074
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For Idaho Power Company: Donovan E. Walker, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
For Rocky Mountain Power: Yvonne R. Hogle, Esq.
9 Rocky Mountain Power
201 S. Main Street, Ste. 2400
10 Salt Lake City, Utah 84111
11 For Avista Corporation: Michael Andrea, Esq.
Avista Corporation
12 Post Office Box 3727
Spokane Washington 99220
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For Clearwater Paper:
For Interrnountain Energy
Partners:
RICHARDSON ADAMS PLLC
by Peter J. Richardson, Esq.
515 North 27th Street
Boise, Idaho 83702
McDEVITT & MILLER
by Dean J. Miller, Esq.
420 West Bannock Street
Boise, Idaho 83702
For J.R. Simplot Company: RICHARDSON ADAMS PLLC
19 by Gregory M. Adams, Esq.
515 North 27th Street
20 Boise, Idaho 83702
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For Idaho Irrigation
Pumpers:
CSB REPORTING
[phone]
RACINE OLSON NYE BUDGE
& BAILEY
by Eric L. Olsen, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
APPEARANCES
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APPEARANCES (Continued)
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For Idaho Conservation
League & Sierra Club:
For Snake River
Alliance:
For Renewable Energy
Coalition:
(Of Record)
For Snake River
Alliance:
For Micron Corportion:
Northside and Twin Falls
Canal Companies:
For Ecoplexus:
CSB REPORTING
[phone]
Benjamin J. Otto, Esq.
Idaho Conservation League
710 North 6th Street
Boise, Idaho 83702
Kelsey Jae Nunez, Esq.
Snake River Alliance
Post Office Box 1731
Boise, Idaho 83701
Williams Bradbury PC
by Ronald L. Williams, Esq.
1015 West Hays Street
Boise, Idaho 83702
-and­
SANGER LAW PC
by Irion Sanger, Esq.
1117 SW 53rd Avenue
Portland, Oregon 97215
Kelsey Jae Nunez, Esq.
Snake River Alliance
Post Office Box 1731
Boise, Idaho 83701
HOLLAND & HART LLP
by Frederick J. Schmidt, Esq.
377 S. Nevada Street
Carson City, Nevada 89703
ARKOOSH LAW OFFICES
by C. Tom Arkoosh, Esq.
Post Office Box 2900
Boise, Idaho 83701
FISHER PUSCH LLP
by John R. Hammond, Jr., Esq.
Post Office Box 1308
Boise, Idaho 83701
APPEARANCES
1
2
3
4 WITNESS
5 Don Reading
(Clearwater/Simplot)
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8
Yao Yin
9 (Staff)
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11 Rick Sterling
(Staff)
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CSB REPORTING
[phone]
I N D E X
EXAMINATION BY PAGE
Mr. Richardson (Direct) 763
Prefiled Direct Testimony 765
Prefiled Rebuttal Testimony 840
Mr. Howell (Cross) 856
Mr. Walker (Cross) 8 61
Commissioner Kjrellander 868
Ms. Huang (Direct) 871
Prefiled Direct Testimony 874
Mr. Richardson (Cross) 884
Mr. Miller (Cross) 886
Mr. Howell (Direct) 890
Prefiled Direct Testimony 892
Prefiled Rebuttal Testimony 924
Mr. Richardson (Cross) 935
Mr. Olsen (Cross) 956
Mr. Adams (Cross) 957
Mr. Otto (Cross) 965
Mr. Hammond (Cross) 968
Mr. Nunez (Cross) 971
Mr. Walker (Cross) 974
Mr. Andrea (Cross) 976
Commissioner Raper 977
Mr. Howell (Redirect) 978
INDEX
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3 NUMBER
E X H I B I T S
DESCRIPTION PAGE
4 FOR IDAHO POWER COMPANY:
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6
1. - 11. Admitted 1026
7 FOR THE STAFF:
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101. Expiration of PURPA Contracts
Over Time
FOR J.R. SIMPLOT & CLEARWATER PAPER:
201. CV for Dr. Don Reading
202. 18 C.F.R. § 292.304
203. Federal Register pages 12214 &
12224-12227
204. Redacted Rebuttal Testimony of
Gregory N. Duvall, 8/2/13
205. Energy Sales Agreements
Terminations for Clark Solar 1-4,
with Attachment 1
Premarked
Admitted 1026
Premarked
Admitted 1026
Premarked
Admitted 1026
Premarked
Admitted 1026
Premarked
Admitted 1026
Premarked
Admitted 1026
20
21 FOR ICL/SIERRA CLUB:
22
23
301. - 305 Admitted 1026
24 FOR INTERMOUNTAIN ENERGY PARTNERS:
25 401. - 402. Admitted 1026
CSB REPORTING EXHIBITS
Wilder, Idaho 83676
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2
3 NUMBER
EXHIBITS (Continued)
DESCRIPTION PAGE
4 FOR SNAKE RIVER ALLIANCE:
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6
501. Admitted 1026
7 FOR ROCKY MOUNTAIN POWER:
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9
601. Admitted 1026
10 FOR AVISTA CORPORATION:
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1101. - 1103. Admitted 1026
CSB REPORTING EXHIBITS
Wilder, Idaho 83676
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BOISE, IDAHO, TUESDAY, JUNE 30, 2015, 9:00 A. M.
COMMISSIONER KJELLANDER: Well, good morning.
5 We'll reconvene and go back on the record as we continue
6 to proceed with the case. I won't go through the
7 laborious naming and numbering of it. We're all aware of
8 it by now. If you're in the wrong place, you can still
9 leave.
10 As we left things yesterday, we were going to
11 start with Don Reading and then move to Staff's final two
12 witnesses; is that still okay with everybody?
13 MR. RICHARDSON: It's fine with us,
14 Mr. Chairman.
15 COMMISSIONER KJELLANDER: Excellent; so with
16 that, then, Mr. Richardson, my assumption is that you are
17 going to get Don Reading ready for us, so why don't I
18 hand it off to you.
19 MR. RICHARDSON: Thank you, Mr. Chairman.
20 Clearwater Paper and J.R. Simplot jointly would call
21 Dr. Reading to the stand.
22 MR. SCHMIDT: Mr. Chairman? Sorry, I wasn't
23 here yesterday and so I just wanted to enter an
24 appearance. I'm Fred Schmidt. I'm counsel for Micron
25 and I'll be attending the remainder of the hearing on
CSB REPORTING
[phone]
762 COLLOQUY
1 behalf of Micron. My partner Pamela Howland substituted
2 for me yesterday. Unfortunately, I was in a hearing for
3 the Nevada PUC, but I'm glad to be here today.
4 COMMISSIONER KJELLANDER: She warned us you'd
5 be here, so thank you for bringing that up.
6
7 DON READING,
8 produced as a witness at the instance of the Clearwater
9 Paper Corporation and the J.R. Simplot Company, having
10 been first duly sworn to tell the truth, the whole truth,
11 and nothing but the truth, was examined and testified as
12 follows:
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16 BY MR. RICHARDSON:
DIRECT EXAMINATION
17 Q. Good morning, Dr. Reading. Would you please
18 state your name and spell your last name for the
19 record?
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21
A.
Q.
Don Reading, R-e-a-d-i-n-g.
And are you the same Dr. Reading who has
22 prefiled direct and rebuttal testimony in this
23 proceeding?
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A.
Q.
Yes.
And are you the same Dr. Reading who caused
CSB REPORTING
[phone]
763 READING (Di)
Simplot/Clearwater
1 replacement page No. 15 to be filed in this proceeding?
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A.
Q.
Yes.
And Dr. Reading, if I were to ask you the same
4 questions you were asked in your prefiled direct,
5 rebuttal, and replacement page testimony, would your
6 answers be the same today?
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8
A.
Q.
Yes, they would.
And do you have any corrections or additions to
9 make to your testimony?
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A. None I know of.
MR. RICHARDSON: Mr. Chairman, I would move
12 that Dr. Reading's testimony, prefiled testimony, and
13 exhibits -- what are the exhibit numbers -- 201 through
14 205 be marked for identification purposes and his
15 testimony be spread upon the record as if it were read in
16 full.
17 COMMISSIONER KJELLANDER: That's what I had as
18 well, so without objection, we will put the testimony
19 across the record as if read, both the direct and the
20 rebuttal, and mark and identify Exhibits 201 through 205.
21 Thank you, Mr. Richardson.
22 (The following prefiled direct and rebuttal
23 testimony of Dr. Don Reading is spread upon the record.)
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CSB REPORTING
[phone]
764 READING (Di)
Simplot/Clearwater
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Q.
A.
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Don Reading and my business address
3 is Ben Johnson Associates, 6070 Hill Road, Boise, Idaho.
4 I am Vice President and Consulting Economist for Ben
5 Johnson Associates.
6 Q. HAVE YOU PREPARED AN EXHIBIT OUTLINING YOUR
7 QUALIFICATIONS AND BACKGROUND?
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A.
Q.
Yes. Exhibit No. 201 serves that purpose.
ON WHOSE BEHALF ARE YOU TESTIFYING IN THIS
10 CONSOLIDATED DOCKET?
11 A. The J.R. Simplot Company (Simplot) and
12 Clearwater Paper Corporation (Clearwater).
13 Q. WHAT IS THE PURPOSE AND GENERAL CONCLUSION OF
14 YOUR TESTIMONY IN THIS CASE?
15 A. I have been retained by Simplot and Clearwater
16 to review the petitions filed by the Idaho Power Company
17 (Idaho Power), Avista Corporation (Avista), and Rocky
18 Mountain Power (RMP) asking the Idaho Public Utilities
19 Commission (Commission, IPUC) to modify the terms and
20 conditions of Public Utility Regulatory Policies Act of
21 1978 (PURPA) contracts. I will explain why the
22 recommendations of the three utilities is an unreasonably
23 overbroad approach. Both the Federal Energy Regulatory
24 Commission (FERC) and the Idaho Commission have correctly
25 stated that PURPA projects need contracts of duration
765 Reading, Di 1
Simplot/Clearwater
1 longer than five years to allow for financing of a PURPA
2 generation facility. I will explain why the examples
3 used by Idaho Power to criticize PURPA are misleading,
4 and will demonstrate that Idaho Power's claim of a
5 "flood" of incoming
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766 Reading, Di la
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1 PURPA contracts is misleading. It is far from certain
2 from the evidence provided that these projects will ever
3 be built. I recommend the Commission maintain the
4 current 20-year contract length for qualifying facilities
5 (QFs) eligible for the IRP methodology rates, or at a
6 minimum for non-intermittent QFs, and if adjustments need
7 to be made they should be through the calculation of
8 avoided cost rates and not limiting the term of the
9 contract.
10 Q. YOU INDICATED YOU ARE TESTIFYING ON BEHALF OF
11 SIMPLOT. DOES SIMPLOT OPERATE OR INTEND TO DEVELOP QF
12 PROJECTS IN IDAHO?
13 A. Yes. Simplot currently operates an existing QF
14 project at its fertilizer plant in Pocatello, Idaho,
15 which utilizes a renewable fuel in the form of waste heat
16 in an industrial cogeneration process and has a nameplate
17 capacity of 15.9 megawatts (MW). It has sold the output
18 from that plant under a series of PURPA contracts, and
19 recently entered into a one-year replacement contract for
20 that PURPA facility. Simplot will need another
21 replacement contract within the next year. Although
22 Simplot has recently obtained QF contracts with published
23 avoided cost rates, it has also requested indicative
24 pricing under the IRP methodology and considered
25 increasing its generation well above 10 average monthly
767 Reading, Di 2
Simplot/Clearwater
1 MW on a consistent basis, which would require a contract
2 containing the !RP methodology avoided cost rates. In
3 recent years, I understand that Simplot has considered
4 contract lengths of up to seven years for this project.
5 Additionally, Magic Reservoir Hydroelectric QF
6 (Magic) is a wholly owned subsidiary of Simplot. Magic
7 is a nine MW hydro facility in Southern Idaho, and
8 currently has a 35-year contract to sell the output to
9 Idaho Power, which expires in 2024.
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768 Reading, Di 2a
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1 Simplot also recently contacted Idaho Power to
2 request indicative pricing for a cogeneration QF sized up
3 to 25 MW, to be developed at the new Idaho Project potato
4 processing facility in Caldwell, Idaho. I understand
5 that Simplot faces difficulty even analyzing the
6 viability of this proposed facility without a fixed rate
7 schedule in excess of five years. It is likely the
8 project will not proceed if the Commission reduces the
9 maximum contract length to five years.
10 Q. YOU ALSO TESTIFIED THAT YOU ARE TESTIFYING ON
11 BEHALF OF CLEARWATER. DOES CLEARWATER OPERATE OR INTEND
12 TO DEVELOP QF PROJECTS IN IDAHO?
13 A. Clearwater owns four generators at its wood
14 pulp, paperboard, and tissue manufacturing facility near
15 Lewiston, Idaho, which primarily utilize as fuel the
16 black liquor byproduct of the paper production process
17 and wood waste. These four generators are cumulatively
18 capable of generating approximately 109 MW of electrical
19 output. Although they primarily use a renewable fuel in
20 the form of biomass, these facilities also use the steam
21 output as process steam in the production of pulp,
22 paperboard and tissue products, and are each certified as
23 cogeneration QFs. Clearwater has previously sold its
24 output from these generators to Avista under PURPA
25 contracts, and Clearwater has maintained its QF
769 Reading, Di 3
Simplot/Clearwater
1 certification to allow it to again make sales under PURPA
2 in the future. Currently, Clearwater operates under a
3 2013 agreement whereby Clearwater uses its generators to
4 serve Clearwater's own load, and Avista compensates
5 Clearwater for its excess generation at the retail
6 electricity rate. The 2013 agreement remains in effect
7 until June 30, 2018, but provides Clearwater with a
8 limited right to terminate its energy sales to Avista
9 with 90 days notice.
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770 Reading, Di 3a
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1 Additionally, I understand from communications with
2 Clearwater personnel that Clearwater and Avista have had
3 periodic conversations over the last five years about the
4 viability of siting a large cogeneration project at
5 Clearwater's Lewiston facility. Given the large and
6 nearly constant steam demand at the Lewiston site, this
7 facility could support a base-load plant of an
8 incremental 75 to 125 MW that would approach 70% thermal
9 efficiency depending on the sizes and types of prime
10 movers selected for the project. The net impact of this
11 project would be an incremental lowering of greenhouse
12 gas emissions for the western U.S. as it would displace
13 base-load coal plants and assist the State of Idaho to
14 comply with the E.P.A. 's recently proposed, and likely
15 promulgated, Section lll(d) carbon reduction rule. The
16 expected economics of such a project would likely require
17 non-recourse financing with terms of at least 15 years,
18 with 20 years being a more feasible term. A limitation
19 of a five-year power purchase agreement takes this type
20 of high efficiency, greenhouse-gas-reducing project off
21 the table as an option at Lewiston. Clearwater does not
22 think this artificial limitation is in the best interest
23 of the ratepayers of Idaho.
24 Q. ASIDE FROM PURPA OR SERVING THEIR OWN LOADS,
25 ARE THERE ANY OTHER VIABLE OPPORTUNITIES TO SELL THE
771 Reading, Di 4
Simplot/Clearwater
1 OUTPUT FROM PROJECTS LIKE SIMPLOT'S AND CLEARWATER'S IN
2 THIS REGION OF THE COUNTRY?
3 A. Unlike the three regulated utilities that
4 petitioned the Commission in this docket, state law bars
5 Simplot and Clearwater from selling electricity at retail
6 to any customer. This is also true of neighboring states
7 that largely bar the sale of electricity at retail.
8 Additionally, FERC has stated that Section 210(m) of
9 PURPA is intended to relieve
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772 Reading, Di 4a
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1 utilities of their PURPA obligation if there is a
2 sufficiently competitive wholesale market for QFs to sell
3 power. But there is no such economically viable
4 wholesale market for the sale of electricity that meets
5 PURPA's requirements in this region. Therefore, aside
6 from PURPA sales to utilities, neither Clearwater nor
7 Simplot have a legal or economically viable market,
8 retail or wholesale, to sell electricity.
11 AVOIDED COSTS TO ANY LENGTH IT CHOOSES. WHAT IS THE
10 HAS THE AUTHORITY TO REDUCE CONTRACT LENGTHS FOR FIXED
12 ORIGIN OF A LONG-TERM CONTRACT WITH FIXED AVOIDED COST
Reading, Di 5
Simplot/Clearwater
773
PURPA is a federal law that directs FERC to
IDAHO POWER SUGGESTS THAT THE IDAHO COMMISSION
A.
Q. 9
13 RATES?
16 small power production from renewable resources. I have
17 included as Exhibit No. 202 a copy of the FERC regulation
18 regarding a QF's right to a legally enforceable
15 implement regulations that encourage cogeneration and
14
19 obligation for a specified term, which is contained in 18
20 Code of Federal Regulations Part 292.304. The FERC
21 regulation provides that each QF shall have the option:
24 energy or capacity over a specified term, in which
25 case the rates for such purchases shall, at the
23 legally enforceable obligation for the delivery of
22 (2) To provide energy or capacity pursuant to a
1 option of the qualifying facility exercised prior to
2 the beginning of the specified term, be based on
3 either:
4 (i) The avoided costs calculated at the time of
5 delivery; or
6 (ii) The avoided costs calculated at the time the
7 obligation is incurred.l
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25 1 Exhibit No. 202 (containing 18 C.F.R. § 292.304 (d) (2).
774 Reading, Di Sa
Simplot/Clearwater
1 Q. COULD YOU PLEASE STATE FERC'S EXPLANATION AS TO
2 THE INTENT OF THIS RULE, AS PROVIDED IN THE FEDERAL
3 REGISTER AT THE TIME FERC PROMULGATED THE RULE?
4 A. Yes. I have provided as Exhibit No. 203 an
5 excerpt of FERC's Order No. 69, which was published in
6 the Federal Register on February 25, 1980, and explained
7 FERC's decision to adopt this regulation. FERC stated:
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Paragraphs (b) (5) and (d) are intended to
reconcile the requirement that the rates for
purchases equal the utilities' avoided cost with the
need for qualifying facilities to be able to enter
into contractual commitments based, by necessity, on
estimates of future avoided costs. Some of the
comments received regarding this section stated
that, if the avoided cost of energy at the time it
is supplied is less than the price provided in the
contract or obligation, the purchasing utility would
be required to pay a rate for purchases that would
subsidize the qualifying facility at the expense of
the utility's other ratepayers. The Commission
recognizes this possibility, but is cognizant that
in other cases, the required rate will turn out to
be lower than the avoided cost at the time of
purchase. The Commission does not believe that the
reference in the statute to the incremental cost of
775 Reading, Di 6
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alternative energy was intended to require a
minute-by-minute evaluation of costs which would be
checked against rates established in long term
contracts between qualifying facilities and electric
utilities.
Many commenters have stressed the need for
certainty with regard to return on investment in new
technologies. The Commission agrees with these
776 Reading, Di 6a
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latter arguments, and believes that, in the long
run, "overestimations" and "underestimations" of
avoided costs will balance out.
* * * *
Paragraph (d) (2) permits a qualifying facility
to enter into a contract or other legally
enforceable obligation to provide energy or capacity
over a specified term. Use of the term "legally
enforceable obligation" is intended to prevent a
utility from circumventing the requirement that
provides capacity credit for an eligible qualifying
facility merely by refusing to enter into a contract
with the qualifying facility.2
14 Q. I RECOGNIZE THAT YOU ARE NOT AN ATTORNEY AND
15 CANNOT PROVIDE A LEGAL OPINION ON FERC'S INTERPRETATION
16 OF ITS OWN REGULATION, BUT AS A MATTER OF ECONOMICS, IS
17 IT YOUR OPINION THAT A FIVE-YEAR CONTRACT TERM WILL, IN
18 FERC'S WORDS, "PREVENT A UTILITY FROM CIRCUMVENTING THE
19 REQUIREMENT THAT PROVIDES CAPACITY CREDIT FOR AN ELIGIBLE
20 QUALIFYING FACILITY"?
21 A. No. The QF will not be able to cause the
22 utility to avoid future capacity additions if the
23 contract term is shortened to five years. One of the
24 ways a utility can avoid, or "circumvent" in FERC's
25 terminology, entering into a QF contract is to limit the
777 Reading, Di 7
Simplot/Clearwater
1 contract term to such a short period that being able to
2 finance the project becomes impossible. The contract
3 terms recommended by the three utilities in this case of
4 two, three, and five years
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24 2 Exhibit No. 203 at 2 (containing FERC Order No. 69, 45 Fed. Reg.
12214, 12,224 (Feb. 25, 1980)).
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1 are all too short to allow a QF to be economically viable
2 or to provide, and be compensated for, the capacity
3 value.
4 Q. AS A MATTER OF ECONOMICS, IS IT YOUR OPINION
5 THAT A FIVE-YEAR CONTRACT TERM WOULD SATISFY "THE NEED
6 FOR CERTAINTY WITH REGARD TO RETURN ON INVESTMENT IN NEW
7 TECHNOLOGIES"?
8 A. No. The only "certainty" that comes to mind
9 with a QF contract term of five years or less is that it
10 is very unlikely the project would ever be built. This
11 conclusion is supported by the fact that utility
12 non-PURPA power purchase agreements are for terms much
13 longer than five years. For example, Idaho Power's Neal
14 Hot Springs power purchase agreement is for a 25-year
15 term, and Idaho Power retained the right to extend the
16 term of that agreement. In his comments on the Neal Hot
17 Springs contract, IPUC Technical Staff, Rick Sterling,
18 identified the right to extend the term as one of the
19 "benefits" of that agreement in recommending its
20 approval.3
21 Q. ALL THREE OF THE UTILITIES ASK FOR A PURPA
22 CONTRACT TERM OF FIVE YEARS OR LESS. IF CONTRACT LENGTH
23 WERE ONLY FIVE YEARS OR SHORTER, IS IT YOUR OPINION THAT
24 A QF PROJECT COULD RELY ON THE CONTRACT TO FINANCE THE
25 DEVELOPMENT?
779 Reading, Di 8
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1 A. No. The "Enron meltdown" provided an Idaho
2 example of the impact of shortening the term of QF
3 contracts to five years. As the Commission noted when
4 increasing the term limit from five years to 20 years
5 (after reducing them earlier), only one PURPA contract
6 was signed in Idaho with the shortened contract length.
7 At that time, the Commission explained,
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24 3 IPUC Staff Comments, !PUC Docket No. IPC-E-09-34, pp. 13-14 (filed
May 3, 2010).
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This Commission also cannot ignore the fact that
since reducing the eligibility threshold to 1 MW and
contract term to 5 years, there has been only one
PURPA contract signed in Idaho. A longer contract,
we find, better coincides with the amortization
period or planned resource life of the renewable or
cogeneration resources being offered, better
reflects the amortization period of generation
projects constructed by the utilities themselves and
will coincidently provide a revenue stream that will
facilitate the financing of QF projects.4
12 Q. DOES THE IDAHO COMMISSION LIMIT UTILITY-OWNED
13 GENERATION RESOURCES TO A FIVE-YEAR TERM FOR COST
14 RECOVERY OF THE INVESTMENT?
15 A. No. Any utility-owned resources of any
16 significance that I am familiar with are approved by the
17 Commission with terms in some cases up to 50 years, and
18 are seldom shorter than 20. Of course, for a
19 utility-owned resource the ratepayer is on the hook for
20 providing the utility with a return both of and on the
21 investment for the facility once it is put into rate
22 base. Treating PURPA resources on an equal footing with
23 utility-owned resources would mandate they also should
24 receive longer-term contracts.
25 Q. FERC ALSO REFERENCED "LONG TERM CONTRACTS." IF
781 Reading, Di 9
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1 YOU WERE TO ASSUME THAT PURPA REQUIRES A LONG-TERM
2 CONTRACT, IN YOUR OPINION, IS FIVE YEARS A LONG TERM IN
3 THE CONTEXT OF A UTILITY-SCALE CAPITAL INVESTMENT?
4 A. No. When considering financing significant
5 capital investments, such as utility generation plants,
6 "long-term contracts" would certainly mean more than five
7 years.
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782 Reading, Di 9a
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1 Q. IF I WERE TO TELL YOU THAT FERC'S RULES REQUIRE
2 THE COMMISSION TO IMPLEMENT LONG-TERM, FIXED AVOIDED COST
3 RATES THAT PREVENT THE UTILITY FROM CIRCUMVENTING THE
4 NEED TO PAY FOR THE QF'S CAPACITY OR THAT ARE OF
5 SUFFICIENT LENGTH TO SUPPORT INVESTMENT IN A UTILITY
6 GENERATION FACILITY, IS IT YOUR OPINION THAT A FIVE-YEAR
7 CONTRACT TERM MEETS THAT TEST?
8 A. No. Using such an unreasonably overbroad
9 approach of shorting the contract length so that QFs
10 cannot obtain financing is a way around FERC's rules.
11 Developing accurate avoided cost pricing is a more
12 rational approach that meets FERC's regulations.
13 Q. HAS THE IDAHO COMMISSION ITSELF MADE FINDINGS
14 REGARDING THE LENGTH OF CONTRACTS WITH A FIXED RATE THAT
15 IS NECESSARY TO ENCOURAGE QF DEVELOPMENT AND SUPPORT
16 FINANCING FOR A QF PROJECT?
17 A. Yes. Just a few years ago, the Idaho Commission
18 found:
19 We find that a 20-year contract length, along with
20 other factors, has been beneficial in encouraging
21 PURPA development in Idaho. We continue to believe
22 that 20-year contracts better coincide with the
23 useful life of the renewable/cogeneration resources.
24 While it is not this Commission's responsibility to
25 ensure a contract length that allows a QF to obtain
783 Reading, Di 10
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financing, we find that reducing maximum contract
length to five years would unduly hinder PURPA
development. That is not the Commission's
objective. We believe that, by utilizing other
5 tools to ensure an accurate and up-to-date avoided
6 cost valuation,
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784 Reading, Di lOa
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we can continue to encourage the types of projects
that were envisioned by PURPA while maintaining the
transparency for ratepayers as PURPA requires.
Therefore, we find that a maximum contract length of
20 years is appropriate. The parties to a power
purchase agreement are free to negotiate a shorter
contract if that would be most suitable for the
project. As in the past, this Commission will
consider contracts of more than 20 years on a
case-by-case basis.5
11 Q. THE COMMISSION STATED, "WE FIND THAT REDUCING
12 MAXIMUM CONTRACT LENGTH TO FIVE YEARS WOULD UNDULY HINDER
13 PURPA DEVELOPMENT." DO YOU AGREE?
14 A. Yes, I believe Commission is correct. Real
15 world economics dictate that a project will not get
16 financing with a contract length of five years unless the
17 investment has a five-year pay-back period. A five-year
18 pay-back is far shorter than generally understood to be
19 necessary for long-term utility-scale investments.
20 Q. HAVE CONDITIONS CHANGED SINCE 2012 WHEN THE
21 COMMISSION STATED THAT REDUCING THE CONTRACT LENGTH WOULD
22 UNDULY HINDER PURPA DEVELOPMENT?
23 A. No. The length of the QF contract has to do
24 with the ability to obtain funds in order to build the
25 project. Those conditions have not changed. The
785 Reading, Di 11
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1 utilities' avoided costs may have changed and that should
2 be the determining factor in whether projects are
3 developed, rather than an arbitrarily short contract term
4 that is designed to deprive financing and capacity
5 payments to the QF.
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25 5 IPUC Order No. 32697, at p. 24.
786 Reading, Di lla
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1 Q. ARE 20-YEAR CONTRACT TERMS OUT OF THE ORDINARY
2 FOR ELECTRIC UTILITIES?
3 A. Not at all. For example, according to Idaho
4 Power's most recent 10-K filing, in April of 2012 Idaho
5 Power issued $75 million in first mortgage bonds that
6 mature after 30 years. Long-term financial corrunitments
7 are routine in all utilities' financing and planning.
8 Q. DR. READING, WHAT PRECIPITATED THE
9 CONSOLIDATION OF PETITIONS FILED BY THE THREE UTILITIES
10 IN THIS DOCKET?
11 A. Idaho Power filed a petition on January 30,
12 2015, to reduce the length of PURPA contracts to two
13 years. The Corrunission granted the Company interim relief
14 temporarily reducing QF contracts from 20 years to five
15 years. On February 27, 2015, Avista petitioned the
16 Corrunission for the same temporary and permanent relief
17 that would be granted to Idaho Power and a five-year
18 contract length for wind and solar QFs. Four days later
19 on March 2, 2015, Rocky Mountain Power filed its petition
20 seeking the same interim relief and a permanent reduction
21 in the length of QF contracts to three years, along with
22 an adjustment in the method of calculating avoided costs.
23 The Corrunission consolidated the three cases into a single
24 docket. I will discuss each of the utilities' petitions.
25 Q. COULD YOU PLEASE TELL US IDAHO POWER'S REASON
787 Reading, Di 12
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1 FOR FILING THE ORGINAL PETITION FOR THIS CASE?
3 what some have called a "tsunami" of wind and solar PURPA
24 6 Idaho Power's Petition, IPUC Case No. IPC-E-15-01, p. 21.
Reading, Di 12a
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788
According to the Company's petition, it faces A. 2
4 projects washing over Idaho Power's system.6 Idaho Power
5 proposes to limit contract terms for all QFs eligible for
6 IRP methodology rates to two years.
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2 PURPA PROJECTS TO ONLY TWO YEARS IN DURATION?
4 "risk" and "harm" to ratepayers. Idaho Power's petition
5 largely discusses a problem with intermittent wind and
WHAT IS IDAHO POWER'S RATIONALE FOR LIMITING
Idaho Power's claim is that PURPA is imposing A.
Q.
3
1
6 solar QFs that have the capability of creating an
7 oversupply problem on Idaho Power's system during certain
8 periods of the year. According to Idaho Power's
9 subsequent pleadings, the problem is not just
10 intermittent wind and solar projects but PURPA itself in
11 obligating ratepayers to the Commission-approved rates
12 for a 20-year period.7 In an attempt to prove its case,
13 Idaho Power provides "examples" of the price paid for
14 PURPA generation. Idaho Power claims customers must
15 purchase power at these higher PURPA prices when the
16 power is not needed to serve load or can be obtained in
17 the market at a cheaper price.
18 Q. DO YOU BELIEVE IDAHO POWER MAKES A COMPELLING
19 ARGUMENT WHEN PRESENTING ITS EVIDENCE?
20 A. No. Idaho Power arrives at its conclusions by
21 only telling half of the story. When valid comparable
22 evidence is presented, it shows the Company's own
23 generating resources commit the same "sins" as the PURPA
24 resources that they are asking the Commission to
25 discourage.
789 Reading, Di 13
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1 Q. COULD YOU PLEASE EXPLAIN WHAT YOU MEAN BY ONLY
2 PRESENTING HALF THE STORY?
3 A. The first half of the story is told when
4 comparing the cost of PURPA resources to Mid-Columbia
5 (Mid-C) prices. As shown in Exhibit No. 10 of Company
6 witness Allphin's
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24 7 Idaho Power's Answer to Simplot/Clearwater Joint/Cross Petition,
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25
790 Reading, Di 13a
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1 direct testimony, historical Mid-C prices have been lower
2 than PURPA prices since 2002 to the present and are
3 projected by Idaho Power to be lower over the next 20
4 years. What this comparison fails to recognize is
5 capital costs are included in the PURPA per MWh price.
6 Mid-C prices are market prices and are more reasonably
7 related to the variable running costs of existing
8 generating resources that do not contain capital costs.
9 Both variable and capital costs are rolled together in
10 the rates customers pay. When a utility's generating
11 resource is approved in rate base, the ratepayers are
12 "forced" to pay the capital costs of the resource over
13 the approved life, even when the Company's own generating
14 resources are not needed to serve load.
15 Q. WHAT DO YOU CONSIDER A MORE APPROPRIATE
16 CAMPARISON?
17 A. The cost of PURPA resources paid by Idaho Power
18 are passed through to customers in the retail rates
19 customers pay. PURPA rates should be compared to what
20 Idaho Power's customers pay for power from the Company's
21 own generation facilities, which would include the rate
22 based capital costs along with the fixed and variable
23 running costs.
24 Q. HAVE YOU MADE THAT COMPARISON WHERE BOTH PURPA
25 PROJECTS AND IDAHO POWER'S GENERATING RESOURCES ARE
791 Reading, Di 14
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1 MEASURED ON AN EQUIVALENT BASIS?
2 A. Yes, a reasonable comparison can be made by
3 using Idaho Power's FERC Form 1 data for production costs
4 and Idaho Power's Responses to Simplot's discovery
5 request for the capital portion of the costs. Chart 1
6 below displays the results of including the estimated
7 capital costs along with the variable running costs of
8 Idaho Power's generating facilities on a per MWh basis
9 for 2013, therefore comparing them on an equivalent basis
10 to the PURPA costs in retail rates. For 2013, as
11 expected, the market Mid-C prices are the
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792 Reading, Di 14a
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1 lowest cost non-hydro resource on Idaho Power's system.
2 Two of the Company's coal resources have a lower cost
3 than PURPA resources with the other four thermal units at
4 a higher cost. This does not take into account the
5 additional costs that might be necessary for coal plant
6 upgrades for environmental compliance for the Company's
7 non-PURPA resources that may be necessary in the near
8 future.
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Chart 1 (Corrected)
Idaho Power Ratepayer Power Costs 2013 & Mid-C $/MWh
Bennett Mt•• j Danskin••
c LangleyGulch .. A. II: i Valmy••
PURPA•
Boardman••
Jim Bridger ..
Mid-C•
18
$0 $50 $100
$/MWh
$150 $200
19 Source:
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22
• R. Allphin Exhibit 10
•• Attachment 2 - Response to Siff1)1ot's Request No. 13, 2013; 'Net Plant'• .18 for Capacity;
Response to Simplot's Request No. S(d), annual re11eUne requirement is 18" of capital Cost;
Production Expense' and 'Net Generation', 2013 FERC Form 1
23 Q. DR. READING, I DO NOT SEE IDAHO POWER'S HYDRO
24 RESOURCES IN YOUR CHART 1. SINCE, DEPENDING ON STREAM
25 FLOWS, IDAHO POWER'S HYDRO RESOURCES MAKE UP HALF OF THE
793 Reading, Di 15
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1 the Company's lowest cost resource with a depreciated
2 rate base and very low variable running cost. Also,
3 depending on stream flow
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794 Reading, Di 15a
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1 conditions the capacity factors will vary significantly
2 from year to year, and that would in turn cause the cost
3 on a per MWh basis to also vary significantly. So the
4 year picked for the analysis could be misleading. Due
5 the above factors I felt looking at thermal resources
6 along with the market price would be a more reasonable
7 comparison.
8 Q. ARE THERE ANY OTHER REASONS TO EXCLUDE HYDRO
9 RESOURCES FROM YOUR ANALYSIS?
10 A. Yes. Idaho Power has been in the process of
11 relicensing its Hells Canyon Complex ("HCC") for well
12 over a decade. It appears that the capital and variable
13 costs associated with the massive environmental
14 remediation associated with that relicensing will
15 dramatically change the economics of the Company's hydro
16 resources as a whole - and not just the costs associated
17 with the HCC. The final cost of relicensing HCC won't be
18 known for years; therefore it would be speculative for me
19 to include the unknowable increased costs of the
20 Company's hydro resources in my analysis.
21 Q. DO THE OTHER TWO UTILITIES IN THIS CASE SUPPORT
22 COMPARING THE PRICE OF PURPA RESOURCES TO THE MID-C
23 PRICES THAT DO NOT INCLUDE THE CONSIDERATION OF CAPACITY
24 COSTS?
25 A. I don't know about Avista, but PacifiCorp has
795 Reading, Di 16
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1 stated in Washington Utilities and Transportation
2 Commission (WUTC) cases that it is inappropriate to make
3 the comparison of PURPA resources with the Mid-C market
4 prices. I have provided as Exhibit No. 204 excerpts of
5 the testimony of Gregory Duvall before the WUTC in recent
6 general rate cases. PacifiCorp witness Gregory Duvall
7 states,
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796 Reading, Di 16a
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1 The inclusion of capacity payments in avoided costs
2 indicates that market prices alone are not
3 equivalent to avoided cost prices.a
4 And the same PacifiCorp witness in a later WUTC docket
5 stated,
6 If avoided cost prices are greater than market
7 prices years after the PPA was signed, it does not
8 mean that the avoided cost prices in the QF PPA are
9 excessive or otherwise violate PURPA's strict
10 requirements.
11 PURPA requires that the prices paid to QFs be
12 equal to a utility's avoided cost of energy and
13 capacity. Each state has an approved method for
14 calculating these avoided costs, and the resulting
15 prices are heavily scrutinized and ultimately
16 approved by the respective regulatory commissions.
17 The avoided cost calculation is intended to ensure
18 that customers are indifferent to QF generation,
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25
i.e., that the price paid to the QF is the same as
the price the utility would otherwise incur if it
was generating the electricity itself. Comparing QF
PPA prices for a single test year to the variable
cost of market purchases or the Company's existing
resources is insufficient to determine whether QF
prices are reasonable and prudent from a ratemaking
797 Reading, Di 17
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1 standpoint.9
2 Subsequently, Mr. Duvall further testified:
3 First, simply relying on market prices does not
4 reflect Pacific Power's actual avoided costs as
5 determined by the Commission because it fails to
6 account for the impact of a QF on the Company's
7 existing resources or the QF's ability to defer
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23 8 Exhibit No. 204 at 11 (containing the Rebuttal Testimony of Gregory
Duvall, WUTC Docket UE-130043, August 2, 2013, p. 22).
24 9 Exhibit No. 204 at 17 (containing Direct Testimony of Gregory
Duvall, WUTC Dockets UE-140762, -140617, -131384, -140094, May, 2014,
25 p. 11).
798 Reading, Di 17a
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1 future capacity additions. PURPA requires the
2 Company to purchase energy and capacity made
3 available by QFs. 10
4 As PacifiCorp's witness, Mr. Duvall testifies in its
5 Washington jurisdiction that comparing market prices to
6 PURPA resource prices is inappropriate and misleading.
7 Q. IDAHO POWER CLAIMS THAT RATEPAYERS ARE HARMED
8 WHEN THE COMPANY IS FORCED TO PURCHASE PURPA POWER WHEN
9 IT IS NOT NEEDED. DO YOU AGREE?
10 A. No more or less than when ratepayers are
11 "forced" to pay for the utilities' own generating
12 resources when they are not needed. Company witness
13 Allphin presents a series of 24 separate graphs in his
14 Exhibit No. 6 for the first week of each month for the
15 years 2016 and 2017. Each graph displays, on an hourly
16 basis, total system load along with the Company's
17 "must-run" resources, "must-take" non-PURPA PPA' s, along
18 with "must-take" PURPA resources. The "must-run"
19 Company-owned facilities are their hydro and coal
20 generation units at their minimum operational levels that
21 cannot be backed down further for environmental reasons
22 for hydro resources, or shut down for coal generation
23 units. Market purchases and sales are excluded from the
24 Exhibit's graphs.
25 Q. WHAT IS THE IDAHO POWER WITNESS ATTEMPTING TO
799 Reading, Di 18
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1 DEMONSTRATE WITH THE SERIES OF 24 GRAPHS?
2 A. Again, Idaho Power is telling only half of the
3 story. According to Mr. Allphin's testimony,
4 This analysis shows the frequency with which Idaho
5 Power's system, when in a state where it cannot be
6 backed down any further, will have generation
7 resources
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24 10 Exhibit No. 204 at 25-26 (containing Rebuttal Testimony of Gregory
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25 14-15).
800 Reading, Di 18a
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1
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in excess of its system load. This will put the
system into an imbalanced, over-generation state
unless some remedial actions are taken to balance
the system. If remedial actions are not available,
6 or not employed in a timely manner, then the Company
7 can have system reliability violations, events,
8 and/or outages and damage.ll
9 An examination of the monthly graphs over the two-year
10 period indicates, as one would expect, a mix of
11 relationships among the Company's load patterns over the
12 24 months considered, and the output of the power supply
13 depicted, indicating both an over and under supply of
14 power in various months.
15 Q. COULD YOU BE MORE SPECIFIC AND PROVIDE EXAMPLES
16 FOR THE 24 GRAPHS THAT INDICATE THE OVER AND UNDER SUPPLY
17 OF POWER ON IDAHO POWER'S SYSTEM RELATIVE TO THE SYSTEMS
18 LOADS?
19 A. I have selected two months as examples that are
20 at the ends of the spectrum of when the graphs indicate
21 first an oversupply relative to loads and second when the
22 situation is reversed and there is an undersupply. The
23 two example months are April and August of 2016 and
24 indicate there are times when both the Company-owned
25 resources and PURPA power contribute to filling part of
801 Reading, Di 19
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1 the gap when output is less than load and other times
2 when the Company's own "must-run" resources alone are
3 producing power greater than system load needs.
4 Q. COULD YOU PLEASE EXPLAIN WHAT YOU MEAN USING
5 THE APRIL 2016 GRAPH FOUND ON PAGE 5 OF 12 OF MR.
6 ALLPHIN'S EXHIBIT NO. 6?
7 A. Below is copy of the April 2016 Graph included
8 in Mr. Allphin's testimony.
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24 11 Direct Testimony of Randy Allphin, Idaho Power, IPUC Case No.
IPC-E-15-01, pp. 9-10.
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802 Reading, Di 19a
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_......,AW'lflo
Idaho Power Forecasted load vs. Forecasted Must Run or Take Generation(MW) ).000 -·
9
6
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2
1
10 t'Co Mll•-Auft GMtrtoOl'I
(tfydtoltl'ld1HtNlofCo�
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........ AlttJ.101' .... l& ·�1016
Arst Week of the Month
,.,,,20u
14
15 As can be seen in the above graph for April, when loads
16 are relatively low, system loads are less than both the
17 "must run" Idaho Power generation units as well as PURPA
18 resources. This would mean that Idaho Power's "must run"
19 units are contributing alone to the "system reliability
20 violations, events, and/or outages and damage'' unless
21 remedial action is taken in a timely manner, even if
22 there is no PURPA power being produced.
23 Q. COULD YOU PLEASE EXPLAIN THE OTHER END OF THE
24 SPECTURM, AUGUST 2016 WHEN BOTH IDAHO POWER'S RESOURCES
25 AT "MUST-RUN" AND PURPA RESOUSES ARE NOT SUFFICIENT TO
803 Reading, Di 20
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1 MEET THE SYSTEMS LOADS?
2 A. As can be seen below in a copy of Mr. Allphin's
3 graph for August 2016, that is predicted to be a
4 relativity high load month. In this graph, Idaho Power's
5 "must run" resources and PURPA are significantly below
6 system loads.
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......... ...... - ......... .... .....
RntWteloltheMmlh
.........
--- -. ...... - .. '"°
15 This means PURPA generation is contributing to the
16 Company's system load demands just as Idaho Power's
17 Company-owned resources are. The other monthly first week
18 graphs display a mix of over and under generation during
19 certain hours over the first week of each month.
20 Q. DO YOU HAVE ANY ADDITIONAL OBSERVATIONS ABOUT
21 IDAHO POWER'S EXHIBIT NO. 6?
22 Yes, for the casual observer, since PURPA, other
23 PPAs and Company-owned resources are all defined as "must
24 run" in the Exhibit No. 6, PURPA could just as easily be
25 displayed along the horizontal axis first with the
805 Reading, Di 21
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1 utility-owned resources on top. This could lead one to
2 assume the Company-owned resources are the problem of
3 Idaho Power being "forced" to receive power when it is
4 not needed, not PURPA resources. The graph below uses
5 the same data for April 2016 as used by in Exhibit No. 6
6 and only reorders how the resources are displayed in the
7 graph.
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1
2
3 r-· Idaho Powerforecastedloadvs. Foreca.sted Must Run or lale Generation (MW}
-:•.A9'at�'ll<llM*W ....
c::::,�,v�,cu•,:•,
, .. ,._ .. ,'l,:liffV"'ll•tC•i
,-,,.au, ,-,.&,JUI Motl.IOU
-
4
8
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6
5
11
12
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13
FlrstWeekoftM Month
14
15 As can be seen, reversing the display of the various
16 resources causes it to appear that Idaho Power's
17 "must-run" resources are the source of oversupply, not
18 PURPA. In truth, all of the resources are all part of the
19 same power supply system and contribute to over and
20 undersupply at any point in time.
21 Q. ARE YOU IMPLYING THAT COMPANY-OWNED RESOURCES
22 AND PURPA RESOUCES ARE THE SAME THING?
23 A. No. There are important differences depending
24 on the type of resource, and both impose different risks
25 and provide benefits for ratepayers under different load
807 Reading, Di 22
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1 and resource and power market conditions. The off-system
2 price of power is currently relatively low, and the
3 Northwest currently has a surplus of power. However,
4 history shows that power market prices in the Northwest
5 have been volatile and power surpluses and deficits can
6 change quickly. One thing that is certain is there will
7 be ups and downs in the future, and the current situation
8 will not stay the same as today over the next 20 years.
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1 Q. CAN YOU PROVIDE AN EXAMPLE OF WHAT YOU MEAN BY
2 SAYING THERE CAN SOMETIMES BE RAPID CHANGES IN POWER
3 MARKETS?
4 A. The most dramatic swing in market prices for
5 power in the Northwest in the recent past is the
6 so-called "Enron meltdown" when Mid-C prices got as high
7 as $677 per MWh in June of 2000 on a daily basis.12 At
8 the same time, due to a variety of causes, utilities were
9 facing power shortages. With the then-dramatic swings as
10 background, the Commission issued Order No. 29029 quoted
11 above and increased the length of PURPA contracts to 20
12 years from five years and raised the eligibility cap for
13 published rates.13
14 Q. WHAT OTHER ACTIONS DID THE COMMISSION UNDERTAKE
15 IN THIS VOLATILE MARKET TIME FRAME?
16 A. The Commission, in July of 2001, approved a
17 Certificate of Public Convenience and Necessity (CPCN)
18 for Idaho Power's peaking facility, the Mountain Home
19 Generation Station (Danskin). In its decision the
20 Commission said,
21 We note that the procedure followed in this
22 case has limited the type and extent of review that
23
24
25
would otherwise occur in a certificate filing. The
price of power on the spot market, the shortage of
water for hydro generation and the Company's
809 Reading, Di 23
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1 projected inability to serve native load
2 requirements with Company generation and contract
3 supplies have all joined to create the unique
4 factual situation presented and have also fashioned
5 the particular regulatory treatment requested by the
6 Company.
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24 12 https://www.nwcouncil.org.Appendix
C Electricity Price Forecast .pdf.
25 13 IPUC Order No. 29029, at p. 7.
810 Reading, Di 23a
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1 We are convinced that the volatility of the
2 electric spot market created a situation that
3 justified a deviation from the Company's 2000 IRP
4 and its actions in developing plans for the Mountain
5 Home Station.14
6 Faced with the upheaval in the power markets at this
7 time, the Commission reacted by increasing the length of
8 PURPA contracts to 20 years and approving a peaking plant
9 that was not included in Idaho Power's Near-Term Action
10 Plan in its 2000 IRP. The point of the above example is
11 that over a time period of a just a few years unforeseen
12 circumstances can significantly impact market conditions
13 for both supply and price. Current power market
14 conditions today have no guarantee they will remain the
15 same over a 20-year period.
16 Q. COULD YOU PLEASE EXPLAIN FURTHER WHAT YOU MEAN
17 BY SAYING BOTH UTILITY-OWNED RESOURCES AND PURPA
18 RESOURCES HAVE DIFFERENT RISKS AND BENEFITS FOR
19 RATEPAYERS?
20 A. Utility-owned resources and PURPA supply costs
21 impact ratepayers in different ways. A PURPA project
22 will only get paid when it supplies power to the utility.
23 On the other hand, with a rate-based, utility-owned
24 resource, the capital portion of the plant is rolled in
25 customer rates even if the facility is idle. This means
811 Reading, Di 24
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1 for a utility-owned resource the capacity costs are
2 factored into retail rates on a per-MWh basis, and they
3 can vary significantly as the capacity costs of the
4 facility are spread over higher and lower power output.
5 For a PURPA resource, the capital portion of the price is
6 included in the levelized dollars per MWh, and ratepayers
7 are charged only when the facility provides power.
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812 Reading, Di 24a
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1 Idaho Power says it is concerned that as QF
2 contracts get longer there is increased risk and
3 potential harm to ratepayers, without recognizing their
4 own resources lock in ratepayers as well to pay for their
5 own generating resources. The Commission Staff asked
6 Idaho Power;
7 REQUEST NO. 18: On page 22, the Petition states that
8 ". . . the risk and potential harm increases, the
9 longer the price estimates are locked in." Does
10 Idaho Power believe long-term, locked-in price
11 estimates could potentially benefit Idaho Power in
12 some circumstances?
13 RESPONSE TO REQUEST NO. 18: No.15
14 What Idaho Power is failing to acknowledge is that their
15 own plants are also "locked in" for ratepayers for the
16 plant life that is 20 or more years.
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18
Q.
A.
DOES THIS EXAMPLE DEMONSTRATE ANY OTHER POINTS?
The above example also points out that PURPA
19 projects, even those with 20-year contracts, do provide a
20 risk hedge and a benefit to ratepayers. PacifiCorp's
21 witness Mr. Duvall agrees with this point and has
22 testified at length before the Washington Commission
23 regarding the extensive benefits of PURPA projects:
24 In addition to providing the capacity benefits
25 discussed above, the out-of-state QFs provide
813 Reading, Di 25
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significant benefits because they are renewable,
emission-free generators.
* * * *
4 Emission-free resources may act as a hedge
5 against future carbon regulation, the exact nature of
6 which is currently unknown. In fact, the
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814 Reading, Di 25a
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Commission has acknowledged that future carbon
regulation may have a significant impact on the
Company's operations. The out-of-state QFs, like all
of the Company's renewable resources, will help to
mitigate that impact.16
6 Q. ARE THERE OTHER WAYS THAT PURPA POWER PROJECTS
7 CAN LOWER RISKS FOR RATEPAYERS THAT UTILITY-OWNED
8 RESOURCES DON'T?
9 A. In addition to not requiring ratepayers to pay
10 for the capital portion of undelivered electricity, PURPA
11 resources avoid the fuel cost risks ratepayers face from
12 a utility's own resources. All three utilities that are
13 part of this case have some form of a power cost
14 adjustment mechanism that, on an annual basis, allows
15 them to recover the majority of their net power supply
16 expenses. This means the utility is able to pass onto
17 ratepayers any fluctuations in the costs of their fuel
18 supplies so that it is the ratepayer, not the utility,
19 that assumes the risk.
20 Q. THE THREE INVESTOR OWNED UTILITIES ALL ARE
21 PROPOSING TO SHORTEN THE CONTRACT LENGTH FOR ALL PURPA
22 PROJECTS ABOVE THE ELIGIBILITY RATE CAP, IDAHO POWER FOR
23 TWO YEARS AND ROCKY MOUNTAIN POWER THREE YEARS. AVISTA
24 RECOMMENDS FIVE YEARS AND BELIEVES IF A VERY FAVORABLE
25 OPPORTUNITY WAS PRESENTED TO THE UTILITY IT SHOULD HAVE
815 Reading, Di 26
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1 AN OPTION FOR A LONGER CONTRACT.17 DO YOU AGREE WITH THE
2 RECOMMENDATIONS OF THE UTILITIES?
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24 2014, p. 17-18).
17 Direct Testimony of Clint Kalich, Avista Corporation, February 27,
25 2015, AVU-E-15-01, p. 3.
816 Reading, Di 26a
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1 A. The Companies are advocating an unreasonably
2 overbroad approach by treating all types of PURPA
3 resources the same. Limiting the contract length will
4 cause all types of PURPA projects to become uneconomic
5 due to the inability to obtain financing, not just "wind
6 and solar." The Idaho Commission has established
7 precedent for setting different terms and conditions for
8 different types of PURPA projects.
9 Recently, in Case No. GNR-E-10-04 the Commission
10 lowered the eligibility cap for wind and solar to 100 kW
11 while leaving the higher 10 average monthly MW cap for
12 all other project types. The Commission's rationale for
13 doing so was that wind and solar resources have unique
14 characteristics not found in other types of PURPA QFs.
15 Based upon the record, the Commission finds that a
16 convincing case has been made to temporarily reduce
17 the eligibility cap for published avoided cost rates
18 from 10 aMW to 100 kW for wind and solar only while
19 the Commission further investigates the implications
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of disaggregated QF projects. We maintain the
eligibility cap at lOaMW for QF projects other than
wind and solar (including but not limited to
biomass, small hydro, cogeneration, geothermal, and
waste-to-energy). The Petitioners have not
convinced us that lowering the eligibility cap for
817 Reading, Di 27
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1 these other QF technologies is necessary or in the
2 public interest.
3 Wind and solar resources present unique
4 characteristics that differentiate them from other PURPA
5 QFs. Wind and solar generation, integration, capacity
6 and ability to disaggregate provide a basis for
7 distinguishing the eligibility cap for wind and solar
8 from other resources.18
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818 Reading, Di 27a
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1 Currently, the three utilities have posted different
2 published avoided cost rates for different resource
3 types. Each of the utilities recognizes QFs have
4 different defining characteristics.
5 Q. BOTH CLEARWATER AND SIMPLOT CURRENTLY HAVE
6 COGENERATION PROJECTS. DO YOU BELIEVE THEY HAVE
7 CHARACTERISTICS THAT DISTINGUISH THEM FROM WIND AND SOLAR
8 AS WELL AS OTHER PROJECTS?
9 A. Cogeneration projects have "unique
10 characteristics" that are distinct from other types of
11 PURPA projects. They are more fuel efficient than
12 traditional generation and support a stronger economy.
13 FERC defines a cogeneration facility as,
14 A cogeneration facility is a generating facility
15 that sequentially produces electricity and another
16 form of useful thermal energy (such as heat or
17 steam) in a way that is more efficient than the
18 separate production of both forms of energy. For
19 example, in addition to the production of
20 electricity, large cogeneration facilities might
21 provide steam for industrial uses in facilities such
22 as paper mills, refineries, or factories, or for
23 HVAC applications in commercial or residential
24 buildings.19
25 FERC regulations also exempt cogeneration QFs from the 80
819 Reading, Di 28
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1 MW cap imposed on other types of qualifying facilities,
2 and FERC has stated that,
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what-is.asp
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820 Reading, Di 28a
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1 Cogeneration facilities can use significantly less
2 fuel to produce electric energy and steam (or other
3 forms of energy) than would be needed to produce the
4 two separately. 20
5 According to an Iowa State University doctoral
6 dissertation,
7 Cogeneration has a fuel efficiency of 80% to 90 %
8 compared to the 33% fuel efficiency of conventional
9 electricity generation units.21
10 Q. YOU STATED ABOVE THAT COGENERATION SUPPORTS A
11 STRONGER ECONOMY. WHY DO YOU SAY THAT?
12 A. Cogeneration supports the economic viability of
13 Idaho industrial facilities. While this is not linked
14 directly to a utility's avoided cost, it contributes to
15 the strength of Idaho's economy and employment, which in
16 turn helps make a stronger utility. Also, cogeneration
17 facilities produce electric power without using
18 additional fuel or contributing additional pollution,
19 which also benefits society. Cogeneration represents one
20 of the most effective approaches to energy conservation,
21 because it produces two types of energy at once -
22 electric power and thermal energy. Conventional thermal
23 power generators typically range from 33% to 60%
24 efficient, with coal plants in the lower end of the range
25 and combined cycle gas plants in the upper range. They
821 Reading, Di 29
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1 essentially waste between 40% to 67% of the fuel energy
2 -- whereas cogeneration facilities can achieve
3 efficiencies of 80%. On top of that, cogeneration
4 facilities make the host manufacturing plant more
5 financially secure with all the attendant societal
6 benefits
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23 20 FERC Order 688, Docket RM06-010, at p. 14 (Oct. 20, 2006).
21 The Economic and Environmental Performance of Cogeneration under
24 the Public Utility Regulatory Policies Act, Daniel, Shantha E., Iowa
State University, 2009, p. 4.
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822 Reading, Di 29a
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1 of having a more robust economy. Cogeneration also
2 significantly reduces carbon emissions, reduces business
3 costs, relieves grid congestion and improves energy
4 security.
5 Q. ARE THERE OTHER CONSIDERATIONS RELATED TO THE
6 BENEFITS OF COGENERATION IN THE CONTEXT OF THIS
7 PARTICULAR CASE?
8 A. Yes. As I noted earlier, Idaho Power's
9 petition primarily points to a problem of oversupply of
10 generation that is occurring during certain times of the
11 year as a result of intermittent and relatively
12 unpredictable PURPA output from wind and solar projects.
13 Cogeneration QFs are base-load resources that do not
14 provide intermittent deliveries, and their output should
15 be more easily predicted and managed during these
16 over-supply periods.
17 Q. WHAT IS THE POSITION OF THE THREE UTILITIES
18 RELATING TO THE PURPA PROJECTS PROPOSED IN THEIR
19 RESPECTIVE SERVICE TERRITORIES?
20 A. The perceived "flood" of PURPA projects varies
21 among the three utilities. Idaho Power states the Company
22 currently has 461 MW of PURPA solar capacity under
23 contract with an additional 885 MW in the queue actively
24 seeking power sales agreements.22 Rocky Mountain Power
25 states it has had an "exponential increase in PURPA
823 Reading, Di 30
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1 contract requests" consisting of 97 projects totaling
2 1,553 MW in the last two years throughout its multi-state
3 system.23
4 Q. WHAT IS AVISTA'S POSITION WITH REGARD TO QFS
5 SEEKING PURPA CONTRACTS IN ITS SERVICE TERRITORY?
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24 22 Idaho Power's Petition, !PUC Case No. IPC-E-15-01, p. 18.
23 Rocky Mountain Power's Petition, !PUC Case No. PAC-E-15-03, p. 19.
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824 Reading, Di 30a
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1 A. While Avista is not claiming there is a torrent
2 of PURPA projects in its service territory, its concern
3 is if a neighboring utility such as Idaho Power offers
4 only five-year contacts "sophisticated and motivated
5 PURPA developers" will seek longer term contracts by
6 wheeling the QF output to Avista.24 Avista advocates
7 for the ability to contract for PURPA projects with terms
8 longer than five years in the event of a very favorable
9 PURPA opportunity.25 Avista, however, does not offer
10 specifics on what a "very favorable PURPA opportunity"
11 means, and it does not state that it supports continuing
12 20-year QF contracts for projects subject to the IRP
13 methodology.
14 Q. DO YOU AGREE WITH AVISTA'S POSITION THAT
15 UTILITIES SHOULD BE ALLOWED TO NEGOTIATE A TERM LONGER
16 THAN THE COMMISSION-AUTHORIZED TERM?
17 A. Yes. Under the Commission's long-standing
18 rules, utilities have always been allowed to negotiate a
19 term longer than the Commission-approved contract length.
20 I agree that regardless of the outcome of this proceeding
21 the utility and the QF should be allowed to agree to a
22 longer term under the appropriate circumstances.
23 Q. DOES AVISTA PROVIDE ANY EVIDENCE THAT ANY QFS
24 HAVE TRIED TO WHEEL THEIR OUTPUT TO SELL IT TO AVISTA,
25 GIVEN THE OVERSUPPLY PROBLEM ON IDAHO POWER'S SYSTEM?
825 Reading, Di 31
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1 A. No. Avista provides no evidence any QF has
2 tried to wheel its power to Avista to sell to it from
3 off-system. Avista only points to a single QF, operated
4 by Kootenai Electric Cooperative, Inc., that sought to
5 wheel its output away from Avista and to Idaho Power.
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23 24 Direct Testimony of Clint Kalich, Avista Corporation, IPUC Case
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24 25 Id. at pp. 2-3.
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826 Reading, Di 31a
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3 IDAHO POWER'S PETITION MAY SEEK TO SELL TO AVISTA
6 are lower than Idaho Power's avoided costs for solar
2 THE LARGE NUMBER OF PROSPECTIVE SOLAR QFS DISCUSSED IN
DOES AVISTA PROVIDE ANY REASON TO BELIEVE THAT
No. Avista's avoided costs for solar resources
Q.
A. 5
1
4 INSTEAD?
7 resources because Avista has a different load profile
8 that does not lend itself to high avoided costs for solar
9 output. Avista's published rates for solar projects are
10 currently set at $49.77 per MWh on a 20-year levelized
11 basis for an online date in 2016, while Idaho Power's
12 comparable rate for a 2016 online year is $66.85 per MWh.
13 I would expect the IRP methodology rates may well be
14 lower than the $49.77 per MWh amount, plus the off-system
15 solar QF would need to pay to wheel the output to Avista.
16 There is no reason to believe solar QFs would be able to
17 rely on the economics of those low rates to finance a
18 solar QF.
19 Q. IDAHO POWER, AS YOU POINTED OUT ABOVE, STATES
20 IT HAS 461 MW OF PURPA SOLAR CAPACIY UNDER CONTRACT AND
21 AN ADDITIONAL 885 MW IN THE QUEUE TO BE ON-LINE IN 2016.
22 DO YOU HAVE AN OPINION AS TO THE PROBABILITY THAT ALL
23 THOSE QF PROJECTS WILL ACTUALLY BE CONSTRUCTED?
24 A. In Response No. 2 to the Idaho Conservation
25 League and Sierra Club's First Production Request Idaho
827 Reading, Di 32
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1 Power stated,
2 As of the date of the response to this Request, 380
3 megawatts ("MW") of the 521 MW of QFs under
4 contract, but not yet on-line, are in compliance
5 with their respective agreements; therefore, Idaho
6 Power has no reason to assume they will not come
7 on-line as stated in their agreements. To date, 141
8 MW of the 521
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828 Reading, Di 32a
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1 MW are not in compliance with their respective QF
2 agreements and Idaho Power is taking the appropriate
3 actions as allowed within those agreements.26
4 Based on a copy of a letter provided to me by the
5 developer, Idaho Power has now terminated the four
6 projects with 141 MW of capacity, Clark Solar 1 through
7 4. I have provided a copy of this letter as Exhibit No.
8 205. This means more than one-fourth of the capacity of
9 the signed QF contracts due to come on line in 2016 have
10 had their contracts terminated. At this point, the
11 status of the others under contract is uncertain.
12 The projects that do not have executed contracts
13 appear to be unlikely to ever obtain a contract or be
14 developed in the near future. Under Idaho Power's
15 Schedule 73, a developer must only provide basic project
16 information in writing to receive indicative pricing, and
17 must provide a few additional items, such as proof of
18 site control over the property underlying the project, in
19 order to obtain a draft contract. In response to Simplot
20 Production Request No. 4, Idaho Power indicates, of the
21 48 PURPA projects that comprise the 885 MW in the queue
22 requesting pricing or contracts, only one of the proposed
23 projects has provided sufficient information to receive a
24 draft energy sales agreement and 61% of the Idaho
25 projects have failed to provide enough information to
829 Reading, Di 33
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1 receive indicative pricing. Idaho Power has provided no
2 documents supporting an assertion that most of these
3 projects provided anything more than a simple inquiry
4 through a telephone call.
5 In addition, if any of the solar projects fail to be
6 on-line before the end of 2016, the investment tax
7 credits for capital costs will drop from 30% to 10%.
8 Thus, there is
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24 26 Idaho Power's Response to Idaho Conservation League/Sierra Club
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830 Reading, Di 33a
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1 sufficient evidence to doubt that the volume of solar
2 projects claimed by Idaho Power will actually be
3 producing electricity by the end of 2016, if ever.
4 Q. ARE THERE OTHER ISSUES FOUND IN ANY OF THE
5 UTILITIES' FILINGS?
6 A. Yes. Rocky Mountain Power proposes to change
7 the IRP methodology to better respond to a large influx
8 of QFs. Rocky Mountain Power stated they are seeking the
9 Commission to approve,
10 Modification of the Company's avoided cost
11 methodology such that preparation of indicative
12 pricing for QFs reflects all active QF projects in
13 the pricing queue ahead of any newly proposed QF
14 requests for indicative pricing.21
15 Q. DO YOU AGREE WITH ROCKY MOUNTAIN POWER THAT THE
16 COMMISSION SHOULD CONSIDER REVISIONS TO THE AVOIDED COST
17 PRICING METHODOLOGY?
18 A. Yes. For the reasons I will explain further
19 below, it would be appropriate to address the avoided
20 cost pricing methodology if the utilities have truly
21 demonstrated that there is an oversupply problem.
22 However, unlike Rocky Mountain Power, I believe that
23 adjusting the pricing methodology to send accurate price
24 signals is the only step that needs to be taken to
25 rectify any problems with Idaho's implementation of
831 Reading, Di 34
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1 PURPA.
2 Q. HAVE THERE BEEN SOME OTHER CHANGES IN THE
3 METHOD TO FIND AVOIDED COST SINCE THE COMMISSION ISSUED
4 ITS ORDER IN GNR-E-11-03, THE CASE THAT APPROVED THE
9 the Commission
5 CURRENT METHOD?
8 (IPC-E-14-20) and Grand View PV Solar Two (IPC-E-14-19)
Yes. When Idaho Power filed with the A. 6
7 Commission its PURPA contracts with Boise City Solar
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4.
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1 Staff filed Comments stating they were correcting some
2 "errors" caused by the simplifying assumption in Idaho
3 Power's single-run method approved by the Commission.
4 Staff then recalculated the rates offered by Idaho Power
5 for the two contracts.28 The two projects decided to
6 accept the lower rates based on Staff's methodological
7 changes that were subsequently corrected by Idaho Power.
8 Rocky Mountain Power's suggestion to update the resource
9 stack more quickly to respond to large influxes of QFs
10 may also be appropriate.
11 Q. IDAHO POWER ASSERTS THAT IT HAS AN OVER-SUPPLY
12 PROBLEM DURING CERTAIN TIMES THAT CAUSES IT TO SELL PURPA
13 POWER ON THE MARKET AT AN ECONOMIC LOSS. DO YOU KNOW OF
14 OTHER ADJUSTMENTS TO THE AVOIDED COST METHODOLOGY THAT
15 COULD POTENTIALLY BE EXAMINED?
16 A. Idaho Power is describing a situation where the
17 actual avoided costs during certain time frames may be
18 negative because the Company states it would incur an
19 economic loss by accepting the QF power. The
20 Commission's Staff Production Request No. 14 asked if
21 Idaho Power's single-run IRP methodology accounts for
22 such instances by assuming excess PURPA generation will
23 be sold at a loss, and thus lower the overall average
24 avoided cost over the term of the contract. The Company
25 responded,
833 Reading, Di 35
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1 Within the Incremental Cost IRP Methodology (IRP
2 methodology) the hourly price is assigned based on
3 the highest increment cost displaceable generation
4 resource operating in that hour. The displaceable
5 resources being Idaho Power-owned generation,
6 including any must-run limitations and Idaho Power
7 market
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purchases. If there are no displaceable
resources available in a specific hour, the energy
rate is set to $0 in that hour. The methodology does
not assume excess PURPA generation will be sold at a
loss.29
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A.
HOW DO YOU INTERPRET THE COMPANY'S RESPONSE?
Idaho Power indicated that the single-run
8 methodology does not address the circumstance where the
9 avoided costs are negative due to uneconomic off-system
10 sales during the over-supply event, and instead assigns
11 an avoided cost of zero when the actual avoided cost is
12 negative.
13 Q. WHAT WOULD BE THE IMPACT OF CHANGING THE
14 METHODOLOGY SO THAT IT COULD ACCOUNT FOR NEGATIVE AVOIDED
15 COSTS?
16 A. The average avoided cost offered to the QF
17 would incorporate these instances of negative avoided
18 costs, and the instance of negative avoided costs would
19 cause the overall average rate calculated over the term
20 of the agreement to be lower.
21 Q. WHAT WOULD BE THE REAL-WORLD IMPACT OF A LOWER
22 OVERALL AVOIDED COST ASSOCIATED WITH THE INSTANCES OF
23 NEGATIVE AVOIDED COSTS?
24 A. The impact would be that the IRP methodology
25 rates offered to prospective QFs would be lower. That
835 Reading, Di 36
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1 lower price signal would, based on that QF's projected
2 output profile, determine whether the project could be
3 economically developed. In this example, I would expect
4 that a lower avoided cost rate would have the impact of
5 deterring PURPA development.
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1 Q. IN YOUR OPINION, IS AN ACCURATE PRICE SIGNAL A
2 BETTER WAY TO ADDRESS THE ALLEGED PURPA PROBLEM IDAHO
3 POWER IDENTIFIED THAN A SHORTER CONTRACT TERM?
4
5
A.
Q.
Yes.
DO YOU HAVE ANY OTHER COMMENTS ON THE
6 LIMITATIONS OF THE CURRENT SINGLE-RUN METHODOLOGY?
7 A. The prior double-run methodology would have
8 accurately taken into account the instances where
9 off-system sales caused the avoided costs to be negative,
10 and in my opinion would send more accurate price signals.
11 Q. YOU HAVE JUST DISCUSSED POTENTIAL ADJUSTMENTS
12 THAT HAVE BEEN MADE OR COULD BE MADE TO THE CALCULATION
13 OF AVOIDED COSTS. ARE YOU RECOMMENDING ANY OF THESE
14 CHANGES BE MADE AND APPROVED BY THE COMMISSION?
15 A. No, not without considering other potential
16 adjustments to send accurate price signals. In a fully
17 litigated case dealing with avoided cost methodologies,
18 there would no doubt be changes to the method of
19 calculating avoided costs that would cause resulting
20 increases and decreases to QF prices offered by the
21 utilities. What I am suggesting is that correct pricing
22 should be used rather than an arbitrarily short contract
23 length that will, on its own, discourage PURPA
24 development. If the price is not sufficient to make a
25 project profitable at the utility's avoided costs, the
837 Reading, Di 37
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1 length of the contract is irrelevant and projects will
2 not be built. The key is to properly price the avoided
3 costs at the utility's avoided costs. This is what PURPA
4 was intended to do and will only encourage projects when
5 they meet a threshold price of the project being
6 economical.
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1 Q. WHAT ARE YOUR RECOMMENDATIONS FOR THE
2 COMMISSION?
3 A. Because limiting the term of contracts to five
4 years or less will essentially eliminate all types of
5 PURPA projects including those that are environmentally
6 sound, fuel efficient, and contribute to the economy of
7 the state, I recommend the Commission maintain the
8 current 20-year contract length for QFs eligible for the
9 IRP methodology, or at a minimum for all non-intermittent
10 QFs. If adjustments need to be made to the Commission's
11 implementation of PURPA, they should be made through the
12 calculation of avoided cost rates and not arbitrarily
13 limiting the term of the contract to a length that is
14 intentionally designed to prohibit financing or otherwise
15 ensure that no QF receives capacity payments.
16 Q. DOES THIS END YOUR TESTIMONY AS OF APRIL 23,
17 2015?
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839 Reading, Di 38
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1
2
Q.
A.
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Don Reading and my business address
3 is Ben Johnson Associates, 6070 Hill Road, Boise, Idaho.
4 I am Vice President and Consulting Economist for Ben
5 Johnson Associates.
6 Q. ARE YOU THE SAME DON READING WHO PREFILED
7 DIRECT TESTIMONY IN THE CURRENT DOCKET ON APRIL 23RD,
8 2015?
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Q.
A.
Yes.
WHAT IS THE PURPOSE OF YOU REPLAY TESTIMONY?
The following Reply Testimony is to provide
12 comments on the Intervenor testimonies of Rick Sterling
13 and Yao Yin of the Commission Staff (Staff), Adam Wenner
14 and R. Thomas Beach for Idaho Conservation League and the
15 Sierra Club (ICL/Sierra), Anthony J. Yankel for the Idaho
16 Irrigation Pumpers Association (IIPA), John R. Lowe of
17 the Renewable Energy Coalition (Coalition), Ken Miller of
18 the Snake River Alliance (SRA), and Mark Van Gulik of the
19 Intermountain Energy Partners (IEP). Each of the above
20 Intervenors filed Direct Testimony in response to the
21 petitions filed by Idaho Power Company (Idaho Power),
22 Avista Corporation (Avista), and Rocky Mountain Power
23 ( RMP) (collectively the "Utilities") as king the Idaho
24 Public Utilities Commission (Commission, IPUC) to modify
25 the terms and conditions of Public Utility Regulatory
840 Reading, Reply 2
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1 Policies Act of 1978 (PURPA) contracts.
2 Five of the seven non-utility parties - including
3 Simplot/Clearwater - that filed direct testimony three
4 weeks ago strongly urged the Commission not to shorten QF
5 contract lengths from the current 20 years. The IIPA
6 witness Tony Yankel proposed a
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1 temporary two year contract length as a "stopgap" in
2 order to allow time to correct errors he identified in
3 the Commission's avoided cost model. The Commission Staff
4 recommends maintaining a 20 year contract length for
5 PURPA projects that currently qualify for SAR-based rates
6 and a maximum five years for QFs subject to the IRP based
7 rates.
8 In our reply testimony, Simplot/Clearwater
9 recommend a compromise proposal pertaining to PURPA
10 contract length for QFs ineligible for standard rates.
11 We propose that capacity and energy be treated slightly
12 differently within the term of a 20-year contract. We
13 recommend the Commission maintain a 20-year contract
14 length with the capacity component of the rate fixed for
15 the entire 20-year term. However, as a compromise, the
16 energy portion of the rate would only be fixed for the
17 first 10 years of the contract. After the first 10
18 years, the energy component would be recalculated each
19 year adhering to the Commission approved method for the
20 remaining term of the contract. Simplot/Clearwater still
21 believe the current 20-year term, for reasons stated in
22 my direct testimony, should be maintained. However, as
23 described below, this alternative proposal addresses some
24 of the concerns of the other parties.
25 Q. YOU ARE RECOMMENDING THE ENERGY COMPONENT OF
842 Reading, Reply 3
Simplot/Clearwater
1 THE 20-YEAR CONTRACT BE UPDATED ANNUALLY OVER THE SECOND
2 TEN YEARS. ARE THERE CURRENT PURPA CONTRACTS IN IDAHO
3 THAT THE ENERGY PORTION IS UPDATED ANNUALLY?
4 A. Yes. There are approximately 25 PURPA
5 contracts that are adjusted periodically based on coal
6 costs. The commission uses the variable costs associated
7 with the operation of Colstrip, a coal-fired generation
8 facility located in southeast Montana, for an annual
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25
843 Reading, Reply 3a
Simplot/Clearwater
1 adjustment of the adjustable portion of avoided costs for
2 those contracts. These projects had their rates set
3 using an older coal SAR methodology. So there is ample
4 precedent for adjusting PURPA contracts on an annual
5 basis.
6 Q. Are YOU AWARE OF OTHER PURPA CONTRACTS APPROVED
7 BY THE IDAHO COMMISSION WHERE CAPACITY IS FIXED FOR THE
8 TERM OF THE CONTRACT AND ENERGY IS ADJUSTED PERIODICALLY?
9 A. There are approximately 43 PURPA contracts tied
10 to Idaho Power's Schedule 89 where the energy rate is
11 adjusted when Net Power Supply Expenses (NPSE) are
12 changed in the Company's base rates. For these projects
13 the capacity component was fixed for the life of the
14 contract, however the utility's variable costs, including
15 fuel and variable operation and maintenance costs, are
16 adjusted when these expenses change in the Company's base
17 rates, most often in a general rate case filing. This
18 approach was intended to minimize potential overpayments
19 and underpayments. The Commission's rational for
20 establishing these contracts was:
21 Idaho Power appears particularly sensitive to
fluctuations in avoided energy costs. Allowing
22 energy payments derived from annual estimation of
avoided costs may obligate the Company to payments
23 in excess of the actual avoided costs. Conversely,
annual estimates of avoided energy costs may also
24 allow the QF too little. Underpayments are likely to
occur from this scheme during poor water years or
25 during nearly every year for those facilities whose
production coincides with the months of high avoided
844 Reading, Reply 4
Simplot/Clearwater
1
2
3
energy costs. In the long run, a policy based on
Idaho Power's estimated avoided costs at delivery
time reduces the financial risk to both the utility
and the QF.1
4 If the Companies were filing periodic rate cases or
5 updates to base rates then the energy costs would be
6 adjusted every few years.
7 I
8
9 I
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12
13
14
15
16
17
18
19
20
21
22
23
24 1 Order No. 15746, Docket No. P-200-12.
25
845 Reading, Reply 4a
Simplot/Clearwater
1 Q. YOU STATED ABOVE YOUR ALTERNATIVE PROPOSAL
2 ADDRESSES SOME OF THE CONCERNS OF THE OTHER PARTIES.
3 COULD YOU PLEASE BE MORE SPECIFIC?
4 A. The majority of the intervenors focused on the
5 inability of a PURPA project to receive financing with
6 shortened contracts on the one hand, and on the other
7 hand the Utilities and Staff focused on the risks
8 ratepayers face from the utilities signing fixed-price
9 long-term contracts. As I explained in my direct
10 testimony, I do not agree with the latter contention of
11 ratepayer risk, however the alternative proposal offered
12 here addresses that issue by adjusting the energy
13 component annually during the second ten years of the
14 contract.
15 Q. YOU SAID MOST OF THE INTERVENORS ARE CONCERNED
16 ABOUT THE INABILITY OF PURPA PROJECTS TO OBTAIN FINANCING
17 USING SHORT-TERM CONTRACTS. COULD YOU CITE SOME
18 EXAMPLES?
19 A. Without repeating the logic used by the
20 intervenors, the crux of their positions was made
21 clear in their direct testimony. The shorter the
22 contract length the more difficult it is to obtain
23 financing for a PURPA project. For example, "The
24 consequence of a Commission order limiting energy sales
25 agreements to two or five years would be to bring any
846 Reading, Reply 5
Simplot/Clearwater
1 meaningful PURPA development in Idaho to a halt. "2 The
2 Renewable Energy Coalition witness John Lowe stated, "In
3 addition, imposing a policy change like a shortened
4 contract term on existing QFs could have significant and
5 unnecessary harm on these projects, the utilities, and
6 ratepayers. 1 And,
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17
18
19
20
21
22
23
I
I
I
This need for long term assurance of capital
recovery is the same for QFs as it is for a utility
that proposes to build a new power plant and seeks
Commission
24 2 Direct Testimony of Mark Van Gulik, Intermountain Energy
Partners, March 23, 2015, IPC-E-15-01, p. 2.
25
847 Reading, Reply Sa
Simplot/Clearwater
1
2
3
approval for long-term recovery of the plant's costs
by including them in rate base. This history
suggests that, without long-term, 20-year contracts,
QFs will not be developed in Idaho.3
4 The Commission Staff, while recommending five year
5 contracts for IRP method based PURPA contracts, also
6 acknowledged,
7 Q. But won't a five-year limit on maximum contract
length, if approved, limit the ability of projects
8 to obtain financing, thus making extensive project
development unlikely?
9 A. Yes, I agree that development would likely slow
considerably, at least under PURPA.4
10
11 Also Snake River Alliance witness Ken Miller said,
12 I think this application, if approved, will cause
further migration of solar developers away from
13 Idaho, as the proposed reduction in contract terms
to two years is tantamount to a freeze on future
14 solar PURPA projects.5
15 Q. DR. READING, I REALIZE YOU ARE AN ECONOMIST NOT
16 A LAWYER, BUT DID ONE OF THE INTERVENORS EXPRESS SOME
17 LEGAL CONCERNS ABOUT SHORTER CONTRACTS FAILING TO MEET
18 FERC'S PURPA REQUIREMENTS?
19 A. Yes. ICL/Sierra witness Adam Wenner stated in
20 his direct testimony,
21 In the electric utility industry, and as discussed
in my testimony, a two-year term fails to permit a
22 QF to estimate, with reasonable certainty, the
expected return on its potential investment in a QF,
23 and would frustrate the requirement of section 210
of PURPA that FERC's rules, as implemented by state
24 commissions, encourage cogeneration and small power
production.6
25
848 Reading, Reply 6
Simplot/Clearwater
1
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9
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18
19
20
21 3 Direct Testimony of R. Thomas Beach, Idaho Conservation
League and Sierra Club, March 23, 2015, IPC-E-15-01, p.10.
22 4 Direct Testimony of Rick Sterling, Idaho Public Utilities
Commission Staff, March 23, 2015, IPC-E-15-01, p. 8.
23 5 Direct Testimony of Ken Miller, Snake River Alliance, March
23, 2015, IPC-E-15-01, p.10.
24 6 Direct Testimony of Adam Wernner, Idaho Conservation League
and Sierra Club, March 23, 2015, IPC-E-15-01, p. 10.
25
849 Reading, Reply 6a
Simplot/Clearwater
1 The alternative proposal offered here is aimed at finding
2 a balance among the parties' concerns about a QF's
3 ability to obtain financing, FERC's legal requirements
4 under PURPA and the risks of longer term fixed contracts
5 in an uncertain world.
6 Q. YOU JUST USED THE TERM "BALANCE" AMONG THE
7 VARIOUS VIEWS OF THE PARTIES. WHY DO YOU BELIEVE YOUR
8 ALTERNATIVE PROPOSAL HELPS ALLEVIATE SOME OF THOSE
9 CONCERNS?
10 A. The alternative proposal offered here maintains
11 a fixed capacity component of the rate for the full
12 20-year duration, which more closely matches the fixed
13 capacity length of a utility-built facility. A QF, under
14 current Commission policy, does not receive capacity
15 credits until the utility's IRP shows a capacity deficit,
16 therefore putting a QF resource and a utility built
17 resource on relatively equal footing. The energy
18 component, on the other hand, will be updated annually
19 over the last ten years of the contract, reducing the
20 perceived risk to ratepayers from fluctuating fuel costs.
21 Because the contract length would remain at 20 years and
22 have a fixed capacity component, it should give
23 financiers an additional sense of confidence and also
24 addresses FERC's legal requirements. Of course the most
25 important aspect of this compromise is the incorporation
850 Reading, Reply 7
Simplot/Clearwater
1 of a variable component for energy, the most volatile
2 portion of a utility's avoided cost.
3 Q. YOU MENTIONED ABOVE YOU WANT TO ADDRESS, IN
4 ADDITION TO YOUR PROPOSED ALTERNATIVE, A SPECIFIC ASPECT
5 OF A PARTY'S DIRECT TESTIMONY. WHAT ASPECT WOULD YOU
6 LIKE TO ADDRESS?
7 A. Commission Staff witness Rick Sterling stated,
8 Q. Do you believe PURPA is an effective
9 mechanism for utilities to acquire new
10 generation?
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21
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24
25
851 Reading, Reply 7a
Simplot/Clearwater
1 A. No, I do not. I believe PURPA was intended
2 to permit relatively small, non-utility-owned
3 projects to be developed and to compete on an
4 equal footing with utility owned facilities. I
5 do not believe PURPA was ever intended to serve
6 as the primary, or even a major, mechanism for
7 utility acquisition of new resources.?
8 I fundamentally disagree with Mr. Sterling's statement
9 that PURPA was "intended primarily to permit relatively
10 small non-utility-owned projects to be developed."
11 Utilities can, and do, develop PURPA projects. It is
12 true that in the early days, utilities could only own 50%
13 of a PURPA project, but that restriction was repealed ten
14 years ago. PURPA, arising out of the energy crises of
15 1970's was part of National Energy Act enacted in 1978.
16 The law was aimed at both relatively small renewable
17 energy projects and large projects with no limit as to
18 size. These projects provide electrical energy at a more
19 fuel efficient alternative to traditional fossil fuel
20 utility base load plant.
21 In addition, it appears at odds with Staff's
22 recommendations in this docket and Staff witness
23 Sterling's statement that PURPA was intended to allow
24 these projects to "be developed and to compete on an
25 equal footing with utility owned facilities." For
852 Reading, Reply 8
Simplot/Clearwater
1 example, Idaho Power's certificate of public convenience
2 and necessity (CPCN) for Langley Gulch does not expire
3 after five years with capacity rates adjusted to lower
4 ratepayer risk over the depreciated life of the plant. I
5 would expect Idaho Power would have difficulty financing
6 the project with a CPCN that expired after five years.
7 One of the concepts behind the creation of PURPA is
8 that the market (a.k.a developers) could provide electric
9 power at prices that are competitive with regulated
10 utilities' resources. This has been proven to be true as
11 I demonstrated in my direct
12 I
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14 I
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23
24 7 Direct Testimony of Rick Sterling, Idaho Public Utilities
Commission Staff, March 23, 2015, IPC-E-15-01, p. 24.
25
853 Reading, Reply 8a
Simplot/Clearwater
1 testimony. In addition as these facilities are added to
2 a utility's resource stack, they delay or eliminate less
3 fuel efficient future utility-built generation plant.
4 PURPA therefore is indifferent to who provides the
5 generation of electric power, the utility or a
6 non-utility generator, only the avoided cost of providing
7 the power should be the determining factor.
8 Q. DO YOU AGREE WITH MR. STERLING'S STATEMENT ON
9 PAGES 20-21 THAT "AVOIDED COST RATES HAVE EXCEEDED
10 COMPARABLE MARKET PRICES THROUGHOUT MOST OF THE HISTORY
11 OF PURPA IN IDAHO"?
12 A. No I do not. As I pointed out in my direct
13 testimony comparing long-term avoided cost estimates with
14 current market prices is, from an economist's point of
15 view, inappropriate and misleading. Long-term marginal
16 cost rates (avoided cost rates) are not the same as
17 short-term market prices. When this Commission approved
18 the Langley Gulch plant for inclusion in Idaho Power's
19 rates, it did so using long-term cost estimates over the
20 expected life of the plant. Had the Commission used
21 current market prices as the benchmark, that plant would
22 probably not have been built.
23 Q. WHAT ARE YOUR RECOMMENDATIONS FOR THE
24 COMMISSION?
25 A. While still maintaining the recommendation put
854 Reading, Reply 9
Simplot/Clearwater
1 forth in my direct testimony Simplot/Clearwater are
2 offering an alternative proposal should the Commission
3 decide alter the length of PURPA contracts. The
4 alternative recommendation is that capacity and energy be
5 treated differently within the term of a 20-year
6 contract. Capacity would remain fixed, however the
7 energy component would be recalculated each year
8 beginning in the 11th year for the remaining 10 years of
9 the contract.
10 Q. DOES THIS END YOUR TESTIMONY AS OF MAY 14,
11 2015?
12
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A. Yes.
855 Reading, Reply 9a
Simplot/Clearwater
1 (The following proceedings were had in
2 open hearing.)
3 MR. RICHARDSON: Mr. Chairman, Dr. Reading is
4 available for cross-examination.
5 COMMISSIONER KJELLANDER: Thank you very much.
6 Let's begin with Staff.
7
8
9
10
MR. HOWELL: Thank you, Mr. Chairman.
CROSS-EXAMINATION
11 BY MR. HOWELL:
12 Q. Good morning, Dr. Reading. I just have a few
13 questions, mostly about your direct testimony.
14
15
A.
Q.
Okay.
On page 2 around about line 11, you address
16 Simplot's QF project at its fertilizer plant in
17 Pocatello
18
19
A.
Q.
Yes.
-- and you say it has sold the output under a
20 series of PURPA contracts. Do you know when Simplot
21 began selling its output to Idaho Power with PURPA
22 contracts?
23 A. Oh, wow. A while ago. That's as close as I
24 can come.
25 Q. Maybe you can answer this question: During the
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856 READING (X)
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1 time that it sold power under PURPA contracts, has
2 Simplot ever had a 20-year contract with Idaho Power for
3 PURPA?
4 A. The Magic Valley -- Magic Reservoir was a 24 --
5 35-year.
6 Q. And that contract, since you brought it up,
7 Magic Valley or Magic Reservoir, Simplot wasn't the
8 initial party in that case, was it?
9
10
A.
Q.
I do not know.
Well, in Order No. 21358, it says the
11 Commission on July 10, 1987, approved an Order for firm
12 energy sales between Idaho Power and Cook Electric, Inc.
13 Is Cook Electric, Inc. Simplot?
14
15
A.
Q.
Not to my knowledge.
Later in Case IPC-E-98-14, the Commission in a
16 notice of modified procedure said or described that Magic
17 Reservoir Hydroelectric, Inc. was the successor to Cook
18 Electric.
19 MR. RICHARDSON: Mr. Chairman, if counsel for
20 the Staff could make these documents he's referring to
21 available to the witness, it might be helpful for the
22 witness to respond.
23
24
COMMISSIONER KJELLANDER: Mr. Howell.
MR. HOWELL: That ends my questions about
25 whether Idaho Power and Simplot were the original parties
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857 READING (X)
Simplot/Clearwater
1 in the hydroelectric project.
2 COMMISSIONER KJELLANDER: It sounds like he
3 surrendered.
4 Q. BY MR. HOWELL: So can you tell the Commission
5 whether Simplot at its Pocatello facility has ever had a
6 15-year contract?
7
8
9
A.
Q.
A.
Not to my knowledge.
Has it ever --
I know they've had a series of contracts of
10 varying lengths. Beyond that, I will yield to your
11 research of how long the history of the contracts are.
12 Q. Can you tell the Commission what the longest QF
13 contract was between Simplot?
14 A. The longest that I can remember, I think, was a
15 five-year, but subject to check, I'd have to look through
16 the records.
17 Q. All right, thank you. I'd like to move on now
18 to Clearwater's QF contracts and has Clearwater or its
19 predecessor Potlatch ever had a 20-year QF contract with
20 Washington Water Power or Avista?
21
22
23
A.
Q.
A.
Not to my knowledge.
Has it ever had a 15-year contract?
I do not know the history of the length of the
24 contract for Clearwater's cogeneration facility.
25 Q. And on page 3, line 19, you talk about the
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858 READING (X)
Simplot/Clearwater
1 current contract that was entered into in 2013. Is that
2 contract a PURPA contract?
3
4
A.
Q.
I think its current status is not PURPA.
And on line or, excuse me, on page 4 of your
5 direct testimony, line 9, you state that Clearwater is
6 considering constructing a new cogen facility that would
7 assist the State of Idaho in complying with EPA's
8 proposed lll(d) rule. Can you tell the Commission if
9 that rule is final?
10
11
A.
Q.
As we all know, it is not final.
And have you read Idaho's comments to that
12 proposed rule?
13
14
A.
Q.
Bits and pieces.
And can you tell the Commission what the
15 primary recommendation of the State of Idaho was in
16 response to the proposed rule?
17 A. The general tone of it was the whole thing
18 should go away.
19 Q. Would it be fair to characterize that the State
20 of Idaho said that the proposed rule should not apply to
21 Idaho because Idaho's generation mix is already very low
22 and the second lowest in the nation?
23 A. I would yield that is there. There's also lots
24 of discussions around lll(d) that it should be a regional
25 solution, and the reason for that is, of course, and why
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Simplot/Clearwater
-- - ------- ----------- -----------------------------------
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9
10
Idaho has such a low carbon footprint, for want of a
better word, is that physically within the boundaries of
the state, we don't have any coal facilities; however,
about, I think, Idaho Power -- half of the consumption in
Idaho Power's territory is from coal plants, so the
surrounding states are certainly moving ahead with trying
to have a regional solution and have the decision of the
carbon footprint based on something like consumption
rather than the physical location of the individual
plants.
11 Q. And when you talk about regional solutions, are
12 you talking about states entering into multi-state plans
13 on a state-by-state basis?
14
15
A.
Q.
Yes, I am.
And what do you think the likelihood of the
16 State of Idaho or Oregon entering into a contract?
17 A. I don't know. That's speculative and sort of
18 what witnesses are never supposed to, but moving ahead
19 where you're going with this line
20
21
Q.
A.
I'm happy if you just say it's speculation.
Okay, and speculation and explain what I mean
22 by speculation, lll(d) may go away. The multi-state
23 compact may go away. Given what the Supreme Court
24 decided yesterday on mercury emissions, the courts may go
25 away. Given all of that speculation, I firmly believe
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860 READING (X)
Simplot/Clearwater
1 that down the road, maybe sooner than later, there will
2 be higher costs for carbon, whatever kind of rules or
3 laws or whatever that will be imposed on all states in
4 the U.S., primarily from older coal plants, so we can say
5 lll(d) is not going to work, Wyoming and Idaho will never
6 get together except hunting elk or something, but I'm
7 convinced that there will be a carbon penalty for
8
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14
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electric generation in the next five, ten years.
MR. HOWELL: All right, thank you. I have no
further questions.
COMMISSIONER KJELLANDER: Thank you, Mr.
Howell. Let's move to Idaho Power.
CROSS-EXAMINATION
16 BY MR. WALKER:
17
18
19
Q.
A.
Q.
Good morning, Dr. Reading.
Good morning.
So Dr. Reading, I see from your experience and
20 credentials that you were on Staff at the Idaho Public
22
23
A.
Q.
Correct.
So could you tell us, Dr. Reading, you used the
21 Utilities Commission from '81 to '86; is that correct?
24 acronym CPCN in your testimony, can you tell us, what
25 does "CPCN" stand for?
CSB REPORTING
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861 READING (X)
Simplot/Clearwater
1
2
3
A.
Q.
Did I misspell that?
No, CPCN.
MR. RICHARDSON: Do you have a specific
4 citation to where in his testimony you're referring?
5
6
MR. WALKER: No, just generally.
MR. RICHARDSON: You don't have any idea where
7 you're referring to?
8
9 testimony.
10
11
MR. WALKER: Throughout his rebuttal
MR. RICHARDSON: Can you give us an example?
MR. WALKER: I don't think he needs an example
12 to answer a general question of what the acronym CPCN
13 stands for.
14 MR. RICHARDSON: So you don't know where in his
15 testimony you're referring?
16
17 testimony.
18
19
MR. WALKER: I'm referring to his rebuttal
MR. RICHARDSON: What page? What line?
MR. WALKER: That's not necessary.
20 COMMISSIONER KJELLANDER: Mr. Richardson and
21 counsel for Idaho Power, I feel comfortable enough that
22 the witness does have the ability to respond to a general
23 question about that acronym, and if he doesn't know, he
24 can say he doesn't know. Let's move on with this and if
25 the witness would respond one way or the other.
CSB REPORTING
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862 READING (X)
Simplot/Clearwater
1 THE WITNESS: I'm sure what I meant to say is
2 certificate of public convenience and necessity. Being
3 slightly dyslexic, it doesn't surprise me I would have
4 that mixed up.
5 Q. BY MR. WALKER: So can you tell us based on
6 your experience, including your work at the Public
7 Utilities Commission, what's the meaning of that
8 certificate of public convenience and necessity?
9 A. That means that the Commission approves the
10 building of a generation facility for the utility that is
11 applying for it.
12 Q. And is a CPCN required in Idaho in order for a
13 utility to build a generation resource?
14 MR. RICHARDSON: Mr. Chairman, he's calling for
15 a legal conclusion. Dr. Reading is not an attorney.
16 MR. WALKER: Dr. Reading is a former Staff
17 member of the Commission and I believe his experience, he
18 can speak to what a CPCN means and if it's required.
19 MR. RICHARDSON: It calls for a legal
20 conclusion, Mr. Chairman.
21 MR. WALKER: Actually, on page 8 of his
22 rebuttal testimony and page 9, he discusses the
23 requirements of a CPCN in relation to the Langley Gulch
24 generation plant, so I would like to explore his
25 understanding of that.
CSB REPORTING
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863 READING (X)
Simplot/Clearwater
1 COMMISSIONER KJELLANDER: As a recommendation,
2 why not refer directly to those lines and that page
3 number within the construction of your question and I
4 think you can probably get to where you want to go.
5 Q. BY MR. WALKER: Mr. Reading, on page 8 of your
6 rebuttal
7
8
9
MR. RICHARDSON: Dr. Reading, not mister.
MR. WALKER: He's not a mister?
COMMISSIONER KJELLANDER: Gentlemen, might I
10 just for purposes of trying to move forward, there
11 appears to be just a level of combativeness that perhaps
12 is unnecessary. We recognize that Dr. Reading has
13 wonderful credentials and not being impugned here. We're
14 simply getting to the bottom of this, so let's just move
15 forward and see if we can't get through this in a very
16 civil fashion.
17
18 Q.
MR. WALKER: Certainly.
BY MR. WALKER: On page 8, line 16 and line 19,
19 and page 9, lines 9 through 15, you have some discussion
20 about a CPCN, and an opinion that Idaho Power, line 18
21 through 19 on page 8, that Idaho Power would have
22 difficulty financing a project with a CPCN that expired
23 after five years, and my question was, is a CPCN required
24 for a utility to build a generation facility?
25 A. Just a moment. I would like to find that so I
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864 READING (X)
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1 can read what we're talking about. Would you give me the
2 references again?
3
4
5
Q.
A.
Q.
Page 8 of your rebuttal.
Okay. Okay, repeat the question.
Is a CPCN required in Idaho for a utility to
6 build a generation facility?
7 A. My understanding is that -- being a non-lawyer,
8 my understanding is that it is.
9 Q. And is a CPCN required before a utility is
10 required to purchase a QF's output?
11
12
A.
Q.
No.
And if a QF purchase had to meet the same
13 requirements as a utility to build a resource, would that
14 QF purchase be approved today under today's
15 circumstances?
16
19 is.
20
21
22
A.
Q.
A.
Q.
It would depend on what it is and what the
What if it was an 80 megawatt solar QF project?
Would it be approved by the Commission?
Well, let me rephrase in this manner: If the
18 without knowing specifically what kind of project it
17 price is and what the impact is. I can't answer that
23 1,336 megawatts of proposed QF solar were instead
24 proposed for construction by Idaho Power in a CPCN
25 proceeding, do you think that would be approved under
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1 today's circumstances?
2 A. I would doubt it. It would depend on what the
3 price is. It would depend on various things, but I will
4 add that, and I can't remember whether it's in my direct
5 or my rebuttal, during the Enron meltdown, the Commission
6 approved the Danskin project which a year before would
7 have never got approved. In that Order, the Commission
8 said that due to all of these unusual circumstances that
9 we'll waive the fact that it wasn't in the IRP and did
10 rapid approval, so your generic question is whether a
11 whole bunch of solar would be rubber-stamped and approved
12 through a certificate process, I would certainly doubt it
13 right now, but that doesn't mean that for whatever
14 reason, whether it leads back to Mr. Howell's discussion
15 of carbon, things often change and I certainly would
17 whatever size and was able to cost justify it, then the
16 believe that if Idaho Power proposed a solar project of
18 Commission would approve it.
MR. WALKER: I have no further questions. 19
20 COMMISSIONER KJELLANDER: Thank you. Let's
21 move now to Avista Corporation.
22 MR. ANDREA: No questions, Mr. Chairman.
23 COMMISSIONER KJELLANDER: Thank you.
24 PacifiCorp.
25 MS. HOGLE: PacifiCorp has no questions. Thank
CSB REPORTING
[phone]
866 READING (X)
Simplot/Clearwater
1 you.
2 COMMISSIONER KJELLANDER: Thank you. Let's
3 look to -- anything from the Idaho Conservation
4 League/Sierra Club?
5
6
MR. OTTO: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you, Mr. Otto.
7 Intermountain Energy Partners, Mr. Miller.
8
9
10
11
12
13
14
15
MR. MILLER: No, thank you.
COMMISSIONER KJELLANDER: Ms. Nunez.
MS. NUNEZ: No questions.
COMMISSIONER KJELLANDER: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Sanger.
MR. SANGER: No questions.
COMMISSIONER KJELLANDER: You're sort of hiding
16 out over there. Good to see you. Mr. Hammond.
17
18
19
20
MR. HAMMOND: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Arkoosh.
MR. ARKOOSH: No, Mr. Chairman, thank you.
COMMISSIONER KJELLANDER: Mr. Schmidt being new
21 to the process, do you want to weigh in?
22 MR. SCHMIDT: Boy, it's tempting, but I'll
23 pass. Thank you.
24 COMMISSIONER KJELLANDER: Fair enough. Are
25 there questions from the Commission?
CSB REPORTING
[phone]
867 READING (X)
Simplot/Clearwater
1
2
EXAMINATION
3 BY COMMISSIONER KJELLANDER:
4 Q. I just have a little bit before we get to
5 redirect and it's nothing heavy and if it's something
6 that you'd feel uncomfortable in responding to, just say
7 so and we'll stop, unless you say you're uncomfortable
8 with it before I ask. You've been around for a long
9 time. You've testified in front of us multiple times and
10 a lot of it tied to PURPA-related cases, and part of
11 where I'm going with this is that we've had one public
12 hearing and we've got another telephonic hearing coming
13 up this evening, and the general impression that we get
14 from a lot of people who testify publicly is that there's
15 a perception or at least the illusion of a perception,
16 perhaps my illusion of my interpretation of what they're
17 saying, is that there seems to be some underlying belief
18 that the only way renewables will be developed is through
19 PURPA. In your experience, are there other options that
20 a utility can utilize to develop renewable resources?
21
22
23
24
25
A.
Q.
A.
Q.
A.
Correct.
And among them there are RFPs?
Yeah, RFPs.
Self-builds?
Self-build, yes.
CSB REPORTING
[phone]
868 READING (Com)
Simplot/Clearwater
1 Q. And if you were to look down the road and
2 hearing your testimony earlier, there was some futuristic
3 projections of what you see happening, and one way or the
4 other I think we all probably come to a singular
5 conclusion that the likelihood of there being any new
6 coal-fired generators built is slim to none; would that
7 be your assessment?
8
9
A.
Q.
That would certainly be my assessment, yes.
So assuming that you and I are on the same page
10 with that, what are the next resources, then, that a
11 utility would look at, whether they're PURPA resources or
12 whether they're RFP resources? If they need to serve
13 future load, what are their options?
14 A. The current option of choice is gas plants,
15 because their emissions, their carbon emissions, are
16 about half of what a coal plant is, and I'll put a
17 footnote on that that, you know, the general assumption
18 is that gas is rock bottom and gas will always stay rock
19 bottom, and I have enough gray hair that once we all
20 agree that something is going to happen, that tells me
21 that that is not going to happen.
22 Q. Yeah, I have gray hair, too. I remember the 10
23 and $14.00 per megatherm prices.
24 A. Right, for instance, you know, fracking, I
25 wouldn't be shocked if we had a major problem with
CSB REPORTING
[phone]
869 READING (Com)
Simplot/Clearwater
1 tracking somewhere, whether it's earthquakes or fires or
2 whatever
3 Q. So if I could interrupt, then, we're probably
4 in agreement that natural gas is a resource that today
5 looks like the next viable resource, but the volatility
6 that we've seen in pricing could alter that, so what
7 else?
8 A. So then we do move to the "renewable
9 resources," such as wind and solar and biogas and those
10 kinds, so I think looking down the road, if I were to
11 forecast and knock on wood I'm going to be around to see
12 it, that the utility mix in the future for utilities
13 would be a much higher percentage of renewables and I
14 believe that whether Idaho Power ever -- I mean, the
15 State of Idaho ever gets RPS standards or not, that's
16 where the electric generation world is moving.
17 Q. So then if I could sum this up and you can
18 agree or disagree or add to it, regardless of whether
19 it's PURPA, an RFP or self-build, it's your perception
20 that renewables will be in Idaho Power's future, Rocky
21 Mountain Power's future, and Avista's future
22
23
24
A.
Q.
A.
Yes.
-- as it relates to serving future load?
Right, and I think specifically to the clients
25 that hired me for this case, I think CHP is going to
CSB REPORTING
[phone]
870 READING (Com)
Simplot/Clearwater
1 become even more important because of its use of already
2 generated it's so fuel efficient relative to a regular
3 gas plant or a coal plant.
4
5
COMMISSIONER KJELLANDER: Thank you. Redirect?
MR. RICHARDSON: Thank you, Mr. Chairman. I
6 have no redirect.
7 COMMISSIONER KJELLANDER: Thank you. Thank
8 you, Mr. Reading, always a pleasure to see you.
9 (The witness left the stand.)
10 COMMISSIONER KJELLANDER: Let's move now to
11 Staff for the Public Utilities Commission.
12 MS. HUANG: Thank you, Mr. Chairman. The Staff
13 would call Dr. Yao Yin.
14
15 YAO YIN,
16 produced as a witness at the instance of the Staff,
17 having been first duly sworn to tell the truth, the whole
18 truth, and nothing but the truth, was examined and
19 testified as follows:
20
21
22
23 BY MS. HUANG:
DIRECT EXAMINATION
24
25
Q.
A.
Good morning, Dr. Yin.
Good morning.
CSB REPORTING
[phone]
871 YIN (Di)
Staff
1 Q. Would you please state your full name and spell
2 your last name for the record?
3
4
A.
Q.
Yao Yin, Y-i-n.
By whom are you employed and in what
5 capacity?
6 A. I'm employed by the Idaho Public Utilities
7 Commission as a utilities analyst.
8 Q. Are you the same Yao Yin who filed direct
9 testimony in this matter on April 23rd, 2015?
10
11
A.
Q.
Yes, I am.
Do you have any changes you'd like to make to
12 your testimony, changes or corrections?
13 A. I do. On page 9 of my testimony, line 24, the
14 word "avoid" should be changed to "avoided."
15 Q. And do you have any other changes to your
16 testimony?
17
18
A.
Q.
I do not.
If I were to ask you those same questions that
19 are set forth in your direct testimony with that change,
20 would your answers be the same today?
21
22
A. Yes.
MS. HUANG: Mr. Chairman, I would move that Dr.
23 Yin's testimony be spread on the record.
24 COMMISSIONER KJELLANDER: And without
25 objection, we will spread the testimony of Dr. Yin across
CSB REPORTING
[phone]
872 YIN (Di)
Staff
1 the record as if read.
2 (The following prefiled testimony of Dr. Yao
3 Yin is spread upon the record.)
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
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21
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25
CSB REPORTING
[phone]
873 YIN (Di)
Staff
1 Q. Please state your name and business address for
2 the record.
3 A. My name is Yao Yin. My business address is 472
4 West Washington Street, Boise, Idaho.
5
6
Q.
A.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
7 Commission as a Utilities Analyst.
8 Q. What is your educational and professional
9 background?
10 A. I received a Bachelor of Science in Biological
11 Sciences from Shandong University in 2006. Later, I
12 earned a Master of Science in Molecular Cellular Biology
13 (2007), a Master of Public Policy in Environmental Policy
14 (2009), and a Ph.D. in Environmental Science (2011), all
15 from Oregon State University. I will be attending the
16 Practical Regulatory Training for the Electric Industry
17 Course held May 17-22, 2015 by the Center for Public
18 Utilities at New Mexico State University.
19 Prior to joining the Commission, I worked for
20 Energy Biosciences Institute at University of Illinois at
21 Urbana-Champaign as a Postdoctoral Research Associate.
22 Later, I worked for the Energy Policy Institute at Boise
23 State University as a Research Assistant Professor. I
24 joined the Commission in May 2014.
25 Q. What is the purpose of your testimony in this
IPC-E-15-01
4/23/15
874 YIN, Y. (Di) 1
STAFF
1 proceeding?
2 A. The purpose of my testimony is to review Rocky
3 Mountain Power's proposal to change its indicative
4 pricing practice in the Integrated Resource Planning
5 (IRP) methodology so that it may provide more accurate
6 avoided cost rates to proposed QF projects.
7
8
Q.
A.
What do you mean by "proposed QF projects"?
"Proposed QF projects" are projects for which a
9 QF developer has requested indicative avoided cost
10 prices, and is actively pursuing or negotiating a power
11 purchase agreement (PPA) with a utility.
12 Q. Do the "proposed QF projects" include QF
13 projects that are seeking SAR-based published rates?
14 A. No, not in the context of my testimony as
15 discussed here. SAR-based projects that are seeking
16 published rates (those that are smaller than the
17 published rate eligibility cap) may request the current
18 published rates approved by the Commission.
19 Q. Are you proposing changes to the Integrated
20 Resource Planning process?
21 A. No. SAR-based projects, IRP-based projects,
22 and other long-term non-PURPA contracts will continue to
23 be included in the IRP planning process as contracts are
24 signed.
25 My testimony addresses a change to the practice
IPC-E-15-01
4/23/15
875 YIN, Y. (Di) 2
STAFF
1 of giving indicative pricing to proposed QF project that
2 are negotiating IRP-based avoided cost rates as part of
3 the IRP methodology.
4 Q. Does the term "proposed QF project" refer to
5 projects that make general inquiries about procedures for
6 obtaining a PURPA contract?
7 A. No. Typically, a QF is considered a proposed
8 QF when it is seriously pursuing a power purchase
9 agreement (PPA) and makes it to the stage of requesting
10 indicative avoided cost prices. Projects at earlier
11 stages, such as the general inquiry stage, are typically
12 not considered as proposed projects.
13
14
Q.
A.
What are indicative prices?
Indicative prices are preliminary estimates of
15 avoided cost rates which serve as the starting point for
16 negotiations between QFs and a utility. They may differ
17 from the final prices in a contract (i.e., contract
18 prices).
19 Q. What do QF projects need to do before
20 requesting indicative prices from a utility?
21 A. Idaho Power's Schedule 73 and Avista's Schedule
22 62 specify the information a project needs to submit
23 before requesting indicative prices. Rocky Mountain
24 Power does not have a similar schedule in Idaho, although
25 I recommend it propose one so that QF projects can have a
IPC-E-15-01
4/23/15
876 YIN, Y. (Di) 3
STAFF
1 better idea of the procedures for requesting indicative
2 prices in Idaho.
3 Q. Please describe the current indicative pricing
4 practice approved by the Commission.
5 A. Currently, proposed projects are not placed in
6 a queue but are instead treated for pricing purposes as
7 if they are all the first project to receive the next
8 indicative prices. In other words, the first proposed
9 project, the second proposed project, the third proposed
10 project ... will all be treated the same as the first
11 project for purposes of receiving indicative pricing.
12 The indicative prices, however, can be
13 recalculated (before they become contract prices) if an
14 earlier contract is signed, or if a signed contract is
15 removed.
16 Q. Which Commission Order approved of this
17 practice?
18 A. In Case No. GNR-E-11-03, the Commission stated
19 that "long-term contracts shall be considered in IRP
20 Methodology calculations at such time as the utility and
21 QF have entered into a signed contract for the sale and
22 purchase of QF power." Order No. 32697 at 22. (Emphasis
23 added) .
24 Q. Are there practical concerns with this
25 practice?
A. Theoretically, this practice may result in
IPC-E-15-01
4/23/15
877 YIN, Y. (Di) 4
STAFF
1 accurate avoided cost rates by allowing indicative prices
2 to be recalculated when an earlier contract is signed.
3 In reality, however, it can be very difficult to
4 recalculate rates for proposed projects in a timely
5 manner when there are many projects seeking indicative
6 prices at the same time. As Rocky Mountain stated on
7 page 7 of its Petition in this case (PAC-E-15-03), "the
8 currently approved requirement that the Company's avoided
9 cost rate modeling can only be updated to account for
10 signed QF contract[s] will result in PURPA [contracts]
11 based on indicative pricing that becomes inaccurate
12 " The inability to update indicative pricing
13 "will result in payments to QFs that exceed avoided costs
14 " (Rocky Mountain Petition at 33.)
15 In addition, a QF may not want to re-negotiate
16 the new updated rates, because the new indicative prices
17 may be lower than the original ones. New indicative
18 prices may be lower because, under the !RP methodology,
19 each successive QF displaces lower-cost resources in the
20 utility's dispatch stack.
21 Q. Why were these concerns not much of an issue in
22 the past?
23 A. The current indicative pricing practice works
24 well when individual project sizes are small, cumulative
25 project sizes are small, and multiple projects are not
IPC-E-15-01
4/23/15
878 YIN, Y. (Di) 5
STAFF
1 being proposed at about the same time, because the
2 resulting indicative prices are accurate and rarely need
3 to be recalculated. Today, however, PURPA project sizes
4 are much larger, both individually and cumulatively, and
5 multiple projects frequently seek indicative prices at
6 the same time. Under this circumstance, the sequence of
7 projects, which determines every project's avoided cost
8 rates, needs to be established to reflect how each
9 project actually displaces the utility's resources and
10 contributes to the utility's capacity. Unless indicative
11 pricing is able to reflect the actual impacts of each
12 project, inaccurate avoided cost rates may result.
13 Q. Please describe the new indicative pricing
14 practice proposed by Rocky Mountain.
15 A. The new indicative pricing practice would offer
16 more accurate indicative prices to QFs by putting all the
17 proposed projects into a queue based on the times they
18 request indicative prices. As Rocky Mountain describes
19 the proposed change on page 38 of its Petition, the
20 proposed modified indicative pricing practice "reflects
21 all active QF projects in the pricing queue ahead of any
22 newly proposed QF requests for indicative pricing."
23 Q. Are there advantages to the newly proposed
24 practice?
25 A. Yes. When all proposed projects are placed in
IPC-E-15-01
4/23/15
879 YIN, Y. (Di) 6
STAFF
1 a queue, rather than being treated as the first project,
2 each project will receive different indicative pricing,
3 depending on its position in the queue. Generally, the
4 higher the position in the queue, the higher the avoided
5 cost rates. Using a queue will allow indicative pricing
6 to reflect how each project actually displaces the
7 utility's resources and contributes to the utility's
8 capacity at the start of the negotiation process.
9 Q. Can you give an example to show how the new
10 indicative pricing practice would impact contract prices?
11 A. Rocky Mountain witness Dickman provides an
12 example on page 10 of his direct testimony. There he
13 states "[t]he Company calculated the impact on the IRP
14 Method avoided costs of including roughly 3,000 MW of
15 proposed QFs [generation] (located in Idaho, Utah,
16 Wyoming, Oregon) prior to the next Idaho QF. Accounting
17 for these proposed QFs rather than just those QFs with
18 signed contracts reduces avoided costs for the next Idaho
19 QF in the pricing queue by approximately $18 per MWh on a
20 20-year levelized basis 11
21 If proposed projects are not placed in a queue,
22 there could be substantial overpayments in avoided cost
23 rates to the QFs.
24 Q. Indicative pricing using this methodology
25 assumes that the proposed projects will be built
IPC-E-15-01
4/23/15
880 YIN, Y. (Di) 7
STAFF
1 eventually, but what if a proposed project drops out of
2 the queue?
3 A. If projects drop out of the queue, utilities
4 will recalculate the indicative prices for projects
5 succeeding the dropped one, and the parties would
6 negotiate based on the new rates. Obviously, the new
7 rates will be higher than the original rates, because all
8 the projects that are situated lower in the queue will be
9 bumped up to displace higher-cost resources and have
10 better opportunity to contribute to the utility's
11 capacity need. Because the remaining projects will
12 receive higher avoided cost rates, they will financially
13 benefit and should readily accept the new, higher rates.
14 Q. Under the proposed indicative pricing practice,
15 is it likely that in order to get higher indicative
16 prices, projects will try to request indicative prices as
17 soon as possible to save an earlier spot in the queue
18 even if QFs are not ready to seriously negotiate an
19 IRP-based PURPA contract?
20 A. Both Idaho Power's Schedule 73 and Avista's
21 Schedule 62 require projects to provide specific
22 information about each project before the utilities
23 provide indicative pricing. Also, the schedules specify
24 timeline milestones for QFs to meet as projects and
25 negotiations progress.
IPC-E-15-01
4/23/15
881 YIN, Y. (Di) 8
STAFF
1 Staff recorrunends that Rocky Mountain should
2 file a similar tariff schedule to lay out the PURPA
3 negotiating process and prevent projects from prematurely
4 requesting indicative pricing.
5 Q. If a QF changes significant details about its
6 project, will the QF remain in the queue?
7 A. Yes, but not in the same queue position. Rocky
8 Mountain Power states in its response to Staff's first
9 production request that "if the QF changes significant
10 details about the project (such as site location, online
11 date, or project size), the QF is removed from the queue
12 and then re-enters the queue at the bottom as a new
13 request with the new project description." I agree with
14 Rocky Mountain's approach, but believe specific criteria
15 may need to be developed for management of the queue,
16 such as rules for QF entry, re-positioning, and removal
17 from the queue.
18 Q. What is your recorrunendation regarding Rocky
19 Mountain's request to change its indicative pricing
20 practice?
21 A. I recorrunend that the indicative pricing
22 practice provided to proposed QF projects be updated to
23 place all the proposed projects in a queue, thereby
24 providing more accurate and up-to-date avoided costs.
25 The Corrunission should discontinue the "signed contract"
IPC-E-15-01
4/23/15
882 YIN, Y. (Di) 9
STAFF
1 requirement in Order No. 32697 for purposes of giving
2 indicative pricing to IRP-base projects. Finally, Rocky
3 Mountain should be directed to file a tariff schedule
4 outlining its PURPA contracting procedures in Idaho.
5 Q. Does this conclude your direct testimony in
6 this proceeding?
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
A. Yes, it does.
IPC-E-15-01
4/23/15
883 YIN, Y. (Di) 10
STAFF
1 (The following proceedings were had in
2 open hearing.)
3 MS. HUANG: Thank you, Mr. Chair. Dr. Yin is
4 now available for cross-examination.
5 COMMISSIONER KJELLANDER: Let's just move down
6 the list and keep it simple for me. Idaho Power.
7
8
9
10
11
12
13
14
15
16
17
18
MR. WALKER: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Avista.
MR. ANDREA: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: PacifiCorp.
MS. HOGLE: No questions, thank you.
COMMISSIONER KJELLANDER: And Mr. Adams.
MR. ADAMS: No questions from Simplot.
COMMISSIONER KJELLANDER: Mr. Richardson.
MR. RICHARDSON: Just one, Mr. Chairman.
CROSS-EXAMINATION
19 BY MR. RICHARDSON:
20 Q. Dr. Yin, on page 8 of your direct testimony on
21 line 3, you talk about projects dropping out of the
22 queue?
23
24
A.
Q.
Yes.
Do you have any proposal or system in mind for
25 how projects are dropped out of the queue?
CSB REPORTING
[phone]
884 YIN (X)
Staff
�--
1
2
A.
Q.
How they drop out of the queue?
Right, because it seems to me that you could
3 accumulate projects that are not serious projects in the
4 queue that a utility might leave in the queue in order to
5 artificially lower the avoided cost rate, so is there
6 some sort of system for dropping projects out of the
7 queue you had in mind?
8 A. I think right now we don't have specific rules
9 for queue management and I think the utilities should
10 come up with specific management rules to deal with
11 situations like dropping out, repositioning, reentering
12 into the queue, or removal from the queue. I think we
13 should in the near future develop specific rules.
14 Q. And I think you testified that PacifiCorp does
15 not have a tariff on file in Idaho. What is your
16 recommendation for PacifiCorp in terms of filing a tariff
17 for setting the procedures for QFs to get in the queue
18 and fall out of the queue or whatever?
19 A. Two points. I think, first of all, PacifiCorp
20 should file a similar tariff schedule similar to Idaho
21 Power's Schedule 73 and Avista's 62 to specify the
22 specific procedures for the QF to be able to request
23 indicative prices and also as to the specific rules for
24 queue management. I think it's a different order or
25 different issue so that I don't envision two things
CSB REPORTING
[phone]
885 YIN {X)
Staff
1 combined in the same order.
2 Q. And do you recall in the last generic avoided
3 cost case, this Commission ordered all the three
4 utilities to file such a tariff?
5
6
A.
Q.
Say your question again.
Do you recall that in the last generic avoided
7 cost docket, this Commission ordered all three utilities
8 to file a queue management tariff?
9
10
11
A. I don't think I was hired.
MR. RICHARDSON: Okay, thank you.
COMMISSIONER KJELLANDER: The other response is
12 it's beyond my pay grade, they both work. Let's see, who
13 is next? Mr. Otto.
14
15
16
17 or two.
18
19
20
MR. OTTO: No questions, Mr. Commissioner.
COMMISSIONER KJELLANDER: Mr. Miller.
MR. MILLER: Thank you, Mr. Chairman, just one
CROSS-EXAMINATION
21 BY MR. MILLER:
22
23
24
Q.
A.
Q.
Good morning, Doctor.
Good morning.
Welcome to the world of public utility
25 testifying.
CSB REPORTING
[phone]
886 YIN (X)
Staff
1
2
A.
Q.
Thank you.
I hope it's not a too burdensome experience for
3 you. I always say it's no worse than your standard root
4 canal, right. I just have one question on page 9 of your
5 testimony.
6
7
A.
Q.
Okay.
At the very bottom on the last two lines, you
8 suggest that the Commission discontinue the signed
9 contract requirement for purposes of giving indicative
10 pricing. Are you recommending that with respect to the
11 Idaho Power method of computing or providing indicative
12 pricing or just PacifiCorp?
13 A. The proposal that PacifiCorp is proposing is
14 the queuing methodology and Idaho Power has adopted it in
15 the 13 solar parties.
16 Q. Currently the Idaho Power methodology is based
17 on signed contracts; right?
18 A. No. It's based on PacifiCorp's methodology
19 that it is proposing.
20
21
Q.
A.
I'm sorry, I couldn't quite hear you.
Idaho Power has already applied the method
22 PacifiCorp is proposing.
23
24
Q.
A.
And it uses a signed contract?
No, PacifiCorp is proposing the queued
25 methodology, the queuing.
CSB REPORTING
[phone]
887 YIN (X)
Staff
12 in Case GNR-E-11-03.
2 the Idaho Power methodology as you understand it?
5 contract requirement is not intended to modify the
YIN (X)
Staff
888
MR. MILLER: All right, I think that clarifies
With respect to Idaho Power?
With respect to Idaho Power, Idaho Power has
Uh-huh.
Is that what you're saying?
Right. That's the methodology in the Order and
So is it your understanding that Idaho Power
Your proposal here to eliminate the signed
Define "existing Idaho Power methodology." Can
Can you say the question again?
Correct.
Give me a second here. Going back to page 4 of
So you're not proposing, then, any change to
A.
A.
A.
Q.
A.
A.
Q.
Q.
Q.
Q.
A.
Q.
projects.
CSB REPORTING
[phone]
4
7
3
1
9 please?
6 existing Idaho Power methodology?
8 you define the existing Idaho Power's methodology for me,
13
18
19
17 already adopted this methodology in their 13 solar
16
10
20 has already moved away from signed contracts?
21
11 your testimony, you reference the Commission Order 32697
22
23
15
24
25 it in my mind, I think.
14 I'm proposing we should change that methodology.
1
2
3
5
6
7 Olsen.
8
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15
16
17
THE WITNESS: Thank you.
MR. MILLER: That's all I have.
COMMISSIONER KJELLANDER: Thank you,
MS. NUNEZ: No questions. Thank you.
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. OLSEN: No questions.
COMMISSIONER KJELLANDER: Mr. Sanger.
MR. SANGER: No questions.
COMMISSIONER KJELLANDER: Mr. Hammond.
MR. HAMMOND: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Arkoosh.
MR. ARKOOSH: No, thank you, Mr. Chairman.
COMMISSIONER KJELLANDER: And Mr. Schmidt.
MR. SCHMIDT: No, thank you.
COMMISSIONER KJELLANDER: Any questions from
4 Mr. Miller. Ms. Nunez.
18 members of the Commission? Well, you've been baptized.
19 You are now are officially a witness at the PUC.
20 Oh, I'm sorry, redirect. One chance for your
21 worst enemy, your own attorney, to ruin your day.
22
23
24
25
THE WITNESS: Okay.
MS. HUANG: No redirect, thank you.
COMMISSIONER KJELLANDER: You got off easy.
THE WITNESS: Thank you.
CSB REPORTING
[phone]
889 YIN (X)
Staff
1
2
(The witness left the stand.)
COMMISSIONER KJELLANDER: All right, Staff
3 would call their final witness.
4 MR. HOWELL: Thank you, Mr. Chairman. We would
5 call Rick Sterling to the stand.
6
7 RICK STERLING,
8 produced as a witness at the instance of the Staff,
9 having been first duly sworn to tell the truth, the whole
10 truth, and nothing but the truth, was examined and
11 testified as follows:
12
13
14
15 BY MR. HOWELL:
DIRECT EXAMINATION
16
17
18
19
20
Q. Could you state your name and spell your last
for the record, please?
A. My,name is Rick Sterling, S-t-e-r-1-i-n-g.
Q. And Mr. Sterling, whom are you employed by and
in what capacity?
21 A. I'm employed by the Idaho Public Utilities
22 Commission as an engineering supervisor.
23 Q. Are you the same Rick Sterling that filed
24 direct testimony dated April 23rd and rebuttal testimony
25 dated May 14th in this matter?
CSB REPORTING
[phone]
890 STERLING (Di)
Staff
24
18 marked for identification.
6 Staff Exhibit 101?
STERLING (Di)
Staff
891
Do you have any changes or corrections to
Do you have any changes or corrections to the
No, I do not.
Yes, I am.
I am.
Yes, they would.
No.
And if I were to ask you the questions set out
Are you also the same person that prepared
MR. HOWELL: With that, Mr. Chairman, I would
COMMISSIONER KJELLANDER: And without
A.
A.
A.
A.
A.
Q.
Q.
Q.
Q.
CSB REPORTING
[phone]
4
7
8
2
5
1
9 exhibit?
3 either your direct or rebuttal testimony?
12 in your direct and rebuttal testimony, would your answers
10
17 spread upon the record as if read and his Exhibit 101 be
14
13 be the same today?
15
16 move that Mr. Sterling's direct and rebuttal testimony be
11
19
21 (The following prefiled direct and rebuttal
22 testimony of Mr. Rick Sterling is spread upon the
20 objection, so ordered.
25
23 record.)
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
6
Q.
A.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
7 Commission as the Engineering Supervisor.
8 Q. What is your educational and professional
9 background?
10 A. I received a Bachelor of Science degree in
11 Civil Engineering from the University of Idaho in 1981
12 and a Master of Science degree in Civil Engineering from
13 the University of Idaho in 1983. I worked for the Idaho
14 Department of Water Resources Energy Division from 1983
15 to 1994. In 1988, I became licensed in Idaho as a
16 registered professional Civil Engineer. I began working
17 at the Idaho Public Utilities Commission in 1994. My
18 duties at the Commission include analysis of a wide
19 variety of electric and large water utility applications.
20 I have been the lead staff member on all Public Utility
21 Regulatory Policies Act (PURPA) dockets at the Commission
22 since 1994. In addition, I lead the Engineering Section
23 and supervise a staff of engineers and utility analysts.
24 Q. What is the purpose of your testimony in this
25 proceeding?
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STAFF
1 A. The purpose of my testimony is to address the
2 petition of Idaho Power to reduce the maximum contract
3 length for !RP-based (Integrated Resource Plan) PURPA
4 contracts from the current 20 years to two years. I will
5 also address similar requests by Avista and PacifiCorp
6 for reduced contract lengths. In addition, I will make
7 recommendations for maximum contract length for SAR-based
8 (Surrogate Avoided Resource) PURPA contracts, including
9 replacement contracts.
10 Q. What do you believe is the real issue that
11 needs to be addressed in this case?
12 A. I believe the real issue is the risk exposure
13 to ratepayers that can occur due to long-term PURPA
14 contracts. Long-term contracts, by themselves, would not
15 necessarily be problematic if the long-term avoided cost
16 rates contained in those contracts fairly represented
17 avoided costs over the entire duration of the contract.
18 Unfortunately, however, I do not believe any avoided cost
19 calculation can prove to remain accurate over a 20-year
20 period. Absent any mechanism to periodically adjust
21 avoided cost rates throughout the term of the contract,
22 shorter contract lengths appear to be one of the only
23 viable and effective ways to reduce the risk exposure to
24 ratepayers.
25 Q. Why don't you believe avoided cost calculations
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STAFF
1 can prove to remain accurate over a 20-year period?
2 A. Under the IRP method, avoided cost rates are
3 computed, in large part, using an hourly dispatch model
4 that dispatches generation to meet load in each hour at
5 the lowest possible cost. The dispatch models require
6 extensive information about each of the generation
7 plants, typically throughout the western U.S., as well as
8 long-term forecasts of loads and fuel prices. While
9 forecasts can be prepared and assumptions can be made
10 easily enough, it is extremely unlikely that those
11 forecasts and assumptions will remain accurate over a
12 long period of time. Consequently, it is equally
13 unlikely that the avoided cost rates that emerge from the
14 dispatch models will remain accurate. It is possible
15 that the avoided cost rates will be too high at some
16 times and too low at other times. It is also possible,
17 however, that the avoided cost rates will be too high or
18 too low throughout the entire contract length.
19 Regardless of whether the avoided cost rates are too high
20 or too low, 100 percent of the risk of actual prices
21 deviating from forecasted avoided cost rates is borne by
22 ratepayers and none of the risk is borne by QFs.
23 Q. Has the Commission Staff taken a position
24 recently on maximum contract length for PURPA contracts?
25 A. Yes, in Case No. GNR-E-11-03, I recommended
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894 STERLING, R. (Di) 3
STAFF
1 that the Cornrnission reduce maximum contract length to
2 five years for contracts containing rates computed under
3 the !RP methodology. This recommendation supported Idaho
4 Power's request in that case.
5
6
Q.
A.
Did the Cornrnission accept your recornrnendation?
No, the Cornrnission did not. The Cornrnission
7 stated the following in Order No. 32697:
8 We find that a 20-year contract length, along with
other factors, has been beneficial in encouraging
9 PURPA development in Idaho. We continue to believe
that 20-year contracts better coincide with the
10 useful life of the renewable/cogeneration resources.
While it is not this Cornrnission's responsibility to
11 ensure a contract length that allows a QF to obtain
financing, we find that reducing maximum contract
12 length to five years would unduly hinder PURPA
development. That is not the Cornrnission's
13 objective. We believe that, by utilizing other
tools to ensure an accurate and up-to-date avoided
14 cost valuation, we can continue to encourage the
types of projects that were envisioned by PURPA
15 while maintaining the transparency for ratepayers as
PURPA requires. Therefore, we find that a maximum
16 contract length of 20 years is appropriate. The
parties to a power purchase agreement are free to
17 negotiate a shorter contract if that would be most
suitable for the project. As in the past, this
18 Cornrnission will consider contracts of more than 20
years on a case-by-case basis.
19
20 Q. The passage from Order No. 32697 you have
21 quoted above reflects the Commission's position less
22 than two and a half years ago. Why do you believe
23 the Cornrnission should consider a different position
24 today?
25 A. In the short two and a half years since the
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STAFF
1 Order was issued, Idaho Power has signed agreements for
2 461 MW of new solar generation,! and, as stated in its
3 Petition, has received pricing requests for 885 MW of
4 additional solar generation. In response to Staff
5 production requests, Idaho Power states that it has
6 received additional requests for solar contracts of
7 approximately 120 MW since the filing of this case on
8 January 30, 2015. PacifiCorp has received pricing
9 requests for 275.5 MW of new solar generation according
10 to its Petition. Contrary to what was contemplated in
11 the Order, it would not appear that PURPA development
12 needs further encouragement at this time.
13 Order No. 32697 suggested that other tools
14 should be used to ensure accurate and up to date avoided
15 cost rates, but I believe there are now few other tools
16 available. Avoided cost rates can be calculated
17 accurately at the beginning of a contract term, but no
18 matter how accurate they may be to start, they are bound
19 to become inaccurate over a 20-year period for a long
20 term contract.
21 Q. Is the significant increase in the cumulative
22 amount of PURPA power a recent phenomenon?
23
24 1 The Commission was recently informed by Idaho Power
that four solar contracts representing 141 MW have been
25 terminated for failure to post security.
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896 STERLING, R. (Di) 5
STAFF
1 A. Yes, as shown in Idaho Power's Exhibit No. 1,
2 the total amount of PURPA power began its significant
3 increase from 216 MW in 2008, to an estimate of 2187 MW
4 in 2018.2 From 1982 to about 2007, Idaho Power had less
5 than 200 MW of PURPA generation, primarily hydro. For
6 approximately the first 25 years, the average size of
7 PURPA projects was only about 2.5 MW.
8 Q. Has the Commission ever before limited
9 contracts to five years or less?
10 A. Yes, it has. The Commission's policy with
11 regard to contract length has evolved over the years.
12 From 1980 when PURPA was first implemented in Idaho,
13 through 1987, utilities were obligated to offer QFs up to
14 35-year contracts. The reason for the 35-year maximum
15 contract length was that 35 years was the amortization
16 period allowed for similar utility-owned facilities. A
17 contract length that matched the project's amortization
18 schedule made financing easier, and in effect, helped
19 encourage QF development.
20 In 1987 (See Case No. U-1500-170, Order No.
21 21630) the Commission shortened the standard contract
22
23 2 Note that the total estimate for 2018 includes 885 of
proposed contracts. In addition, it includes 461 MW of
24 signed contracts. The Commission was recently notified
that 141 MW of signed contracts have defaulted, and the
25 contracts have been terminated.
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897 STERLING, R. (Di) 6
STAFF
1 length to 20 years reasoning that risk and uncertainty
2 inherent in long-range forecasting increases dramatically
3 with time and that a shorter contract term would reduce
4 that risk. The Commission ruled that contracts longer
5 than 20 years would be available to QFs only upon a
6 persuasive showing of need.
7 Nine years later, in 1996, the Commission again
8 reexamined the issue of contract length. In Order No.
9 26576 in Case No. IPC-E-95-9, the Commission further
10 shortened the maximum required contract length from 20
11 years to five years for projects 1 MW and larger. In
12 1997, the Commission extended the five-year contract
13 length limitation established for large QFs to smaller
14 than 1 MW QFs as well. (See Case No. IPC-E-97-9, Order
15 No. 27111)
16 In 2002, the Commission increased maximum
17 contract length from 5 years back to 20 years. The
18 Commission explained that when it earlier had reduced
19 maximum contract length to five years, there was an
20 expectation of widespread deregulation, more competitive
21 markets, and greater reliance on short-term market
22 purchases. However, by 2002, the Commission recognized
23 that each of Idaho's regulated electric utilities were
24 constructing or had recently constructed long-term new
25 generation resources. In restoring 20 years as the
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898 STERLING, R. (Di) 7
STAFF
1 maximum contract length, the Commission reasoned that a
2 longer contract better coincides with the planned
3 resource life of renewable or cogeneration resources
4 being offered, better reflects the amortization period of
5 generation projects constructed by the utilities
6 themselves and will coincidentally provide a revenue
7 stream that will facilitate the financing of QF projects.
9 Q. During the approximately five and a half year
8 (See Order No. 29029)
10 period when contract length was limited to five years
11 (September, 1996 through May, 2002), weren't very few
12 PURPA contracts signed?
13 A. Yes, there was only one PURPA contract signed
14 in Idaho during this time frame. However, at the time,
15 the eligibility threshold for published rates was also
16 limited to facilities one megawatt or smaller. In
17 addition, published rates were also quite low at this
18 time, primarily due to low natural gas prices.
19 Furthermore, most PURPA hydro and cogeneration projects
20 had already been developed, while wind, solar and biogas
21 technology had yet to fully develop. The combination of
22 all of these factors, not shortened contract length
23 alone, caused very few PURPA projects to be developed in
24 Idaho during this time period.
25 Q. But won't a five-year limit on maximum contract
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899 STERLING, R. (Di) 8
STAFF
1 length, if approved, limit the ability of projects to
2 obtain financing, thus making extensive project
3 development unlikely?
4 A. Yes, I agree that development would likely slow
5 considerably, at least under PURPA. However, facilities
6 could still be developed under other mechanisms. For
7 example, if a utility identified a need in its IRP and if
8 certain renewables or cogeneration possessed the
9 characteristics and costs making it part of a preferred
10 portfolio, then the utility could acquire renewables or
11 cogeneration with long-term contracts in response to
12 utility requests for proposal. This was the mechanism
13 employed by Idaho Power in signing power purchase
14 agreements (PPAs) with the Neal Hot Springs and Raft
15 River geothermal projects (35 MW), and the Elkhorn wind
16 project (101 MW). Similarly, Avista secured a PPA for
17 the Palouse wind project in the same way. Finally,
18 PacifiCorp has either signed multiple PPAs or acquired
19 ownership of wind projects in the same manner.
20 QFs could also sell their output to other
21 utilities outside of Idaho, just as some out of state
22 projects currently sell their output to Idaho utilities.
23 In addition, projects could be developed in Idaho and
24 sell their output to out of state buyers, not as QFs
25 under PURPA, but as Exempt Wholesale Generators. At
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900 STERLING, R. (Di) 9
STAFF
1 least one large wind project in eastern Idaho sells its
2 output to Southern California Edison in this fashion. In
3 fact, this is a very common mechanism for project
4 development throughout other parts of the country.
5 Alternatively, projects could also sign PURPA
6 contracts and replace them every five years (or whatever
7 maximum contract length the Commission decides) as long
8 as PURPA remains in effect.
9 Q. Do you believe that the Commission should
10 shoulder some responsibility for ensuring contract
11 lengths are long enough to enable QFs to obtain
12 financing?
13 A. No, not necessarily. Where the Commission
14 desires to boost development of PURPA projects, long-term
15 contracts may accomplish that goal. However, currently,
16 Idaho utilities, particularly Idaho Power, are being
17 inundated with more projects than they need or can
18 accommodate. In Order No. 32697, the Commission stated
19 that it is not the Commission's responsibility to ensure
20 contracts are long enough to enable projects to obtain
21 financing. Because the Commission must also regulate the
22 reasonableness of customer rates and the reliability of
23 power, it is ultimately a matter of policy-how the
24 Commission wishes to weigh its various considerations.
25 Q. Is a 20-year maximum contract length
inconsistent with PURPA's objectives?
L
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901 STERLING, R. (Di) 10
STAFF
1 A. Yes, it can be. One of the Commission's
2 primary duties under PURPA is to set avoided cost rates
3 that are just and reasonable to customers, in the public
4 interest, and not discriminatory to QFs. Such rates must
5 not exceed incremental costs to the utility. The concern
6 arises when contracts extend for many years and the
7 forecast of avoided cost becomes inaccurate. Long-term
8 contracts based on forecasted rates create greater risks
9 for customers because the rates in the later years are
10 not reflective of avoided costs.
11 Q. Are there any specific requirements under PURPA
12 regarding contract length?
13 A. No, FERC's regulations implementing PURPA are
14 silent on contract length. Furthermore, I am not aware
15 of any FERC case or court decision involving a
16 requirement for a minimum contract length.
17 However, FERC rules do appear to contemplate
18 less than 20 year contracts. Section 292.302 of the FERC
19 rules implementing PURPA, requires utilities to make
20 available information from which avoided costs may be
21 derived. For energy, utilities are required to estimate
22 the energy component of avoided costs by year for the
23 current year and each of the next five years. For
24 capacity, the utility must make available its plan for
25 the addition of capacity by amount and type, for
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902 STERLING, R. (Di) 11
STAFF
1 purchases of firm energy and capacity, and for capacity
2 retirements for each year during the succeeding 10 years.
3 Thus, these component forecasts are much less than the
4 20-year contract.
5 In Idaho, utilities do not actually submit such
6 information to the Commission because FERC rules permit
7 states to require different information for deriving
8 avoided costs. Nonetheless, I think the mere mention of
9 five year estimates for energy and 10 years for capacity
10 suggests 20 year maximum contract lengths are not
11 necessarily expected.
12 Q. Are there other reasons why you believe that
13 maximum contract length should be shortened to five
14 years?
15 A. Yes, there are. When the surrogate avoided
16 resource (SAR) was changed from a coal-fired resource to
17 a gas-fired resource in 1995, fuel became a much larger
18 portion of the avoided cost rate. By comparison, fuel is
19 a far more substantial portion of costs for a gas-fired
20 resource than for a coal-fired resource. In fact, for
21 the gas-fired combined cycle combustion turbine (CCCT)
22 now used as the SAR, fuel represents approximately two
23 thirds of the project costs. The fuel component of costs
24 must be estimated based on 20-year forecasts. As history
25 has demonstrated, it can be extremely difficult to
IPC-E-15-01
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903 STERLING, R. (Di) 12
STAFF
1 accurately forecast gas prices just a few years into the
2 future, let
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904 STERLING, R. (Di) 12a
STAFF
1 alone 20 years into the future. Similarly, under the IRP
2 methodology, much of the cost upon which PURPA rates are
3 based is driven by fuel prices. Gas-fired generation is
4 on the margin much of the hours of the year;
5 consequently, electric market prices are frequently
6 closely tied to natural gas prices. A five year contract
7 allows contract rates to be adjusted regularly to more
8 accurately reflect current fuel prices.
9 Moreover, a fixed price contract is more risky
10 than one in which prices are adjusted frequently. A
11 long-term fixed price could possibly be accurate just
12 once during its term - at the beginning of the contract
13 when the rates are first established. The shorter the
14 term of the contract, the more frequently prices can be
15 adjusted to ensure they accurately represent the true
16 value of the power. A shorter term contract helps to
17 minimize risk to ratepayers.
18 Q. Some people have argued over the years that
19 PURPA projects, because the prices are established at the
20 start of the contract term and are fixed for the 20 years
21 of the contract, present little or no fuel-price risk
22 compared to gas-fired generation acquired by utilities.
23 Do you agree?
24 A. No, I do not. Although there may be no price
25 uncertainty associated with long-term PURPA contracts,
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905 STERLING, R. (Di) 13
STAFF
1 that is not the same as having no price risk. Prices
2 established at the start of a long-term contract could
3 prove to be too high or too low compared to other
4 alternatives or to market prices in effect throughout the
5 term of the contract. A long-term contract locks in
6 those prices, regardless of what happens with market
7 prices. Because 100 percent of PURPA costs are passed on
8 to customers through PCAs, ratepayers are fully exposed
9 to the risk that PURPA rates prove to be too high.
10 Fuel costs associated with utility-owned
11 resources are also passed on to customers, partly through
12 base rates and partly through PCAs. However, fuel costs
13 are tracked annually and rates are adjusted accordingly.
14 Consequently, while customers are exposed to fuel price
15 risk for both PURPA and utility-owned resources, the
16 annual adjustment of rates for utility-owned resources
17 exposes customers to less risk for utility-owned
18 resources than for PURPA resources.
19 Q. You stated earlier that ratepayers bear 100
20 percent of the risk when prices in PURPA contracts
21 deviate from actual values of the power over the life of
22 the contract. Why shouldn't ratepayers bear 100 percent
23 of the risk? Don't they bear 100 percent of the risk for
24 utility-owned resources?
25 A. Ratepayers do bear nearly all of the risk of
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906 STERLING, R. (Di) 14
STAFF
1 utility-owned resources, except for relatively small
2 portions that may be borne by the utilities through cost
3 sharing mechanisms built into PCAs. However, because of
4 the annual power cost adjustment mechanisms, the risk for
5 utility-owned resources is less. In other words, the
6 annual adjustment allows costs to be bracketed more
7 accurately.
8 PURPA resources, on the other hand, receive
9 revenue at fixed rates over long contract terms. I can
10 think of few investments made by private investors in
11 which the rates are fixed and the entire revenue is
12 guaranteed for 20 year periods. Private businesses must
13 almost always make their own assessment of the risks and
14 rewards for new long term investments. I don't think it
15 should be much different when private businesses invest
16 in PURPA projects.
17 Q. Do you agree that a long-term PURPA contract
18 provides long-term price protection, or a "hedge" against
19 high prices that can benefit ratepayers?
20 A. It is certainly possible that this could occur,
21 but it is also possible that long-term price certainty
22 could lock in high prices to the detriment of ratepayers.
23 As I stated, price certainty and price protection are not
24 necessarily the same thing.
25 Q. Do you support Idaho Power's request to limit
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1 contract length under the IRP methodology to two years or
2 PacifiCorp's request to limit it to three years?
3 A. Although I agree with all three utilities'
5 I think it could potentially be so short that QFs who did
4 rationale for two or three year maximum contract lengths,
6 sign contracts would nearly be in perpetual negotiation
7 to renew contracts. For some QFs, the negotiation
8 process can take months or even more than a year. If
9 many QFs signed short two or three year contracts, it
10 could be administratively difficult for both the
11 utilities and the Commission to review, approve, and
12 manage these contracts. Therefore, for practical reasons,
13 I think a five year maximum contract length would be more
14 reasonable. Moreover, the risk associated with 20-year
15 contract is greatly reduced when using a contract of five
16 years.
17 Q. Do you support Avista's request to limit
18 contract length under the IRP methodology, similar to
19 Idaho Power, but allow Avista the option to sign
20 contracts for more than five years in length if a very
21 favorable opportunity arises? (Reference Kalich, Di at
22 p.3, lines 2-4).
23 A. For the same reasons just stated for Idaho
24 Power and PacifiCorp, I think a maximum contract length
25 of five years is more reasonable and manageable for all
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1 three utilities. With regard to Avista's request to be
2 able to
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1 sign contracts for a period of longer than five years in
2 certain circumstances, I believe that option has always
3 existed. I am not opposed to that option continuing to
4 be available for all three utilities, provided that
5 contracts longer than five years can be justified, will
6 benefit ratepayers, and are only used in very rare
7 circumstances.
8 Q. What contract length have QFs historically
9 chosen, both under the SAR and the !RP methods?
10 A. The vast majority of QFs in the past have
11 chosen the maximum contract length available at the time,
12 whether they were SAR or IRP contracts. Some QFs have
13 chosen shorter contract lengths, generally less than five
14 years, in most cases because they did not want to be
15 locked into certain rates for long periods of time. In
16 some cases, QFs had some expectation that rates would
21 for PURPA contracts in other states?
18 for generation in the meantime until a longer term
19 contract could be signed at more attractive rates.
STERLING, R. (Di) 17
STAFF
910
Do you know what the maximum contract length is
I am not familiar with all other states in the A.
Q.
IPC-E-15-01
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17 increase in the future, but wanted to be able to be paid
20
23 U.S. in which there is significant PURPA activity, but I
22
25 years in Oregon, Utah, and Wyoming. It is 25 years in
24 do know that maximum contract length is currently 20
1 Montana, but only five years in Washington. In areas
2 where non-
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1 utility generators have ready access to wholesale power
2 markets such as PJM, ISO New England, New York ISO,
3 California ISO, Southwest Power Pool and ERCOT, there is
4 no mandatory purchase obligation under PURPA, thus, no
5 maximum contract length.
6 Q. Do you believe there may be other options
8 the problem?
7 besides reducing contract lengths that could also address
9 A. The Commission, in Order No. 32697 suggested
10
11
that it believed other tools, besides shortened contract
lengths, could be utilized to ensure an accurate and up I
12 to date avoided cost valuation. However, the Commission
13 stopped short of suggesting what those tools should be.
16 Although I believe avoided costs are reasonably being
15 beginning of the contract is, obviously, a first step.
14 Trying to determine accurate avoided cost rates from the
I I there may be additional factors that are currently not
being considered. For example, solar projects are
computed today under the IRP method, I also believe that
18
19
17
20 currently eligible for tax credits valued at up to 30
21 percent of the project cost. Presumably, the value of
22 these credits is being realized by the owners or
23 financiers of the projects, but is not being passed on to
24 the utility or its ratepayers. If a utility acquired a
comparable solar project or its output through a 25
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1 competitive solicitation, I would assume the value of any
2 tax incentives would be reflected in the purchase price
3 and therefore passed on indirectly to ratepayers.
4 Currently, tax incentives are not accounted for in the
5 IRP methodology, yet they provide tremendous benefit to
6 QFs.
7 There could be other potential changes to the way in
8 which avoided cost rates are calculated, but none would
9 adequately address the real problem-rates becoming
10 inaccurate over long contract lengths.
11 Q. Do you believe a periodic rate adjustment
12 mechanism could work, while maintaining QFs' option to
13 choose 20-year contracts?
14 A. In theory, periodically adjusting rates
15 throughout the term of the contract, say at two to five
16 year intervals, could help to ensure that avoided cost
17 rates in the contract remain accurate and reflect the
18 proper value compared to the market or other
19 alternatives. Similarly, indexing prices in the contract
20 based on electric market indexes or fuel prices could
21 accomplish the same thing.
22 Q. Do you believe QFs would find periodic rate
23 adjustments acceptable?
24 A. No, I do not. I expect QFs would view
25 adjustable rates, either through reopeners or indexing,
to be nearly comparable to short term contracts. Because
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913 STERLING, R. (Di) 19
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1 prices are the single most important element in a
2 contract, periodic adjustment of those prices could be
3 functionally equivalent to signing a new contract to QF
4 owners and financiers.
5 Q. Do PURPA or FERC rules allow periodic rate
6 adjustments?
7 A. FERC and various courts have made clear that
8 avoided cost rates contained in a PURPA contract cannot
9 be modified after the contract has been signed, although
10 neither the Idaho nor the U.S. Supreme Courts have held
11 as much. However, FERC rules do not specifically address
12 whether adjustable rate contracts are acceptable in
13 instances in which the contracting parties agree in
14 advance to an adjustment method and frequency.
15 Consequently, I am uncertain as to whether FERC would
16 find adjustment mechanisms acceptable. Because of this
17 uncertainty, and because I believe QFs would view
18 periodic rate adjustments as functionally equivalent to
19 new contracts, I think shorter contracts are the best
20 approach to reduce the financial or price risk of
21 long-term contracts.
22 Q. Do you agree that PURPA projects will always be
23 paid too much under 20-year contracts?
24 A. No, not necessarily. While it is true that
25 avoided cost rates have exceeded comparable market prices
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914 STERLING, R. (Di) 20
STAFF
1 throughout most of the history of PURPA in Idaho, there
2 have been times when this was not true. For example,
3 during the extreme electricity price spikes in late
4 2001-2002, market price far exceeded avoided cost rates
5 for extended periods of time.
6 Price comparisons at any single snapshot in
7 time are generally not valid projections over a long
8 period of time. Contractual avoided cost rates will
9 nearly always be higher or lower than comparable market
10 prices over the long-term such as 20 years. What is
11 important is that the prices are close over the entire
12 course of the contract term.
13 Now that a few contracts have reached or are
14 nearing their 20 or 35-year expiration, a comparison can
15 perhaps be made. However, in my opinion, if avoided cost
16 rates in any contracts have proven to be accurate over
17 time, it has been just by chance, not by design.
18 Q. Do you think it is fair for utilities to be
19 permitted to develop or acquire long-term generation
20 assets, but to only be obligated in the case of PURPA
21 resources to two, three, or five year contracts?
22 A. Whenever a utility acquires a resource or signs
23 a long-term PPA for new generation, it must identify the
24 need in its !RP, evaluate a range of alternatives, and
25 procure the resource or contract through a competitive
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STAFF
1 process. Throughout the entire process, the utility's
2 decisions are subject to intense scrutiny by the
3 Commission, intervenors, and other interested parties,
4 including customers. If the utility cannot first
5 demonstrate a need and second justify the cost-effective
6 resource, it does not receive Commission approval to
7 pursue the project.
8 As examples of utility acquisitions of
9 non-PURPA renewable projects, Idaho Power's Neal Hot
10 Springs and Raft River geothermal PPAs and its Elkhorn
11 Wind PPA were signed as a result of geothermal and wind
12 resources being identified as preferred resources in the
13 utility's IRP. Similarly, Avista's Palouse Wind Project
14 PPA and several PacifiCorp wind projects and PPAs were
15 identified through the IRP process and acquired through
16 subsequent competitive procurement processes.
17 Q. Was the procurement of thermal projects by
18 utilities, such as Idaho Power's Langley Gulch project,
19 PacifiCorp's Lakeside II, or Avista's Lancaster PPA any
20 different than the acquisition process employed for
21 renewables? Aren't those examples of long-term
22 commitments that bind ratepayers for very long periods of
23 time?
24 A. Just like the renewable projects previously
25 discussed, the utilities' thermal facilities mentioned
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916 STERLING, R. (Di) 22
STAFF
1 above also had to pass intense scrutiny before the
2 utilities were permitted to procure them. While it is
3 true that utilities are permitted to sign long-term
4 contracts and secure long-term financing, for most
5 projects there is no guaranteed complete cost recovery at
6 fixed rates. For example, in the case of Idaho Power's
7 Langley Gulch project, various costs of the facility are
8 included in base rates for recovery over the life of the
9 plant. However, fuel costs, which can represent as much
10 as two thirds of the total cost over the facility's
11 lifetime, are subject to annual adjustment to the extent
12 actual costs vary from what is included in base rates.
13 Moreover, most of these thermal generating facilities
14 provide other benefits such as dispatchability, variable
15 ramp rates, reserves and other ancillary services.
16 PURPA projects, on the other hand, are treated
17 differently. They are currently entitled to long-term
18 contracts at fixed rates. The utility is obligated to
19 sign contracts at Commission-approved rates, with no
20 consideration of need, with no competitive procurement
21 process, and without regard to cost-based pricing.
22 Recovery of PURPA contract payments by the utility is
23 through a combination of base rates and PCAs, but always
24 at 100 percent. There is no adjustment to the avoided
25 cost rates or to the amount authorized for recovery from
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917 STERLING, R. (Di) 23
STAFF
1 ratepayers throughout the entire term of the contract.
2 Q. Can PURPA cogeneration projects like Simplot or
3 Clearwater present additional risks over non-cogeneration
4 PURPA projects?
5 A. Perhaps. Cogeneration projects are always
6 associated with some other industrial process besides
7 generating electricity. Consequently, they face business
8 risks independent of their electric production. If the
9 thermal host for a cogeneration facility goes out of
10 business, then the electric production cannot continue.
11 Some examples of this have been the Magic West facility
12 in Glenns Ferry and the Yellowstone Power project at
13 Emmett.
14 Q. Do you believe PURPA is an effective mechanism
15 for utilities to acquire new generation?
16 A. No, I do not. I believe PURPA was intended to
17 permit relatively small, non-utility-owned projects to be
18 developed and to compete on an equal footing with
19 utility-owned facilities. I do not believe PURPA was
20 ever intended to serve as the primary, or even a major,
21 mechanism for utility acquisition of new resources.
22 Instead, at least for Idaho Power and perhaps PacifiCorp,
23 PURPA resources have become major resources, forced upon
24 them with no planning whatsoever. PURPA projects
25 entirely circumvent the planning process and sometimes
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918 STERLING, R . ( Di ) 2 4
STAFF
1 cause the utility to plan around them rather than
2 planning for them.
3 I
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5 I
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1 This creates a very awkward and inefficient planning
2 process and can lead to a poorly conceived generation
3 fleet that is not in the best interests of ratepayers.
4 Therefore, I do not support long-term contracts to
5 encourage PURPA at a time when utilities would not
6 otherwise be making long-term commitments for non-PURPA
7 generation resources.
8 Q. Each of the utilities' petitions in this case
9 have asked to reduce the maximum length of only IRP-based
10 contracts; however, SAR-based contracts continue to be
11 eligible for 20-year contracts. Do you believe 20-year
12 maximum contract lengths should continue to be available
13 to SAR-based contracts?
14 A. Yes, I do. Twenty year contracts should
15 continue to be available for wind and solar projects
16 smaller than 100 kW, and for all other project types
17 smaller than 10 aMW.
18 Q. If maximum contract lengths are reduced to less
19 than 20 years in this case for IRP-based contracts, are
20 you concerned about the difference in contract length
21 between SAR-based and IRP-based contracts?
22 A. No, I am not. Although there would be a
23 difference between maximum contract length for IRP and
24 SAR-based contracts, I believe such a difference is
25 reasonable. In the past, there have been instances in
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STAFF
1 which contract rates and/or terms were much more
2 favorable for SAR-based than for IRP-based contracts, and
3 it has led to QF developers strongly preferring one
4 contract type over the other. One recent example was the
5 disparity in rates (either real or perceived) between IRP
6 and SAR rates, which led to disaggregation of large wind
7 farms into smaller 10 MW projects.
8 In this case, most new PURPA projects are
9 likely to be solar, and the size limit or eligibility cap
10 for SAR-based solar contracts is 100 kW. Because this
11 cap is 100 kW, I believe it is unlikely a QF would be
12 disaggregated into such small pieces in order to qualify
13 for SAR-based rates, or more importantly, for 20-year
14 contracts. The same would likely be true for wind
18 of PURPA generation. For example, wind and solar
25 contracts for new SAR-based projects also apply to
STERLING, R. (Di} 26
STAFF
921
Does your proposal to maintain 20-year Q.
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16 In addition, SAR-based projects do not
15 projects.
19 projects (both under contract and proposed} account for
17 represent a significant portion of the cumulative amount
21 according to Idaho Power Exhibit No. 1. Thus, the impact
20 more than 1973 MW of Idaho Power's PURPA projects
23 magnitude of IRP-based projects.
24
22 of SAR-based projects is very small in comparison to the
1 SAR-based contracts that will be expiring and that desire
2 new contracts?
3
4
A.
Q.
Yes, it does.
Please discuss the number and timing of
5 expiring SAR-based contracts.
6 A. In the coming years, many existing PURPA
7 contracts will expire and will be seeking replacement
8 contracts. Exhibit No. 101 depicts graphically the
9 timing and number (but not the amount of generation) of
10 QF contracts that will be expiring. Each line on the
11 graph represents a different contract. In the coming 10
12 years, 94 contracts will expire and could choose to be
13 renewed.
14 Q. Why should SAR-based contracts be permitted
15 longer contracts than IRP-based contracts?
16 A. Neither SAR-based nor IRP-based rates are
17 likely to remain accurate over a 20-year period. On a
18 per kW basis, the risk for SAR-based contracts is exactly
19 the same as for IRP based contracts. However, SAR-based
20 contracts, because the project sizes are individually and
21 collectively small, present much less risk if contract
22 rates prove to be too high or too low compared to the
23 actual value of the power.
24 Q. Should SAR-based replacement contracts be
25 permitted 20-year terms?
A. Yes, I recommend that all SAR-based contracts
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922 STERLING, R. (Di) 27
STAFF
1 be eligible for 20-year contracts, regardless of whether
2 they are for new projects or for replacement contracts.
3 SAR-based projects that are renewing contracts will
4 receive the then current energy rates and capacity rates.
5 Even though projects seeking replacement contracts
6 presumably have already been financed and retired their
7 debt, for consistency sake I think it is reasonable that
8 all SAR-based contracts follow the same rules.
9 Contracts that were initially SAR-based, but at
10 the time of contract replacement exceed the size
11 threshold for SAR-based rates, should be treated as new
12 !RP-based contracts but eligible for capacity payments
13 throughout the entire contract term.
14
15
Q.
A.
Please summarize your recommendations.
I recommend that the maximum contract length
16 for standard !RP-based contracts be five years for Idaho
17 Power, PacifiCorp, and Avista. I also recommend that the
18 maximum contract length for SAR-based contracts remain at
19 20 years, both for new and for replacement contracts.
20 Q. Does this conclude your direct testimony in
21 this proceeding?
22
23
24
25
A. Yes, it does.
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923 STERLING, R. (Di) 28
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
6
Q.
A.
By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities
7 Commission as the Engineering Supervisor.
8 Q. Are you the same Rick Sterling that previously
9 submitted testimony in this proceeding?
10
11
12
A.
Q.
A.
Yes, I am.
What is the purpose of your rebuttal testimony?
The purpose of my rebuttal testimony is to
13 address several issues raised by Clearwater/Simplot
14 witness Dr. Reading and ICL/Sierra Club witness Beach.
15 Q. Various witnesses have suggested that there is
16 unequal treatment between QFs and utility-owned
17 resources. Do you agree?
18 A. I would agree that QFs and utility-owned
19 resources are not treated the same. However, much of the
20 different treatment is because PURPA requires it. A
21 significant difference is the pricing of QF generation.
22 PURPA dictates that the price or rate a utility pays for
23 the purchase of QF power be based on the avoided cost of
24 the utility-not the QFs cost of producing the power. In
25 particular, a QF that places its facility into service
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STAFF
1 before January 1, 2017 will receive a 30 percent tax
2 credit. This substantial tax credit is not reflected in
3 the avoided cost rate.
4 Furthermore, most of the different treatment is
5 to the benefit rather than the detriment of QFs. For
6 example, the utility has a "must purchase" obligation
7 under PURPA whereas utilities may engage in arms-length
8 bargaining when acquiring resources. In addition, QFS
9 are entitled to contracts regardless of a utility's need,
10 whereas utility-owned resources must obtain a Certificate
11 of Public Convenience and Necessity, which requires a
12 showing of present or future need and competitive cost
13 compared to other alternatives. Utility-owned resources
14 must be competitively procured and are subject to
15 cost-based pricing, whereas QF contracts are not subject
16 to competition and non-negotiated pricing. Utility-owned
17 resources are dispatched based on market prices or the
18 cost of alternate resources, but QF power must be
19 accepted by the utility whenever offered. Finally, the
20 fuel and variable costs of utility-owned resources are
21 subject to annual adjustment through PCAs, but PURPA
22 prices are fixed for the entire duration of the contract.
23 Q. Various witnesses (Reading pp. 25-26; Beach pp.
24 21-25) have also suggested that PURPA projects, because
25 of their fixed pricing, provide a valuable risk hedge and
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STAFF
1 a benefit to ratepayers. Do you agree?
2 A. No, not entirely. QF pricing, because it is
3 locked in for 20 years, may eliminate price volatility,
4 but it does not completely eliminate risk. QF prices
5 that prove to be too high can be locked in to the
6 detriment of ratepayers. Conversely, QF prices that
7 prove to be too low can be locked in to the benefit of
8 ratepayers. In either case, ratepayers are still exposed
9 to the same risk. PURPA projects can help to limit risk
10 when market prices rise to extreme levels, but they can
11 also limit opportunities to take advantage of very low or
12 declining prices for the benefit of ratepayers. Like all
13 hedges, the critical question is how much protection do
14 you need and how much should you be willing to pay for
15 it. Utility-owned resources, on the other hand, are
16 economically dispatched. In other words, they are only
17 run when they are less costly than other alternatives or
18 when their output can be sold at a profit.
19 Q. On pages 10 and 11 of Dr. Reading's direct
20 testimony, he quotes a passage from Commission final
21 Order No. 32697 in the GNR-E-11-03. In that Order, the
22 Commission declined to adopt a contract length less than
23 20 years. Are the circumstances of the 2011 case the
24 same as in this case?
25 A. No, they are not. In the GNR-E-11-03 case,
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STAFF
1 Idaho Power proposed that the maximum contract length for
2 all PURPA contracts be reduced from 20 years to 5 years.
3 Tr. at 487, 489, 524 ("Idaho Power recorrunends that the
4 five-year contract term apply to all PURPA QF power sale
5 contracts."). In the GNR-E-11-03 case, Staff's position
6 was that PURPA contracts be limited to five years for
7 only those contracts utilizing the IRP methodology (i.e.,
8 above the SAR-based eligibility cap). I testified that:
9 "Twenty-year contracts should continue to be available to
10 QFs under the SAR methodology." Tr. at 1107-08.
11 So the Corrunission's statement quoted by Dr. Reading
12 was also responding to Idaho Power's position that all
13 PURPA contracts should be reduced to five years,
14 regardless whether they used the SAR-based methodology or
15 IRP-based methodology. In the present case, all the
16 parties have agreed to continue 20-year contracts for
17 SAR-based contracts. In other words, the parties have
18 agreed that SAR-based PURPA contracts will be unaffected
19 by the reduction in contract length recorrunended for
20 IRP-based contracts.
21 Q. Are there other reasons for the Corrunission to
22 re-examine the length of IRP-based PURPA contracts?
23 A. Yes, there are. First, the Corrunission is a
24 regulatory agency that performs legislative functions and
25 re-examines regulatory policies from time-to-time. The
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STAFF
1 Commission is not bound to decide future cases in the
2 same way as in past cases. As I recounted in my direct
3 testimony, since PURPA was first implemented in Idaho,
4 maximum contract length has gone from 35 years, to 20
5 years, to five years, and back to 20 years. The
6 Commission can and should change policy as circumstances
7 change.
8 Second, at the time the Commission issued its
9 Order No. 32697 in the GNR case in December 2012, Idaho
10 Power had less that 800 MW of nameplate PURPA power.
11 Since the GNR case, Idaho Power reported that it had 461
12 MW under contract from solar developers (including the
13 141 MW of recently terminated contracts in the Clark
14 Solar 1 -4 projects) and an additional 885 MW of proposed
15 solar development. See Idaho Power Ex. 1. Simply put,
16 Idaho Power claims that it has more than 1200 MW of
17 contracted and proposed solar projects in this case.
18 This compares with the Company's peak load of 3,400 MW,
19 its minimum system load of 1,073 MW, and its average
20 system load of 1,800 MW. (Grow, Dir at 3; 2013 IRP
21 Appendix A).
22 Q. On pages 14 and 15 of Dr. Reading's direct
23 testimony, he created a chart and purportedly compares
24 the costs of Idaho Power's generating resources to the
25 costs of PURPA projects. Do you agree with the
representations made in his Chart No. 1 on page 15?
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928 STERLING, R. (Reb) 5
STAFF
1 A. No, I do not. In Chart 1 on page 15 of Dr.
2 Reading's direct testimony, he compares the PURPA costs
3 to the estimated capital and running costs of various
4 Idaho Power-owned thermal generation resources. While
5 the comparison may be numerically accurate, it is
6 extremely misleading because the resources being compared
7 are very different types of resources. More
8 specifically, when resource costs are compared on a cost
9 per MWh basis, and certain resources generate
10 substantially different amounts of MWhs, peaking
11 resources, such as Bennett Mountain and Danskin, will
12 appear far more costly than baseload resources such as
13 Jim Bridger. Peaking resources, because they are used
14 infrequently and generate few MWhs, will always appear
15 far more "costly" than baseload resources when measured
16 on a cost per MWh basis. Conversely, on a cost per MW
17 basis, peaking resources will always be less expensive
18 than baseload resources.
19 In addition, Dr. Reading acknowledges that he
20 omitted Idaho Power's lowest cost resources-its hydro
21 resources-from his cost comparison. He could have
22 included the hydro data by using an average over several
23 years or normalized data. He also omitted hydro cost due
24 to, in his words, "massive environmental remediation."
25 (Dir at 16). The failure to include hydro costs
significantly misstates the Company's power costs,
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STAFF
1 especially where 1,709 MW of hydro is included in 3,500
2 MW of nameplate capacity (Grow, Dir at 5).
3 Fair and reasonable direct comparisons between
4 the costs of different resources can only be made for
5 resources with comparable capacity factors, and when the
6 comparisons are made over the same periods of time.
7 Comparisons either on a cost per MW or a cost per MWh
8 alone basis (capacity or energy) should never be used to
9 judge the cost effectiveness of particular resources.
10 Similarly, cost comparisons in which only a portion of
11 the duration of a contract are considered are also
12 usually inappropriate. Differences between PURPA
13 contract rates and market prices may exist in specific
14 years, but there is no certainty that those differences
15 will persist for the duration or remainder of a contract.
16 Q. On page 4, Dr. Reading has asked whether there
17 are other viable opportunities for projects like
18 Simplot's and Clearwater's to sell their output to other
19 buyers in the region. Do you agree with his statement on
20 page 5 that ''aside from PURPA sales to utilities, neither
21 Clearwater nor Simplot have a legal or economically
22 viable market, retail or wholesale, to sell electricity"?
23 A. No, I do not. Conspicuously absent in his
24 answer and analysis is the possibility of either of these
25 two entities selling their output to other utilities in
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STAFF
1 the region. Clearwater and Simplot may be able to
2 operate in a similar fashion to exempt wholesale
3 generators (EWGs) and sell their output to other
4 utilities. For example, Clearwater currently sells its
5 output to Avista using a non-PURA contract.! Other
6 renewable projects have sold their non-PURPA output to
7 other utilities such as the wind farm in eastern Idaho
8 (Goshen North Wind Farm) selling to a California utility;
9 Lucky Peak selling its hydro output to Seattle City Light
10 or Palouse Wind selling its wind generation to Avista.
11 Other renewable generators have been successful in
12 selling their output to utilities without resorting to
13 PURPA contracts including the Neal and Raft River
14 geothermal projects to Idaho Power and the Elkhorn wind
15 project to Idaho Power in Oregon.
16 Q. Could Clearwater sell its output to another
17 utility other than Avista under either a PURPA or
18 non-PURPA agreement?
19 A. Yes. As Dr. Reading notes on page 3 of his
20 direct testimony, Clearwater's current 2013 agreement
21 "provides Clearwater with a limited right to terminate
22 its
23 Ill
24
25
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931 STERLING, R. (Reb) 8
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1 On May 13, 2015, Avista filed an Application seeking
22 Commission approval of an amendment to Avista's contract
with Clearwater. The amendment proposed to extend the
23 current agreement by three additional years, in addition
to permitting Avista to purchase incremental energy from
24 Clearwater at negotiated prices when it is beneficial to
both parties.
25
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932 STERLING, R. (Reb) Ba
STAFF
1 energy sales to Avista with 90 days' notice." (Reading,
2 Dir at 3). Under the terms of its current power purchase
3 agreement with Avista, Section 1 on page 2 of the
4 agreement provides that:
5 If, during the Term of this Agreement, [Clearwater]
desires to sell the output of the Generation to any
6 third party, [Clearwater] shall terminate this
Agreement by providing Avista written notice of
7 termination at least 90 days prior to such
termination. The sale to the third party shall not
8 commence until the date on which this Agreement is
terminated. In the event that [Clearwater] desires
9 to sell the output of the Generation to any third
party(ies), [Clearwater] shall be responsible for
10 making all necessary arrangements to facilitate the
sale of the output of the Generation to such third
11 party(ies).
12 The Commission approved this contract in Order
13 No. 32841 issued June 28, 2013. By the terms of this
14 agreement, Clearwater clearly preserved the opportunity
15 to sell its output to a party other than Avista.
16 Q. Dr. Reading on p. 36 suggests that there is a
17 flaw in the IRP computation methodology because it is
18 unable to account for hours when market prices are
19 negative and that the model instead assigns a price of
20 zero when the actual avoided cost is negative. Do you
21 agree that the model is flawed?
22 A. I would agree that the model should not be
23 assigning a price of zero when prices are negative.
24 However, I would also point out that, despite
25 possible
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1 misconceptions, that the AURORAxmp model used to generate
2 energy prices can, in fact, generate negative prices
3 under certain circumstances. The Idaho Power spreadsheet
4 that uses AURORAxmp prices as input should then, in turn,
5 be able to capture the effect of negative prices.
6 Nonetheless, while the capability to account
7 for negative pricing exists, no negatively priced hours
8 appeared in the AURORAxmp output used for pricing the 13
9 recent Idaho Power solar contracts, primarily because
11 conditions used for PURPA pricing.
13 this proceeding?
10 negative pricing is currently not likely under average
Does this conclude your rebuttal testimony in Q. 12
14 A. Yes, it does.
15
16
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24
25
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6 Mr. Richardson.
4 cross-examination.
2 open hearing.)
MR. HOWELL: And Mr. Sterling is available for
COMMISSIONER KJELLANDER: Let's begin with
3
5
1 (The following proceedings were had in
7 MR. RICHARDSON: Thank you, Mr. Chairman.
8
9 CROSS-EXAMINATION
10
11 BY MR. RICHARDSON:
12 Q. Good morning, Mr. Sterling.
13 A. Good morning.
14 Q. At page 1 and line 18 of your prefiled direct
15 testimony, you describe your duties at the Commission as
16 being "the lead Staff member on all PURPA dockets at the
17 Commission since 1994." Do you see that?
18 A. Yes, I do.
19 Q. So you're the guy who is responsible to shape
20 Staff's positions on PURPA cases?
21 A. I don't do it by myself, but I'm the lead
22 person, I have been.
23 Q. So you're in charge of deciding what the
24 Staff's position will be?
25 A. No, I wouldn't quite put it that way. We
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1 collectively as a Staff discuss issues and discuss
2 positions and come to agreement.
3 Q. But what does it mean to be the lead Staff
4 person?
5 A. It's one of my primary responsibilities. I
6 have been a witness in nearly every PURPA case where
7 Staff has participated in a hearing.
8
9
Q.
A.
And you're the Staff's policy witness?
I'm the Staff witness and I can speak to some
10 policy questions, yes.
11 Q. So reading your testimony, your direct and
12 rebuttal testimony, sort of at the 35,000-foot level,
13 would it be fair to conclude that you would prefer to see
14 the must-buy provisions of PURPA repealed?
15 A. No, I haven't taken a position on that in my
16 testimony.
17 Q. Well, at page 24, line 13, you were asked, "Do
18 you believe PURPA is an effective mechanism for utilities
19 to acquire new generation?" Do you see that?
20
21
22
23
A.
Q.
A.
Q.
Yes, I do.
And what was your response to that question?
No, I do not.
So if you don't believe PURPA is an effective
24 mechanism for utilities to acquire new generation, what
25 is your position on the must-buy provision of PURPA
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1 forcing utilities to buy QF power in light of the fact
2 that you don't think it's an effective mechanism to
3 acquire new generation?
4 A. Well, PURPA is a federal law that we must
5 comply with. We don't create the federal law, "we" the
6 Idaho Public Utilities Conunission. We simply implement
7 it.
8 Q. Right, and I was asking you what your opinion
9 is on the must-buy provision of PURPA. Is it a good law
10 or is it a bad law in your opinion?
11 A. If structured and implemented properly, I think
12 it can be a good law.
13 Q. So you're aware, are you not, that federal law
14 requires state conunissions to encourage the development
15 of QF projects?
16
17
A.
Q.
Yes, I am aware of that.
So isn't that a bit awkward for you given your
18 position that PURPA is a not an effective mechanism for
19 utilities to acquire generation and you're the lead
20 policy person on the PUC Staff implementing PURPA?
21
22
A.
Q.
No, I don't see the a conflict there.
All right; so on page 4 of your direct
23 testimony, you quote from the Conunission's Order in the
24 generic avoided cost docket in which the Conunission
25 rejected your proposal to go to a five-year contract for
CSB REPORTING
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937 STERLING (X)
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1 PURPA projects, and then you are asked basically what has
2 changed in the two-and-a-half years since that Order was
3 issued such that the Commission should now adopt the same
4 five-year contract limit that it rejected just a short
5 time ago, and your answer over on page 5 is that the
6 recently rejected five-year contract term should now be
7 adopted because Idaho Power has signed up 461 megawatts
8 of new solar and has 885 new megawatts of pricing
9 requests, and then you point out that PacifiCorp has
10 received requests for 120 megawatts of new solar and has
11 pricing requests for 275.5 megawatts. Do you see that?
12 A. Yes.
13 Q. Would you agree with me that one thing that
14 hasn't changed since the last avoided cost case where
17 term should be adopted?
16 was rejected is your belief that the five-year contract
15 your recommendation for a five-year contract limitation
No, that hasn't changed. I took a position A. 18
19 of five years should be the maximum contract length in
20 the
21 Q. And that's still your position today;
22 correct?
23 A. Yes, it is.
24 Q. So looking back at your answer on page 5, again
25 to the question of what has changed, does it strike you
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1 as significant that there is no mention of Avista
2 Corporation in your answer?
3
4
6
8
A.
Q.
A.
Q.
No.
What are the equivalent numbers for Avista on
To my knowledge, Avista has no proposed QFs,
So on the bottom of page 8 to the top of page 9
7 solar QFs, that are pending or proposed.
5 new solar and pricing requests?
9 of your direct testimony, you were asked whether a
10 five-year contract term would limit QFs' ability to
11 obtain financing and thus make extensive project
12 development unlikely, and you respond in part by noting
13 that facilities could still be developed by other
14 mechanisms; correct?
15
16
A.
Q.
Yes.
Well, you would agree with me, wouldn't you,
17 that it's still illegal in Idaho for me to generate and
18 sell electricity to my neighbor?
19 A. You're not allowed to sell retail without being
20 regulated as a utility.
21 Q. On page 11, beginning on line 17, you state
22 that FERC rules do appear to contemplate less than
23 20-year contracts. Do you see that section?
24
25
A.
Q.
Yes, I do.
In fact, if you go to line 19 on page 11 and
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1 put a quote mark in front of the word "to" and then go
2 down to line 20 and change the word "information" to
3 "data" and then go down to line 21 and put a quote mark
4 after the word "derive," you would have a verbatim
5 word-for-word quote from 18 CFR 292.302(b); correct?
6
7 me.
8
A.
Q.
I don't have the FERC regulations in front of
Well, you quoted the FERC regulations in your
10
12 side.
13
A.
Q.
I don't know if the wordsmithing that you
I didn't bring the CFRs with me, but would you
9 testimony, did you not?
11 suggest would exactly match without seeing them side by
14 accept, subject to check, that that's a verbatim
15 word-for-word quote from CFR -- 18 CFR 292.302(b)?
16
17
A.
Q.
Subject to check, yes.
And on line 24, if you put quotes in front of
18 the word "plan" and over on to page 12, line 2, if you
19 put quote marks after the word "years," that's a verbatim
20 word-for-word quotation from 18 CFR 292.302(b) (2).
21 Didn't you quote the FERC regulations in your
22 testimony?
23 A. I may have come very close to that. I
24 didn't put quotation marks around
25 Q. Well, subject to check, if you put quotes
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1 around the words I just said, it's a verbatim
9 five-year PURPA contract term?
2 word-for-word quotation. Is that a coincidence or did
No, that's mischaracterizing my testimony.
Well, what is your testimony saying about
It's just a coincidence, I suppose.
It's just a coincidence, okay; so are you Q.
Q.
A.
A. 5
6
4 them?
7 saying that because FERC requires five years of energy
3 you just quote the FERC regulations without citating
8 data to be made available that it is contemplating a
10
11
12 contract terms and the FERC regulations that you
13 coincidentally quoted?
14 A. I think it's very clearly laid out in my
15 testimony, if you'd like to refer me to a specific line.
16 Q. I'm talking about page 11, line 17, through
17 page 12, line 2. "FERC rules do appear to contemplate
18 less than 20-year contracts," so what term do FERC rules
19 contemplate? Something less than 20, perhaps five?
20 A. Less than 20 is what I state in my testimony.
21 Q. For energy -- I'm quoting you at page 11, line
22 21, "For energy, utilities are required to estimate the
23 energy component of avoided costs by year for the current
24 year and each of the next five years." What's the
25 relevance of that statement in terms of contract
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1 length?
2 A. I think it's a suggestion that FERC was
3 contemplating terms that are less than 20 years.
4
5
6
Q.
A.
Q.
Perhaps five?
Perhaps.
Okay, thank you. Then it is also true that in
7 Section 18 CFR 292.302(b) (2) that you quote
8 coincidentally that because 10 years of energy and
9 capacity data has to be made available that FERC is also
10 contemplating a 10-year contract term; correct?
11
12
A.
Q.
Yes.
So over on page 12 at line 12, you were asked
13 if there are other reasons why you believe that the
14 maximum contract should be shortened to five years. Do
15 you see that?
16
17
A.
Q.
Yes, I do.
And you respond with a discussion of the larger
18 fuel risk associated with a gas-fired SAR as opposed to
19 the prior coal-fired SAR; correct?
20
21
A.
Q.
That's correct.
But this is not a new argument, is it? In
22 fact, you just cut and pasted your fuel risk argument
23 from your generic avoided cost testimony two years ago;
24 correct?
25 A. I don't recall.
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1 Q. So I have a copy of your testimony in the
2 generic avoided cost case from two years ago and I could
3 read that into the record and would you accept, subject
4 to check, that it's essentially identical?
5
6
A.
Q.
Subject to check, yes, I would.
Okay; so nothing has changed, has it, in your
7 reasoning about the fuel risk argument since this
8 Commission rejected that argument just two years ago?
9 A. For the fuel risk argument, no, nothing has
10 changed.
11 Q. Okay, then on the bottom of page 13, you were
12 asked about the price risk associated with a long-term
13 contract as yet another reason to adopt your recommended
14 five-year contract term, but, again, you made the same
15 argument two years ago and it was rejected by this
16 Commission, and in fact, this section of your testimony
17 is largely just cut and pasted from your testimony two
18 years ago, so my question to you is but nothing has
19 changed in your price risk argument between now and when
20 it was rejected two years ago, has it?
21
22
23
A.
Q.
A.
No, I wouldn't agree.
What has changed?
We have hundreds or thousands of megawatts
24 collectively amongst the three utilities that are
25 proposing solar contracts. The price risk associated
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1 with those contracts is much greater now than it ever has
2 been, and I've explained that in my testimony.
3 Q. So going over to page 18 at line 6, you're
4 asked, "Do you believe there may be other options besides
5 reducing contract lengths that could also address the
6 problem"; so when you refer to "the problem," is it fair
7 to return to page 2 of your testimony at line 12 where
8 you state, "I believe the real issue is the risk exposure
9 to ratepayers that can occur due to long-term PURPA
10 contracts"; is that what the "problem" is?
11
12
A.
Q.
In my opinion, yes.
But in your answer to that question on page 18,
13 line 6, you spend most of your answer talking about ways
14 utilities could possibly capture solar tax credits from
15 developers. Can you explain what the relationship is
16 between tax credits and contract length?
17 A. There have been suggestions in the case that we
18 should address cost issues, avoided cost pricing issues,
19 rather than contract length and I'm responding to that
20 suggestion that has been made by various witnesses that
21 pricing is the real issue here, not contract length, and
22 that's the context in which this portion of my testimony
23 was offered.
24 Q. So pricing is the real issue, not contract
25 length?
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1 A. It's a combination of the two, but pricing is
2 an issue that other witnesses have brought up, and so I'm
3 simply speaking to that.
4 Q. Did I mishear you say that pricing is the real
5 issue, not contract length?
6
7
A.
Q.
It's a combination of the two.
If you solve the pricing issue, does the
8 contract length issue go away?
9 A. They're both issues, because as I state in my
10 testimony, I don't think for a 20-year contract that you
11 can maintain accurate pricing.
12
13
Q.
A.
Right, but --
If you could possibly maintain accurate pricing
14 for 20 years, then contract length may not be an issue,
15 but I don't believe that you can do that; therefore, I
16 think pricing and contract length both together are
17 issues.
18 Q. So if you have a pricing mechanism that you can
19 true-up on a periodic basis, does that solve the contract
20 length issue?
21
22
A.
Q.
It could.
And Dr. Reading proposed a contract pricing
23 readjustment mechanism, did he not?
24
25
A.
Q.
I believe he did in his rebuttal testimony.
Towards the bottom of page 3, line 19, I think
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1 that's your rebuttal, right, it's your rebuttal
2 testimony, page 3, line 19, you were asked whether the
3 circumstances of the recently concluded generic avoided
4 cost docket where the Commission rejected your five-year
5 contract argument are the same as in this case, and over
6 the next two pages you respond. You first point out that
7 in the generic docket, there was a dispute over whether
8 the contract limitation should apply to all or only
9 IRP-based PURPA contracts, and you note that in this case
10 it's different because we have agreed that we're only
11 discussing IRP-based contracts.
12 Then you point out that the Commission can and
13 does change its mind from time to time, and that's on
14 page 4, line 23. Finally, over on page 5, beginning on
15 line 15, you state ''Simply put, Idaho Power claims that
16 it has more than 1,200 megawatts of contracted and
17 proposed solar projects in this case"; so in your
18 opinion, 1,200 megawatts of proposed and solar --
19 proposed and contracted solar capacity is enough to
20 trigger a reduction in contract length to five years?
21 Did you conduct an analysis as to where the line should
22 be drawn as to how much is enough to trigger a contract
23 length reduction?
24
25
A.
Q.
No.
So you don't know if Idaho Power had 600
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1 megawatts of proposed and contracted solar that that
2 would be sufficient to trigger a contract length
3 reduction?
4 A. I haven't specified a certain level of
5 megawatts.
6 Q. But is that because you haven't changed your
7 position from two-and-a-half years ago that the contract
8 length should be five years and not 20?
9
10
11 it?
12
A.
Q.
A.
I wouldn't say it's because of that.
But nothing has changed in your opinion, has
As I explained previously, we have hundreds or
13 thousands more megawatts proposed than we had two years
14 ago. That's what's changed.
15 Q. So your position on contract length hasn't
16 changed?
17
18
A.
Q.
No, it hasn't.
And that position was rejected by this
19 Commission just two-and-a-half years ago; correct?
20
21
A.
Q.
Yes, it was.
And you're highly critical of Dr. Reading in
22 his presentation of his chart on page 15 of his
23 testimony, and that's at page 5, line 25 of your
24 testimony. I've got to get that reference correct. You
25 are critical of Dr. Reading's chart on page 15 of his
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1 testimony; correct?
2
3
A.
Q.
Yes.
And one of the primary objections you have is
4 that Dr. Reading included peaking resources on his chart
5 that shows that PURPA projects are cheaper, less
6 expensive, than some of Idaho Power's own resources;
8
9
A.
Q.
Yes.
So if we concede your point and remove the two
7 correct?
10 peaking resources from Dr. Reading's chart, we are still
11 left with the fact that PURPA resources are less
12 expensive than Idaho Power's most recent state-of-the-art
13 gas-fired base load unit Langley Gulch, aren't we?
14 A. I still think that's a misunderstanding of the
15 data that's used to create those charts.
16 Q. But you conceded that Dr. Reading's
17 calculations are correct, didn't you?
18 A. I've never spoken to the correctness of his
19 numbers.
20
21
Q.
A.
I believe you do.
I'm not disputing that they're incorrect. I
22 just never addressed that.
23 Q. So finally, you note on page 7 to 8 of your
24 rebuttal testimony that QFs like Simplot or Clearwater
25 could sell their output to other utilities in other
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1 states. Would you agree that that's not always as easy
2 as it seems?
3
4 that.
5
6
7
A. I can't respond to a generalization like
MR. RICHARDSON: Madam Chair --
COMMISSIONER KJELLANDER: Yes, Mr. Miller.
MR. RICHARDSON: Mr. Chair, may I approach the
8 witness with a document?
9
10
11
COMMISSIONER KJELLANDER: Certainly.
(Mr. Adams distributing documents.)
MR. RICHARDSON: Mr. Chair, I'm handing out
12 Idaho Power's petition for a declaratory ruling in the
13 matter of Idaho Power Company's petition for a
14 declaratory ruling regarding PURPA jurisdiction and --
15 MR. HOWELL: Mr. Chairman, could we have a
16 minute until I've been provided a copy of that?
17
18
MR. RICHARDSON: Of course.
COMMISSIONER KJELLANDER: Certainly, and while
19 we're allowing that to be distributed, let's look
20 quickly, this would be, to the extent that you want it
21 marked and identified, 209.
22 MR. RICHARDSON: I'm not going to mark it as an
23 exhibit, Mr. Chairman.
24
25
COMMISSIONER KJELLANDER: You're not, okay.
MR. RICHARDSON: Thank you.
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1 COMMISSIONER KJELLANDER: Mr. Howell, do you
2 have a copy now?
3
4
MR. HOWELL: I do. Thank you, Mr. Chairman.
COMMISSIONER KJELLANDER: Okay, Mr. Richardson,
5 if you'd like to proceed.
6
7 Q.
MR. RICHARDSON: Thank you, Mr. Chairman.
BY MR. RICHARDSON: Mr. Sterling, this is a
8 copy of an Idaho Power petition for a declaratory order
9 on file in an open docket before this Commission in which
10 Idaho Power responds to Kootenai Electric's attempt to do
11 exactly as you suggest, which is to move power to another
12 state. I'm wondering if you would please read for the
13 record the paragraph beginning at the bottom of page 8.
14 No, not page 8, the paragraph beginning at the bottom of
15 page 5.
16 MR. SCHMIDT: Mr. Chairman, my copy just has
17 every other page; is that --
18
19
COMMISSIONER RAPER: Odd pages only.
COMMISSIONER KJELLANDER: Mr. Schmidt has
20 identified the fact that we don't have all the pages
21 here, good catch, and Mr. Richardson, in lieu of running
22 out and grabbing all the even numbered pages, do you have
23 any questions associated with the even numbers?
24 MR. RICHARDSON: I have a complete copy here,
25 which I can provide to the witness.
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1 COMMISSIONER KJELLANDER: Why don't we get that
2 to the witness and see if we can get through this without
3 having to break to make more copies.
4 MR. RICHARDSON: Yes, I apologize for that,
5 Mr. Chairman.
6 THE WITNESS: It's not me. I have page 5.
7 It's the other parties that are going to need page 5.
8
9 page 6?
10
11
12 copy.
13
14 well.
15
16
COMMISSIONER KJELLANDER: Is he going to need
MR. RICHARDSON: He will need page 6.
COMMISSIONER KJELLANDER: Then he will need a
MR. HOWELL: Mr. Chairman, I'd like a copy as
MR. RICHARDSON: So if we could take a break --
COMMISSIONER KJELLANDER: Okay, at this point
17 where we will be is taking a ten-minute break and in ten
18 minutes let's all head back here with brand-spanking new
19 copies that actually have all the pages, and with that,
20 then we can go off the record.
21 (Recess.)
22 COMMISSIONER KJELLANDER: We will now go back
23 on the record and, Mr. Richardson, you have since the
24 break distributed a revised copy with all of the pages,
25 odd and even, and as I recall, you were referencing a
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1 question to Mr. Sterling that was associated, I believe,
2 with page 5, so I will let you continue, but if you could
3 start with the question that you had asked Mr. Sterling
4 to read a paragraph that I believe began on page 5.
5
6 Q.
MR. RICHARDSON: Thank you, Mr. Chairman.
BY MR. RICHARDSON: To reset, restart here, the
7 question, Mr. Sterling, was finally, you note at page 7
8 to 8 of your rebuttal testimony that QFs like Simplot or
9 Clearwater can sell their output to other utilities in
10 other states, and my question was you would agree with
11 me, would you not, that it's not always as easy as it
12 seems, wouldn't you?
13 A. And I think I responded that I can't respond to
14 a generalization like "as easy as it seems." I don't
15 know what you mean by that.
16 Q. And in response, I handed out Idaho Power
17 Company's petition for a declaratory order regarding
18 PURPA jurisdiction in Case No. IPC-E-11-23, and it's a
19 petition for a declaratory order, and this asks the
20 Commission to take judicial notice that this is a
21 petition in an active docket currently before this
22 Commission, and I was asking you to read the paragraph
23 that begins on the bottom of page 5, and I'll just
24 represent to the Commission that this is a matter where
25 Kootenai Electric Cooperative was attempting to do just
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1 what Mr. Sterling was suggesting, which is sell its
2 electric output, its QF electric output, to a utility in
3 another state, and would you please read the paragraph
4 beginning on the bottom of page 5?
5 MR. HOWELL: Mr. Chairman, I'm going to object
6 to the line of questioning. I think asking a witness to
7 read from a document that is not prepared by Staff, but
8 is a petition prepared by another party in this case
9 is leads to confusion about whether the witness would
10 agree or not agree with the statement. As the Commission
11 is aware, or hopefully aware, that Idaho Power in this
12 particular case filed a petition not only in Idaho, but
13 in Oregon and the Commission in this case has done
14 nothing but issue a notice of petition.
15 There have been no Staff comments filed in this
16 case. There have been no further proceedings by the
17 Commission in this case. This matter has reached
18 resolution as far as I know because it was a matter that
19 was decided ultimately by FERC regarding Kootenai
20 Electric's petition against the Oregon Public Utilities
21 Commission, so whether this case is open or closed, I
22 think it's confusing to ask a witness to read a paragraph
23 from a petition, from a document, that the Staff has
24 never prepared, that the Staff has never opined on, that
25 the Commission hasn't had any further proceedings on, and
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1 as far as I know, this matter is closed.
2
3
COMMISSIONER KJELLANDER: Mr. Richardson.
MR. RICHARDSON: Thank you, Mr. Chairman. It's
4 interesting that counsel for the Staff would object to
5 admission of this document to show that it is in fact
6 difficult and challenging to move your power from one
7 jurisdiction to another. We're not here to -- I'm not
8 offering this to prove, one, that Idaho Power was correct
9 or Idaho Power was wrong, that the docket is open or the
10 docket is closed. I'm offering this exhibit, this
11 document, to demonstrate to Mr. Sterling the answer to my
12 question, which is it's not as easy as it seems. When
13 one entity was attempting to move their power to another
14 utility in a different state, this was the response they
15 got, dealing with multiple years of litigation before
16 this Commission, the Oregon --
17 COMMISSIONER RAPER: Mr. Richardson, if you
18 choose to testify in this regard on this document, I
19 think it's something that you might choose to include in
20 closing statements, but we have a witness on the stand
21 that's waiting for questions from you.
22 MR. RICHARDSON: And he has a question before
23 him to read the paragraph beginning on the bottom of page
24 5, which I think is a legitimate response to his direct
25 testimony and that's my response to counsel.
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1 COMMISSIONER KJELLANDER: For purposes of just
2 moving forward, I don't have a significant bit of
3 consternation with regards to Mr. Sterling reading that
4 paragraph, recognizing the objection that was brought in
5 by Mr. Howell and also understanding that Mr. Sterling
6 was not the author of this, so if it helps us move
7 forward and we could hear your lovely voice attached to
8 those words which are not yours, let's go ahead and do it
9 and let's move on.
10 THE WITNESS: "Kootenai Electric's proposed
11 transaction is a blatant manipulation of PURPA's rules
12 and regulations by a QF developer in order to financially
13 profit to the direct and substantial detriment of Idaho
14 Power's customers. Kootenai states in its demand letter
15 to Idaho Power that it has attempted to obtain an Idaho
16 QF contract with Avista, but has 'reached an impasse
17 which would require litigation to resolve.' Attachment
18 1, page 2. Thus, Kootenai Electric seeks out any
19 strained argument it can find to try to avoid addressing
20 the real problems associated with obtaining a QF contract
21 in the jurisdiction where both its project is located and
22 where it interconnects to the transmission grid.
23 Kootenai Electric's proposed transaction stretches the
24 bounds of legitimacy, and such manipulation has the
25 possible practical effect of saddling Idaho customers
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1 with additional costs and higher power rates which exceed
2 Idaho Power's avoided costs."
3
4 have.
5
6 Olsen.
7
8
9
10
MR. RICHARDSON: Mr. Chairman, that's all I
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. OLSEN: Yes, I have just a few questions.
CROSS-EXAMINATION
11 BY MS. OLSEN:
12 Q. Mr. Sterling, turning back to page 2 of your
13 direct testimony, you've already talked a lot about this
14 between the prior generic case that you had testified in
15 and with Mr. Richardson and everything, given the fact
16 that you had in the prior generic case suggested a
17 five-year contract term and are also suggesting, I
18 believe, if I understand your testimony, as one of the
19 tools or one of the ways the Commission can address this
20 issue is a shorter contract term as well, you also have
21 talked about a pricing mechanism and I would just like to
22 try to, I guess, put a connecting theme here. Would it
23 be fair to say that your testimony could be summarized as
24 follows: Long-term contracts would be acceptable if
25 avoided cost pricing could be accurate over the long
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1 term; however, the avoided cost pricing is not accurate
2 over the long run and thus, some shorter mechanism must
3 be put in place to allow contract prices to be adjusted;
4 is that a fair summary of your position?
5
6
A.
Q.
Yes, I think that's a reasonable summary.
So just, again, for the record, is it your
7 position that the contract term should be limited to five
8 years as opposed to the two-year limit suggested by Idaho
9 Power and the Irrigators?
10
11
12
A. Yes.
MS. OLSEN: I have no further questions.
COMMISSIONER KJELLANDER: Thank you, and Mr.
13 Adams.
14 MR. ADAMS: Yes, I have just a few questions
15 for Mr. Sterling.
16
17
18
19
COMMISSIONER KJELLANDER: Please proceed.
CROSS-EXAMINATION
20 BY MR. ADAMS:
21
22
23
Q.
A.
Q.
Good morning, Mr. Sterling.
Good morning.
So were you here yesterday when Mr. Allphin
24 testified that a QF that signed a two-year contract with
25 Idaho Power today would not be compensated for
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1 capacity?
2
3
4
5
A.
Q.
A.
Q.
Yes, I was here yesterday.
Do you agree with that statement?
Could you repeat the statement?
That a QF that signed an IRP-based methodology
6 contract to begin deliveries in 2016 would not be
7 compensated for capacity.
8
9
10
11
A.
Q.
A.
Q.
That's true if the contract was signed today.
And how about a five-year contract?
That would still be true.
Okay. What's the date, what's the cutoff date,
12 where the QF would start getting capacity under Idaho
13 Power's current rates?
14
15
16
17
18
19
A.
Q.
A.
Q.
A.
Q.
I believe it's 2025.
Okay, and what is Avista's?
I'm not sure.
Does 2021 sound about right?
Yes.
So you testify in your direct testimony on page
20 11 regarding FERC's rules for contracts, contract length,
21 and you conclude that there's no specific requirements
22 under PURPA's regulations regarding contract length;
23 correct?
24
25
A.
Q.
That's correct.
So do you think the Commission could shorten
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- - - --- -----------------------------,
1 the contract length to be as short as the Commission
2 chose?
3 A. Yes, I do. In fact, they've done it before.
4 They've shortened contract length on multiple
5 occasions.
6
7
Q.
A.
Do you think two years would be okay?
My position or my recommendation is that it be
8 five years.
9 Q. Okay, well, I'm just asking you in the context
10 of page 11, lines 11 to 14, where you state that there's
11 no specific limit to how short it could be. I'm just
12 wondering if you think that it could be, say, one year or
13 six months or one day.
14 A. I'm just observing that the FERC rules do not
15 specify.
16
17
18
Q.
A.
Q.
So there's no limit at all in the FERC rules?
None that I see.
Would you agree that at some point we're really
19 just talking about a short-term energy only rate that the
20 QF is being paid with these shorter contract terms?
21 A. It depends on when the contract is signed. It
22 depends on the duration of the contract, and it depends
23 upon whether the utility needs capacity during that same
24 time frame, but if the utility does not need capacity
25 during the time frame or the term of the contract, then,
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1 yes, it would probably be just an energy only contract.
2 Q. Okay, and you did review the FERC regulation;
3 correct?
4
5
A.
Q.
Yes.
Okay, but isn't it true that 18 CFR
6 292.304(d) (2) provides the QF with the option to sell
7 energy or capacity over a specified term?
8
9
A.
Q.
That's true.
But the QF wouldn't be able to sell capacity
10 under the shorter term contract lengths under the
11 circumstances existing today?
12 A. What I think the FERC rules provide or require
13 is that if capacity is provided and it is needed by the
14 utility, it has some value, then the utility must pay for
15 it.
16 Q. Okay, moving on to page 17 of your testimony,
17 you discuss PURPA rules in other states and you suggest
18 that the Washington -- in Washington they only allow
19 five-year contracts. You also reference 20-year
20 contracts in Oregon, Utah, and Wyoming, and 25-year
21 contracts in Montana; do you remember that?
22
23
A.
Q.
Yes.
What did you review with regard to the
24 five-year contracts in Washington? Did you review a
25 tariff or orders?
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1 A. I don't recall reviewing anything. I think
2 that was what I was told verbally.
3 Q. Oh, okay. Did you know that PacifiCorp's
4 five-year contract term tariff in Washington provides the
5 QF compensation for energy and capacity during that
6 entire term?
7
8
10
A. I'm not aware of that, no.
MR. ADAMS: I'd like to approach the witness
COMMISSIONER KJELLANDER: Do you have both even
9 with a document, Mr. Chairman?
11 and odd pages?
12 MR. ADAMS: I think I do. I promise we have
13 both even and odd pages this time.
14
15
16 Q.
COMMISSIONER KJELLANDER: Then please proceed.
(Mr. Richardson distributing documents.)
BY MR. ADAMS: So Mr. Sterling, is this the
17 Pacific Power Schedule 37 tariff for Washington; is that
18 what this document states?
19
20
A. It appears to be, yes.
MR. ADAMS: Okay, I'd move to admit this into
21 the record as Exhibit 209.
22 COMMISSIONER KJELLANDER: Without objection, we
23 will mark and identify this as Exhibit 209.
24 MR. HOWELL: Mr. Chairman, I'm not sure a
25 proper foundation has been laid for this. This witness
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1 didn't necessarily agree that this was Schedule 37 from a
2 PacifiCorp -- from a Washington -- I'm not even sure what
3 state.
4 COMMISSIONER KJELLANDER: We have an objection,
5 so in response to that
6 MR. ADAMS: Well, yes, my response is, you
7 know, the witness did testify as to what the contract
8 term is in Washington. This is the Washington tariff.
9 To the extent that Mr. Howell doesn't believe it's an
10 authentic copy of PacifiCorp's Washington tariff, I think
11 he -- I think the witness could still review this
12 document and tell us what it states with regard to
13 whether QFs are paid for capacity for the entire
14 five-year term.
15 MR. HOWELL: Well, Mr. Chairman, I'm not sure
16 that these are the entire pages. I don't think a proper
17 foundation has been laid for this document. It's dated
18 in 2011. I'm not sure there's been any subsequent
19 updates from that.
20 MR. ADAMS: If you'd turn to the second page,
21 Mr. Howell, it's effective February 28, 2014.
22 MR. HOWELL: Well, I guess that's my point,
23 Mr. Chairman. What purports to be Original Sheet 37.1 is
24 issued in 2011 and apparently 37.2 is in 2013 and '14.
25 Again, the witness stated that he was aware only of a
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962 STERLING (X)
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1 five-year term, and I'm not sure that the proper
2 foundation has been laid for the introduction of this
3 exhibit.
4 MR. ADAMS: Well, then in that case, if the
5 exhibit won't be allowed, I would move to strike the
6 lines of Mr. Sterling's testimony stating that the
7 Washington Commission has five-year contract terms for
8 lack of foundation because the witness stated that he
9 didn't read any documents. He just heard that from
10 someone else.
11 MR. HOWELL: I think earlier in this hearing
12 Mr. Clements testified on behalf of Rocky Mountain Power
13 that Washington does indeed have a five-year PURPA
14 contract, so there is testimony in the record by another
15 witness that Washington has a five-year contract.
16 COMMISSIONER KJELLANDER: Let me jump in
17 quickly here and I appreciate the robust nature of the
18 debate that's been made amongst the two of you and also
19 the civility associated with it. Let me just ask this
20 question of you, Mr. Adams: Is there a way without
21 putting this in play to go ahead and ask the specific
22 question you want to get to to get to the end game?
23
24
25 okay?
MR. ADAMS: Yes, that would be fine.
COMMISSIONER KJELLANDER: Then let's do that,
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1 Q. BY MR. ADAMS: Mr. Sterling, could you turn to
2 the second page of the document?
3
4
A.
Q.
I'm there.
What does it state after the number 7 there,
5 the avoided cost rates?
6 A. After avoided cost rates there's a table with
7 three columns. Two of the columns say capacity payments
8 by year; the third column is energy payments by year.
9 Q. And each year has a capacity payment beginning
10 2014; is that correct?
11
12
13
A. That's correct.
MR. ADAMS: Okay, no further questions.
COMMISSIONER KJELLANDER: Thank you.
14 Mr. Miller.
15 MR. MILLER: Mr. Chairman, I'm confident that
16 my intervenor colleagues are going to possibly plow as
17 much ground as can be plowed with this witness, so I
18 don't have any questions.
19
20 Otto.
21
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. OTTO: Thank you, Mr. Chairman. I do have
22 just a few questions.
23
24
25
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1
2
3 BY MR. OTTO:
CROSS-EXAMINATION
4 Q. So Mr. Sterling, you testified in your writings
5 and here today that you're the lead Staff person on PURPA
6 issues and the avoided cost model as part of that; is
7 that correct?
8
9
A.
Q.
Yes, it is.
And is it your understanding that under this
10 model, the capacity payments begin when the utilities
11 identify a resource deficiency date?
12
13
A.
Q.
That's correct.
Is it your understanding that the energy
14 component is based on the utility's incremental avoided
15 cost in each hour?
16
17
A.
Q.
Yes.
Thank you. You also testified in writing and
18 here today that the real risk is about thousands of
19 megawatts of proposed QFs; is that correct?
20
21
A.
Q.
Yes.
Did you observe the Idaho Power IRP
22 development?
23
24
A.
Q.
The 2015?
The 2015 development. This may help.
25 Specifically the day where Mr. Allphin explained PURPA to
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1 the IRP advisory committee, were you there that day?
2 A. I don't recall specifically, but I think I only
3 missed one meeting and I don't believe that was the
4 meeting you're talking about, so I think I was there,
5 yes.
6 Q. Okay, and how does the -- does the IRP, Idaho
7 Power's IRP, does it forecast future PURPA development?
8
9
10 not?
11
A.
Q.
A.
No.
And why not? What's your understanding of why
Because the IRP process is a planning process
12 for the utility to determine how its -- how the best way
13 to meet anticipated load is, and it in planning has to
14 rely on what it knows it can count on, and when it comes
15 to PURPA projects, they take what comes, whether it comes
16 or whether it doesn't come, when it comes, however much
17 comes. It's not within the control of the utility and so
18 the utility doesn't plan for it.
19 Q. So what I heard you say is that in the IRP,
20 they can't count on any future development; is that what
21 you just said?
22
23
A.
Q.
Generally, yes.
But in this case your position is it's almost a
24 certainty that these thousands of megawatts will come
25 on line?
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1
2
3
4
A.
Q.
A.
Q.
I haven't stated that.
It's the risk that that will happen?
That's true, yes.
Now, turning to your direct testimony on page
5 2, lines 18 through 24, you say that it's -- well, let's
6 make sure we get this right. Oh, I have it right here.
7 You say you don't believe that any avoided cost
8 calculation can prove to remain accurate over a 20-year
9 period. Do you see that?
10 A. Yes, I do.
11 Q. And you stand by that?
12 A. Yes, I do.
13 Q. On page 9 in lines 12 through 16, actually all
14 the way through 19, you cite to several power purchase
15 agreements. Do you see that?
16
17
A.
Q.
Yes.
Do you know the term of those power purchase
18 agreements?
19 A. I don't recall with each specific project
20 mentioned, but it's either 20 or 25 years.
21
22
23
24
25
Q.
A.
Q.
A.
Are those fixed price contracts?
Yes, I believe they are.
And do you believe those benefit ratepayers?
Yes, I do.
MR. OTTO: Thank you. That's all.
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1 COMMISSIONER KJELLANDER: Okay, I guess I'm
2 just not used to hearing the word thank you, I appreciate
3 that. Mr. Sanger.
4
5
6
7
8
9
10
11
MR. SANGER: No questions, Chairman.
COMMISSIONER KJELLANDER: Thank you.
MR. SANGER: You're welcome.
COMMISSIONER KJELLANDER: Mr. Hammond.
MR. HAMMOND: Just a couple, Mr. Chairman.
CROSS-EXAMINATION
12 BY MR. HAMMOND:
13 Q. You testified to the thousands of potential
14 megawatts that have been or projects that are seeking to
15 come online. How many of those projects at this point
16 have come online?
17
18
A.
Q.
Thirteen, I believe.
Thirteen? And how much do they represent? How
19 many megawatts do they represent?
20 A. Well, the 13 projects collectively represented,
21 I believe, 461 megawatts, and four of those 13 have since
22 been terminated and those four, I believe, are 160
23 megawatts collectively.
24 Q. And maybe I should clarify, maybe I'm not
25 understanding. I guess when I'm saying online, they're
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1 delivering power to the utilities.
2
3
4
5
A.
Q.
A.
Q.
I'm sorry, I misunderstood.
I'm sorry.
None of them are yet online.
So at this point there's no megawatts being
6 delivered on these thousands of proposed projects; is
7 that correct?
8
9
A.
Q.
That's correct.
Okay. We've heard a lot of testimony and
10 positions made in this case about sort of what is
11 believed to be a balancing of PURPA, that PURPA is -- the
12 Commission is supposed to encourage the development of
13 these projects through PURPA, but, on the other hand, the
14 utilities have expressed the principle, and maybe I'm
15 saying things inaccurately, but ratepayers should be
16 indifferent to PURPA power coming online, they shouldn't
17 be paying too much; is that a fair assessment of the
18 testimony you've heard?
19
20
A.
Q.
Yes.
On page 2, you've made the point, page 2 of
21 your direct testimony on line 14, starting at line 14
22 through line 17, you make the point that long-term
23 contracts, by themselves, would not necessarily be
24 problematic; is that correct?
25 A. That's correct.
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1 Q. Would a fair and balanced way to deal with
2 PURPA to address the Commission's duty or obligation to
3 encourage PURPA development, while at the same time
4 providing a mechanism by which ratepayers will be held
5 indifferent, if prices -- if you updated avoided cost
6 prices on a more frequent basis, could that address that
7 concern and provide that balancing by itself of those two
8 goals?
9
10
11
A.
Q.
A.
Let me clarify your question a bit.
Sure. Thank you, I'm sorry.
When you say update the avoided cost prices,
12 are you talking about updating prices periodically in an
13 existing contract or for new contracts going forward?
14
15
Q.
A.
Either one, either scenario.
Well, we do already and have for many years
16 updated avoided cost rates going forward as they would
17 apply to new contracts, but once a contract has been
18 signed, those contracts do not get changed, at least
19 modern contracts do not get changed, for the term of the
20 contract. If we had a mechanism in an existing contract
21 to periodically update those rates, that could perhaps
22 resolve some of the problems that we have now.
23 MR. HAMMOND: Thank you very much. I have no
24 further questions.
25 COMMISSIONER KJELLANDER: Thank you, Mr.
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1 Hammond. Ms. Nunez.
2 MS. NUNEZ: Thank you, Mr. Chair, I do have a
3 few questions.
4
5
6
7 BY MS. NUNEZ:
CROSS-EXAMINATION
8
9
10
Q.
A.
Q.
Good morning, Mr. Sterling.
Good morning.
Based on your 20 plus years of experience
11 working in PURPA pricing and risk assessment, can you
12 please comment on how the Commission and the utility
13 companies have analyzed the environmental harms of energy
14 production, such as air and water pollution, habitat
15 degradation, and climate change in the context of risk
16 assessment and pricing analysis?
17 A. Well, we don't do any risk analysis as part of
18 PURPA pricing and we do not also include any of the other
19 things that you mentioned in consideration of PURPA
20 prices.
21 Q. Do you believe that the Commission has
22 authority to consider the risks and costs associated with
23 such environmental consequences when they're acting in
24 the public interest?
25 MR. HOWELL: Mr. Chairman, I'm going to object
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1 to the question as being beyond the scope of this
2 witness' direct and rebuttal testimony. He's already
3 testified there's no testimony in his prefiled rebuttal
4 or direct that discusses environmental issues with the
5 pricing of avoided costs.
6 COMMISSIONER KJELLANDER: Thank you,
7 Mr. Howell. Ms. Nunez, can you direct the witness to a
8 page or a line number?
9 MS. NUNEZ: The scope of my questioning is
10 about the full gamut of the risks to Idaho ratepayers
11 when making decisions about the type of energy generation
12 that utility companies will be doing in the future, so it
13 is linked to his testimony in the sense that he has
14 experience working with the Commission and the utility
15 companies on risk assessment and PURPA decisions, so
16 that's the link. I'm not alleging that there's anything
17 about environmental issues in his testimony.
18 MR. HOWELL: And I would renew my objection.
19 This witness has already testified that avoided cost
20 rates do not include any cost-benefit analysis or the
21 balancing of environmental issues in the calculation of
22 avoided cost rates.
23 COMMISSIONER KJELLANDER: And I'm inclined to
24 agree with Mr. Howell in this one. Ms. Nunez, if there's
25 a way to get at the questioning that you want if you
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1 could direct the witness to a page number and lines
2 within his testimony, that would be greatly
3 appreciated.
4 MS. NUNEZ: I actually did get the answer to my
5 question, which is that these environmental harms aren't
6 included in the conversation.
7 COMMISSIONER KJELLANDER: Well, fair enough.
8 Let's move on, then. Is that it?
9 MS. NUNEZ: That's it.
10 COMMISSIONER KJELLANDER: Thank you.
11 Mr. Arkoosh.
12
13
14
15
MR. ARKOOSH: No, thank you, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Schmidt.
MR. SCHMIDT: No, thank you.
COMMISSIONER KJELLANDER: Are you regretting
16 that you showed up here?
17 MR. SCHMIDT: No, I'm enjoying it. I wish I
18 would have been here yesterday. This is a very nice
19 atmosphere and I enjoy being here.
20 COMMISSIONER KJELLANDER: Well, we hope you can
21 find your way back.
22
23
24
25
MR. SCHMIDT: That remains to be seen.
COMMISSIONER KJELLANDER: Idaho Power.
MR. WALKER: Thank you, Mr. Chairman.
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14 above that?
5 Washington tariff sheet that was presented to you. Do
CROSS-EXAMINATION
no, strike that. On page 2, Mr. Sterling,
Yes, I do.
And on page 2 -- well, first of all, on the
Mr. Sterling, I'd just like to follow up on the
Do you see No. 7 under the terms and conditions
Yes, I do.
A.
A.
Q.
Q.
Q.
front page 9
7
2
1
4
8
3 BY MR. WALKER:
6 you still have that with you?
12
13
10 do you see this is where counsel previously had you read
11 the avoided cost rates? Do you recall that?
15 MR. ADAMS: Mr. Chairman, I'm going to object
16 to this. This is not cross-examination. This is more in
17 the form of redirect examination. It's more along the
18 lines of friendly cross, I think. I was pretty limited
19 in what I was allowed to ask, so I don't think it's fair
20 for Mr. Walker to follow up with questions himself. Mr.
21 Howell could, I suppose.
22 COMMISSIONER KJELLANDER: Mr. Walker, having
23 not heard your question, it's difficult for me to assess
24 whether it's friendly cross, but as I recall, it was a
25 very limited response that Mr. Sterling had to a question
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974 STERLING (X)
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1 in which he read a specific line. Can you attach it to
2 that specific response?
3 MR. WALKER: Yes I was simply going to ask him,
4 Mr. Chairman, to read the numbered item 7 on that same
5 page that counsel had him read from in response to his
6 question.
7
8
COMMISSIONER KJELLANDER: I'll allow that.
THE WITNESS: "The avoided cost rates are fixed
9 for five years. However, these rates are recalculated
10 every year and applicable to any seller that enters into
11 a power purchase agreement with PacifiCorp in that year."
12 COMMISSIONER KJELLANDER: Does that conclude
13 your questioning?
14
15 Q.
MR. WALKER: I have one follow-up question.
BY MR. WALKER: Mr. Sterling, is there -- you
16 read the capacity and energy payments, is there any
17 indication here of what the utility's capacity
18 sufficiency or deficiency position was to establish these
19 rates?
20 A. Not that I can see, but, you know, this is a
21 Washington tariff that has no standing in Idaho.
22
23
24
25
MR. WALKER: I have no other questions.
COMMISSIONER KJELLANDER: Thank you. Avista.
MR. ANDREA: One question, Mr. Chairman.
COMMISSIONER KJELLANDER: If you could move a
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1 microphone closer to you. Thank you.
2
3
4
5 BY MR. ANDREA:
CROSS-EXAMINATION
6
7
8
Q.
A.
Q.
Good morning, Mr. Sterling.
Good morning.
I just want to follow up, also, on the
9 questioning on the Washington PURPA rates. It was
10 suggested that, and I don't really know because I don't
11 have the tariff sheet, PacifiCorp does include capacity
12 payments in its Washington five-year contracts. Are you
13 aware that Avista does not include a capacity payment in
14 its five-year Washington PURPA contracts?
15 MR. ADAMS: I'm going to object it's beyond the
16 scope and potentially friendly cross. I don't know what
17 Mr. Andrea is trying to --
18 COMMISSIONER KJELLANDER: I'm very much
19 inclined to agree. I appreciate the questioning, but it
20 certainly does sound like something that would be better
21 addressed in redirect.
22 MR. ANDREA: That's fine, Mr. Chairman. I was
23 just trying to have a complete record as to the
24 Washington rate, but I withdraw the question. Thank
25 you.
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1
2 thank you.
3
4
COMMISSIONER KJELLANDER: I appreciate that and
MR. ANDREA: No further questions.
COMMISSIONER KJELLANDER: Thank you. Let's
5 move to Rocky Mountain Power.
6 MS. HOGLE: Rocky Mountain Power has no
7 questions. Thank you.
8 COMMISSIONER KJELLANDER: Are there questions
9 from the Commission?
10
11
12
13
COMMISSIONER RAPER: I have just one.
EXAMINATION
14 BY COMMISSIONER RAPER:
15 Q. I'm going to ask Mr. Sterling to speculate and
16 see if my former boss Mr. Howell wants to object to my
17 question to the witness. Mr. Sterling, on page 11 of
18 your direct, line 7, there's a sentence that begins,
19 "Long-term contracts based on forecasted rates create
20 greater risks for customers because the rates in the
21 later years are not reflective of avoided costs"; so my
22 question to you based on that statement is, don't you
23 believe that FERC took into account those considerations
24 of long-term contracts when it talks about
25 underestimations and overestimations eventually balancing
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1 out?
2 A. I believe that it did, although I still would
3 submit that neither PURPA nor FERC's rules implementing
4 PURPA specify contract length, so while FERC may have
5 contemplated overestimations and underestimations of
6 avoided cost rates, we don't know whether those
7 overestimations or underestimations would be for a period
8 of one year, two years, five years, 20 years, 30 years,
9 but yes, I do think they thought about overestimations
10 and underestimations and whether in fact they would
11 balance out or not.
12
13
COMMISSIONER RAPER: Thank you. That's all.
COMMISSIONER KJELLANDER: Thank you. There
14 being no further questions from the Commissioners, we
15 move now to redirect. Mr. Howell.
16 MR. HOWELL: Thank you, Mr. Chairman.
17
18
19
20 BY MR. HOWELL:
REDIRECT EXAMINATION
21 Q. Mr. Sterling, do you have what's been marked as
22 Exhibit 209 in front of you?
23
24
25
A.
Q.
A.
Is it a --
The Washington tariff Schedule 37.
Yes, I do have that.
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1 Q. All right, and could you look at the first page
2 of that under the paragraph labeled "Availability"?
3 MR. ADAMS: Mr. Chairman, I'm going to object
4 again. I think this is beyond the scope of what I was
5 allowed to ask and it was not admitted as an exhibit
6 either over Mr. Howell's objection, so to go beyond the
8 MR. HOWELL: Mr. Chairman, I don't think it's
9 beyond the scope. Whether it's admitted or not, there
7 scope of the questions I asked, I think, would be unfair.
10 was cross-examination on this specific exhibit that is
11 purportedly a Pacific Power tariff schedule and so I
12 think I'm within my rights to ask upon redirect about
13 this specific tariff.
14 COMMISSIONER KJELLANDER: I appreciate that and
15 I guess that's the risk you run of bringing a document in
16 on the last day, so I'm going to allow the question.
17
18 Q.
MR. HOWELL: Thank you, Mr. Chairman.
BY MR. HOWELL: So Mr. Sterling, turning your
19 attention to what, I guess, purports to be the front page
20 under the heading "Availability"
21
22
A.
Q.
I see that, yes.
if you were to read that, doesn't this
23 tariff apply to cogeneration/small power production of
24 less than two megawatts or two megawatts or less?
25 A. It appears that way, yes.
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1 Q. So for purposes of IRP in Idaho, would this
2 tariff be applicable to IRP methodology calculations?
3
4
A.
Q.
It could apply to a small number of projects.
And turning over the page on the avoided cost
5 rates, there's no indication, is there, about whether
6 Pacific Power was in in a surplus capacity situation, is
7 there?
8
9
A.
Q.
There's no indication on the tariff, no.
Finally, Mr. Richardson asked you about your
10 criticism of Dr. Reading's Chart No. 1 and the
11 calculations by including Idaho Power's peaker plants in
12 the power costs. Do you recollect that testimony?
13
14
A.
Q.
Yes, I do.
Isn't it true that that was not your only
15 criticism of Dr. Reading's Chart No. 1?
16
17
18
A.
Q.
A.
Yes.
And what was your other criticism?
Well, I think my other criticism related to the
19 fact that you can't just compare costs between resources
20 that way. Under the IRP methodology, the modeling looks
21 at an hourly dispatch of all the resources in the
22 utility's fleet. In some hours, a QF may be displacing a
23 coal plant. In other hours, it may be a different coal
24 plant. In other hours, it may be a gas plant. In other
25 hours, it may be a peaking gas plant. In other hours, it
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1 may be market purchases, so it's a whole collection of
2 resources that go into the determination of avoided cost
3 rates under the IRP methodology, and to compare very
4 different resources with very different capacity factors,
5 very different operating circumstances is just not a
6 valid comparison.
7 Q. And to drill down on your answer, wasn't one of
8 your criticisms that this chart omitted any costs from
9 the Company's hydro generation?
10
11
A. Yes.
MR. HOWELL: Thank you, Mr. Chairman. I have
12 no further questions.
13 COMMISSIONER KJELLANDER: Thank you,
14 Mr. Howell, and that completes our witness list for this
15 case.
16 (The witness left the stand.)
17 COMMISSIONER KJELLANDER: As I mentioned
18 yesterday, it would be my hope that there would not be a
19 request for briefs on this case; instead, we would have
20 some closing statements. Does anyone have another
21 approach that they would like to take? Is anyone bent
22 directly on the path of wanting to file briefs and feel
23 comfortable that we could do it through the approach of
24 closing statements? Good. With that in mind, would it
25 be appropriate to perhaps take a ten-minute recess to
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Staff
1 allow people to gather their thoughts, and just before we
2 break, if I could briefly just get a quick show of hands
3 from those who want to be included in that process so I
4 can kind of guesstimate when to tell my friends that I'd
5 like to have lunch. I'll tell them tomorrow. Fair
6 enough, we will go off the record and return in ten
7 minutes.
8 (Recess.)
9 COMMISSIONER KJELLANDER: Well, welcome back.
10 We'll go back on the record. Even if you didn't raise
11 your hand that you want to make a closing statement,
12 we're going to go through and allow everybody an
13 opportunity to get there. The only privilege of being a
14 former Commissioner and now being legal counsel
15 representing clients before us is that we either really
16 like you or just want to get you out of here, so let's
17 start with Mr. Miller.
18 MR. MILLER: Thank you, Mr. Chairman. I guess
19 I would note that I noticed this morning that the
20 Commission's policy on payment for coffee doesn't seem to
21 exclude former Commissioners.
22 COMMISSIONER KJELLANDER: But it's a fully
23 embedded service.
24 MR. MILLER: Thank you very much for the
25 accommodation. By way of introduction, let me point the
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1 Commission to the fact that we have filed the testimony
2 of Mr. Van Gulik in this case who provides a
3 feet-on-the-ground perspective regarding the difficulties
4 of developing PURPA solar projects and the current status
5 of the viability of that market at current prices.
6 No party filed any testimony rebutting Mr. Van
7 Gulik's testimony and no party cross-examined Mr. Van
8 Gulik in any serious way yesterday, so rather than review
9 that testimony with you here, I would just ask that
10 during the course of your deliberations you again review
11 Mr. Van Gulik's unrebutted testimony.
12 Second, I appreciated the Chairman's
13 explanation to the public the other night at the public
14 hearing where the Chairman explained that the Commission
15 approaches cases such as this in a judicial way; that is,
16 that its decision must be based on evidentiary facts in
17 the record such that any decision would be sustainable as
18 based on substantial and competent evidence, so
19 approaching that case -- approaching that case in this
20 way, the first question obviously is who has the burden
21 of proof, and the answer to that is obvious; that is, it
22 is the utility companies' burden to introduce into the
23 record sufficient facts to justify a departure from a
24 long-standing policy of the use of deployment of 20-year
25 contracts.
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1 The policy was upheld just two years ago
2 despite requests to change it then. Of course, the
3 Commission is not bound strictly by stare decisis, but at
4 the same token, any change from existing policy has to be
5 based on facts that are in the record before the
6 Commission, so what are the relevant facts that are
7 before you as the result of this hearing?
8 The first relevant fact is that a two- to
9 five-year contract would bring renewable development
10 under PURPA to a halt. 1Mr. Van Gulik's testimony on this
11 point is unrebutted. Several other witnesses made the
12 same point. The utility companies and the Staff don't
13 contest this fact, because that is their intended result.
14 Although there was some testimony that some QF projects
15 such as existing industrial gas plants might be able
16 to -- might prefer shorter contracts, there is absolutely
17 no evidence in the record to rebut the point that
18 two-year, two- or five-year, contracts would bring new
19 renewable development under PURPA to an end, so what are
20 the other facts that are in the record that bear on this
21 issue?
22 The first fact is that currently there are zero
23 megawatts of renewable solar PURPA online and producing
24 power to Idaho Power Company. Ms. Grow confirmed that on
25 cross-examination. What are the other relevant facts?
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1 They can be derived from Exhibit 11. Page 2 of Exhibit
2 11, if you have it with you, shows that from January
3 through April of 2015, the number of renewable megawatts
4 under contract has declined rather than increased. The
5 number of renewable megawatts under contract went from
6 401 to 260.
7 The other relevant facts disclosed by Exhibit
8 11 are on page 3, and this is really the heart of the
9 utility companies' case and exhibit -- page 3 is a list
10 of PURPA projects that the Company has labeled as
11 proposed solar, but if you go beneath the surface of this
12 exhibit, certain other facts emerge as disclosed by Mr.
13 Adams' very professional cross-examination yesterday and
14 my meager efforts at cross-examination, but the facts
15 that emerge when you go beneath the surface are that of
16 the 47 projects listed here, only 14 provide enough
17 information to even reach stage one of the Idaho Power
18 contracting process. Of those, only two received
19 indicative pricing for 20-year contracts.
20 Mr. Allphin indicated in his testimony that
21 perhaps one had gone to the stage of actually requesting
22 a contract, but zero of these projects entered into
23 serious negotiations and ever executed a final and
24 binding contract. Mr. Allphin resisted my efforts or
25 suggestion that perhaps this exhibit should be, which is
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1 labeled proposed PURPA should be, somehow relabeled to be
2 an more accurate reflection. I would suggest the best
3 better label for this exhibit would be a list of tire
4 kickers. That's a legal term.
5 The next fact that is, I think, undisputable is
6 that the IRP method as it currently works is
7 self-correcting; that is, it is producing prices such
8 that the demand for solar PURPA projects is decreasing as
9 previous projects come online. Mr. Chairman and Members
10 of the Commission, Senator Patrick Moynihan was famously
11 quoted to saying, "You're entitled to your own opinion,
12 but you're not entitled to your own facts," and if you
13 want to put a bipartisan tone on it, President Reagan was
14 famously quoted as saying, "Facts are stubborn things,"
15 and the facts as they exist in this record are
16 insufficient to support a change in policy that has been
17 in place for many years.
18 The utilities have the burden of proof and they
19 have failed to carry their burden of proof. Those are my
20 meager thoughts.
21 COMMISSIONER KJELLANDER: Thank you,
22 Mr. Miller. Mr. Olsen.
23 MR. OLSEN: We have a few comments. As the
24 Irrigators, we're obviously a big consumer of this
25 electricity. We're not producers of the PURPA projects,
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1 and one thing that's troubling to us and what was pointed
2 out in Mr. Yankel's testimony is that it doesn't appear
3 that certain resources would be necessary at this point
4 in time and the Company would be forced to buy the output
5 of these projects, notwithstanding the fact that they're
6 not needed, and herein lies the crux, I think, of the
7 issues is this policy issue needs to be addressed by the
8 Commission, because to require the forced purchase of
9 this, notwithstanding it's not needed in their resource
10 stack, I think is not logical or fair, just, and
11 reasonable to the Idaho ratepayers, and so we would
12 encourage the Commission to look at all the factors that
13 have come out in these proceedings and rule what you
14 think would be fair, just, and reasonable. Thank you.
15
16 Schmidt.
17
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. SCHMIDT: Thank you. There is a reason I
18 came. I did want to get on the record why Micron is
19 participating, but let me first say what we're not doing.
20 We're not here to oppose or support any particular
21 project, whether it be a cogeneration project or a solar
22 project, but we are here merely as a customer. We're the
23 largest customer on Idaho Power's system and the cost of
24 buying power from Idaho Power is a significant operating
25 cost to us. We don't typically participate in these
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1 cases unless we perceive or see that that cost may be
2 affected and we're asking that you at least take into
3 consideration the impact that your decision in this
4 docket may have on that cost.
5 Now, as I have reviewed the record and,
6 fortunately, my partner who was here yesterday, sent me
7 about 35 pages of notes, so I think I followed most of
8 the cross-examination in intimate detail, maybe more than
9 I wanted to at 11:00 o'clock last night, but as I look at
10 the record in this case, it seems to me that you have a
11 couple of important decisions to make. One is -- the
12 main one is the length of the contract term.
13 I had initially intervened in this case
14 thinking there may be a lot more attention or interest in
15 the calculation of the rate and how avoided cost is done,
16 because I'm not here to tell you that your method is
17 wrong or inaccurate, but my experience shows that there's
18 a lot of other ways that it can be done and they're all
19 perceived as fair, so there is a lot of discretion that
20 this Commission has under PURPA, even though PURPA is a
21 federal mandate.
22 I've been working on PURPA-type cases for over
23 three decades, but PURPA does not mandate the actual
24 contract term that you need to implement. That is within
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25 your discretion. Whether you choose 20 or whether you
1 choose five or even as low as one, I think in this record
2 maybe you can only go as low as two, but I think that's
3 up to you, and it should be based upon what you believe
4 is in the best interests of not just the utilities and
5 the developers who are all here who want to build more
6 projects, but also the customers that you have to look
7 out for as well, and I'm pleased to hear there is another
8 customer represented in the room.
9 I thought we were one of the only ones and
10 that's why Micron wanted to participate is we wanted to
11 make sure that you don't lose sight of customer effect in
12 your decisions here, because PURPA does have effects.
13 It's intended, and I think the last witness who testified
14 made this clear even through the cross-examination, the
15 customers are supposed to be indifferent and indifferent
16 means PURPA should not hopefully in the short term and
17 certainly not in the long term cause us to pay higher
18 costs. It's intended to avoid costs that we otherwise
19 would have to pay that the utility incurs. That's the
20 concept of avoided costs. It's a very simple concept.
21 It's a very logical concept, but it gets messy in the way
22 in which you implement the specifics of it.
23 Now, the facts are we have an excess capacity
24 situation. When there is excess capacity, you would not
25 let Idaho Power build another power plant, you should
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1 not, because capacity is not needed. In those
2 circumstances, hopefully, you didn't get too far
3 overcapacity, but as we know, capacity is lumpy
4 sometimes, so we just added into the system Langley Gulch
5 just a few years ago and Langley Gulch has put us in a
6 very nice situation. The circumstances in the region
7 also have us in a very nice circumstance. Customers
8 should benefit from that. Why? Because they paid for
9 Langley Gulch to go into their rates and it impacts our
10 rates.
11 Secondly, we know that the rates that are
12 recovered by PURPA projects are passed through dollar for
13 dollar, so the utility doesn't profit on that, which I
14 think is appropriate policy and it's consistent with most
15 of the states in the country in the way they handle these
16 type of contracts, but to pass through -- therefore, it
17 passes through not just energy, but energy and capacity,
18 costs through your annual adjustment mechanism.
19 Customers like Micron are high load factor customers, so
20 they pay one could argue a disproportionate share of
21 that, but they pay more in their rates because they are a
22 high load factor customer for that portion of the rates
23 than they do as other portions of the rates change over
24 time and less frequently, so we're not saying that we
25 think there's an obvious decision here that you should
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1 make that dictates one result or another.
2 We think it's solely within your discretion and
3 we would only ask that you make sure you consider what
4 the impact can be on customers, particularly in the near
5 term, because every time you change a rate that impacts a
6 customer like Micron maybe five percent, that's going to
7 impact over millions of dollars of our operating costs.
8 That will affect Idaho's economy. That will affect our
9 ability to hire more employees or continue with the labor
10 force we have. A lot of other factors come into that,
11 but energy is a big one and that's why we're here.
12 We care about whether our costs are going to
13 stay stable, so I don't know if the record in this case
14 makes clear enough what the impact on our rates will be,
15 but I do know from experience that if you add capacity
16 into rates when capacity is not needed, at least in the
17 near term, you end up paying higher costs.
18 If you generate power when other power has to
19 be avoided or not used because it can't be dispatched,
20 you impact costs, so if those costs are going to be
21 impacted severely, we ask that you take that into
22 consideration in making a decision whether you continue
23 with your policy of whether this is the time to continue
24 with a 20-year contract term or not. Thank you.
25 COMMISSIONER KJELLANDER: Thank you.
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1 Ms. Nunez.
2 MS. NUNEZ: Thank you. The Snake River
3 Alliance believes that a decision by the Commission to
4 halt the development of renewable energy exposes Idaho
5 ratepayers to economic risks that have not been
6 adequately analyzed. The testimony of Ken Miller
7 elaborates on the discussion that we think needs to
8 happen, especially when defining what Idaho needs.
9 We believe that the technical and political
10 issues associated with integrating large amounts of
11 renewable energy are resolvable by the many brilliant
12 minds we have in this state. We encourage ambition and
13 optimism and an accelerated commitment to a clean energy
14 future for Idaho. We thank everyone for holding the
15 space and offer our support in this important process.
16 Thank you.
17
18 Sanger.
19
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. SANGER: Thank you, Commissioners. For the
20 record, my name is Irion Sanger. I'm the attorney for
21 Renewable Energy Coalition and Renewable Energy Coalition
22 recommends that any relief you adopt in this proceeding
23 not apply to QFs under the rate eligibility cap; in other
24 words, contract terms should not be reduced for QFs,
25 solar and wind QFs, 100 kilowatts and below and any other
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1 QF 10 megawatts and below.
2 While REC has concerns about the allegations
3 raised by the utilities in their filings, we do commend
4 Idaho Power for not recommending that contract terms be
5 reduced for small QFs. Avista also is not facing a large
6 amount of PURPA development and we understand that their
7 position is primarily that they want whatever relief is
8 provided to Idaho Power Company and Rocky Mountain Power.
9 Therefore, you have both Avista and Idaho Power which are
10 either supporting our view that you don't extend any
11 relief to small QFs or not opposing that. Also, Staff
12 has recommended that small projects not have their
13 contract terms reduced.
14 The only party in this proceeding that has a
15 different view is Rocky Mountain Power. Now, we
16 recommend that Rocky Mountain Power's proposal be
17 rejected because they have not provided any evidence to
18 meet their burden of proof that any of their problems are
19 being caused by small projects, nor have they provided
20 any evidence that ratepayers will be better off if you
21 reduce the contract terms for small QFs.
22 Now, as explained in the testimony of the
23 Coalition's witness John Lowe, most existing projects on
24 the system right now are small hydroelectric projects
25 well under the size threshold for published rates. Now,
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1 the utilities rely upon these projects to provide needed
2 energy and capacity. They include them in their
3 integrated resource plan and they provide significant
4 seasonal benefits to the utilities as well as being major
5 parts of the Idaho agricultural economy and the local
6 communities in which they operate in.
7 Now, I think the record is pretty clear that
8 these small QFs under the rate eligibility cap are not
9 causing any of the problems that have been alleged in
10 this proceeding. Essentially, we would not be here if
11 there was not a large amount of proposed solar
12 development. This proceeding would not exist.
13 Now, Paul Clements, Rocky Mountain Power's
14 witness, stated in his rebuttal testimony that the
15 primary concern of Rocky Mountain Power that led to its
16 position is that currently it has tons of proposals for
17 new QF projects to provide power that is not needed to
18 meet the customers needs. Mr. Clements also has his
19 Exhibit 601 which identified 89 new proposed projects.
20 As he explained yesterday, there's only one of those
21 projects in Idaho, which is not a wind or solar project,
22 and there's only two projects which are not wind and
23 solar proposed projects in the entire six-state service
24 territory; therefore, there's no allegations that
25 non-wind and solar or small projects are causing any
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1 harm.
2 Mr. Clements' rebuttal testimony also did not
3 respond to Renewable Energy Coalition witness testimony,
4 did not respond to John Lowe's allegations and
5 discussions of the harms that would be caused by
6 shortening the contract term for small projects or why
7 small projects are not causing any of these difficulties;
8 therefore, we simply don't believe that Rocky Mountain
9 Power has submitted evidence to support the breadth of
10 its recommendation in this proceeding, and we don't at
11 least as it applies to Rocky Mountain Power, we don't see
12 their petition as a thoughtfully thought-out proposal to
13 protect its ratepayers. Instead, it seems to be part of
14 an overall strategy to reduce its PURPA obligations.
15 The parent company, Berkshire Hathaway, is
16 trying to repeal PURPA at the federal level. PacifiCorp
17 has proceedings in nearly all of its states that are
18 either initiated or completed trying to reduce its PURPA
19 obligations, so we think the Commission should consider
20 this overall strategy of PacifiCorp and Rocky Mountain
21 Power when looking at the breadth of their proposal.
22 Now, the Coalition recognizes that there's an
23 unprecedented and unique circumstance here with all of
24 the new solar development proposals and we recognize the
25 Commission may want to take some sort of action in this
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1 proceeding. We don't necessarily agree with all of the
2 recommendations made by the utilities, but we do believe
3 there is a legitimate issue here.
4 Our recommendation would be that the Commission
5 open a generic proceeding to investigate these issues.
6 The utilities have framed this as proposing only one
7 potential solution and there could be other potential
8 solutions that would address things better. One of the
9 main issues that people have discussed is the question of
10 need. What do you do when a utility doesn't need new
11 projects? Well, shortening the contract term can reduce
12 the number of projects, but it doesn't really get at the
13 heart of the key issue that the utilities keep bringing
14 up, so we would recommend that you open a proceeding up
15 and look at these issues more broadly and try to think of
16 different sorts of solutions, weigh them, and then decide
17 which solution best meets the problems that the utilities
18 are facing.
19 If the Commission is going to take action based
20 on the record here, however, we do recommend that any
21 relief that you guys decide to adopt not apply to small
22 projects under the rate eligibility cap. Thank you very
23 much.
24 COMMISSIONER KJELLANDER: Thank you. Mr.
25 Richardson.
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1 MR. RICHARDSON: Mr. Chairman, thank you.
2 Commissioner Kjellander, Commissioner Raper, appreciate
3 your patience and indulgence in hearing us out today and
4 yesterday. I'm handing out a page from Rocky Mountain's
5 petition in this matter, page 20, just for ease of
6 reference so you don't have to dig it out, and as they
7 say, a picture is worth a thousand words, and I think
8 this graph on Rocky Mountain's page 20 of its petition
9 speaks very loudly. It shows all the potential projects
10 that Rocky Mountain is facing in its different
11 jurisdictions.
12 Of course, California is blank because it's
13 under an RTO and the must-buy provisions of PURPA do not
14 apply in California. All the other jurisdictions that
15 Rocky Mountain operates in have potential projects,
16 except for notably one and that's the State of
17 Washington, zero wind, zero solar, zero other, zero
18 total, and we know Rocky Mountain operates in Washington
19 State and Washington State has a tariff, Exhibit 209. It
20 shows that QFs get paid capacity and energy, but no QF
21 has been successful in Washington State, and what's the
22 controlling factor there is they have a five-year
23 contract, so I think the evidence is pretty clear that if
24 you go to a five-year contract, you are going to kill the
25 QF industry in the State of Idaho, and you need look no
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1 further than the State of Washington and their
2 implementation of PURPA.
3 Clearwater Paper Corporation is Avista's
4 largest customer and we appreciate our relationship with
5 Avista and value it very highly, but we're also kind of
6 like the largest creditor or bank. We need the bank to
7 be healthy and we need the creditor to be healthy. It's
8 a symbiotic relationship. We are dealing after all with
9 state sanctioned monopolies. It's illegal for Clearwater
10 Paper to try to buy power from someone else. We're able
11 to cogenerate and sell our power to Avista under PURPA
12 and we're also currently selling our power to Avista
13 under a non-PURPA agreement, but Clearwater Paper wants
14 to preserve its options to be able to sell under PURPA to
15 Avista, to Idaho Power, to PacifiCorp.
16 Clearwater Paper Corporation operates in a
17 competitive market for all of its products that it buys
18 and that it sells, except for electricity, and we think
19 it's clear now that the dust has settled that there is no
20 imminent or even distant threat to Idaho Power or Rocky
21 Mountain Power or to Avista of being overrun with
22 unchecked solar or wind projects.
23 The IRP methodology for setting avoided cost
24 rates has actually proven to be resilient and sends
25 appropriate price signals. As Staff witness Sterling
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1 noted on the stand today, this morning, the price is the
2 key, not the contract length, and the IRP can even be
3 made more resilient by updating it for -- to account for
4 all QFs in the queue, and this would more appropriately
5 send the correct price signals during large influxes of
6 new QFs.
7 I also think the compromises offered by
8 Dr. Reading on behalf of J.R. Simplot Company and the
9 Clearwater Paper Corporation were very reasonable and I
10 would ask the Commissioners to seriously consider
11 adopting them instead of dropping the contract term.
12 Dr. Reading proposed a fixed 20-year capacity term with
13 an update to the energy component after 10 years. This
14 allows the QF to be compensated for avoided capacity,
15 while at the same time it addresses some of the concerns
16 raised by the utilities on the problem that brought us
17 here.
18 If you are convinced that you need to take
19 action, you should focus only on the alleged culprit,
20 which is the variable and intermittent solar and wind
21 projects, so reduce their contract term if you must, but
22 please take cogeneration out of the crossfire between the
23 utilities and the solar project developers, and I don't
24 really need to point it out, but cogeneration, in
25 addition to being a highly efficient way of producing
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1 electricity, actually makes Clearwater Paper
2 Corporation's products it makes more valuable and more
3 profitable and, hence, makes it a more stable and
4 economic, efficient driver in north Idaho's economy, so
5 thank you for your consideration and I'd be happy to
6 respond to any questions you may have.
7 COMMISSIONER KJELLANDER: Thank you. I don't
8 think we are going to wander into questioning, but we do
9 sure appreciate that. While we've got the microphone
10 next to Mr. Adams, why don't we let Mr. Adams provide us
11 comments.
12 MR. ADAMS: Thank you, Chairman Kjellander.
13 The J.R. Simplot Company, of course, agrees with Mr.
14 Richardson's comments and I won't go into great detail
15 repeating that. I just want to highlight some additional
16 points that we are concerned that based on the evidence
17 that has been presented in the case was either initially
18 overstated or has proven to become overstated with regard
19 to the solar contract requests, and then second, I was
20 going to briefly discuss our position that the utilities'
21 proposals and the Staff's proposal, also, for two-,
22 three-, and five-year contract lengths would be
23 inconsistent with FERC's PURPA regulations.
24 First, as to the statement in the case, Idaho
25 Power filed this case because it had 461 megawatts of
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1 PURPA contracts, solar contracts, executed and approved
2 to be online in 2016 and an additional 885 megawatts of
3 PURPA solar capacity in the queue that they stated were
4 actively seeking PURPA energy sales agreements. Yet,
5 it's undisputed there's no solar QFs online right now,
6 and since that time the Clark Solar 1 through 4 contracts
7 have been terminated, and Idaho Power's overall solar
8 contract total is down to 320 megawatts between Idaho and
9 Oregon currently.
10 Additionally, as Mr. Richardson mentioned, the
11 IRP methodology is sending significantly lower prices to
12 new projects that come along in the queue, and the reason
13 for that is that the point at which the QFs are getting
14 compensated for capacity has been pushed out in the
15 calculation because of the higher-queued QFs, which we
16 believe the design of that was to address the issue of
17 building capacity on the system when it's not needed, and
18 the QFs are simply not going to be compensated for
19 capacity until it's projected that the utility will need
20 additional capacity.
21 Another fact for the Commission's consideration
22 is that the federal tax credits for solar power are going
23 to be reduced significantly in 2016, further reducing the
24 ability of these prospective solar contracts to be
25 developed. We're concerned that Idaho Power's request
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1 for relief would affect all resource types and undermine
2 longstanding Commission policy providing the opportunity
3 for QFs that are economically viable and can sell
4 electricity at the avoided costs, so we ask that the
5 Commission take a step back and consider those facts in
6 the record at this point before addressing the question
7 of whether the contract term should be shortened to two,
8 three, or five years.
9 And moving on to the second point, we do
10 believe that doing that would be inconsistent with FERC's
11 regulations under the facts of this case. The utilities
12 and the Staff have suggested that there is no limit,
13 there's no lower limit to the length of a fixed rate
14 contract under FERC's regulations. We do disagree with
15 that. The critical regulation here is 18 CFR
16 292.304(d) (2) subpart 2. That's the legally enforceable
17 obligation rule and I'm not going to read it into the
18 record, but if you read that regulation on its face, it
19 establishes a few important points.
20 One is that the QF has the option to sell
21 energy. The QF also has the option to choose to sell
22 excuse me, the QF has the option to sell energy or
23 capacity and that the option to sell the capacity is
24 critical in this case. The QF also has the option to
25 choose to sell that capacity over a specified term, and
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1 the QF also has the option to have the rates calculated
2 prior to delivery at the time of creation of that legally
3 enforceable obligation.
4 Order No. 69 which implemented this regulation
5 explains "Use of the term legally enforceable obligation
6 is intended to prevent a utility from circumventing the
7 requirement that provides capacity credit to the QF," and
8 we believe that the fundamental flaw of the proposals for
9 two-, three-, and five-year maximum contract terms is
10 that the QF would not be able to enter into an
11 arrangement where it would be compensated for capacity
12 and be able to displace capacity on the utility's system.
13 J.R. Simplot Company and Clearwater Paper have
14 provided several alternative proposals if the Commission
15 is concerned that Mr. Richardson discussed, but we don't
16 believe it would be appropriate or legal to simply
17 shorten the contract term to a length that appears to be
18 designed to frustrate development of QFs, particularly
19 cogeneration projects. Thank you.
20 COMMISSIONER KJELLANDER: Thank you.
21 Mr. Arkoosh.
22 MR. ARKOOSH: Thank you, Mr. Chairman, Madam
23 Corrunissioner. I represent the canal companies and our
24 interest is in not shortening the contracts for published
25 rates, and two of the utilities here, Idaho Power and
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1 Avista, and the Staff all agree that's not appropriate at
2 this time. Rocky Mountain, on the other hand, has
3 maintained their position that those contracts should be
4 shortened and that's against the background of PURPA as
5 set forth in the Mississippi case in the Supreme Court.
6 It has two significant purposes. One is to incentivize
7 the use of renewable resources and the other is to
8 overcome traditional utility reluctance to purchase
9 privately-produced power.
10 The question of whether or not it incentivizes
11 use really does address the contract term, because I
12 think your record is fairly clear that two-, three-, and
13 five-year contracts won't be successful. As counsel has
14 just pointed out, the way it's currently structured, it
15 would prevent the selling of capacity, but the customers'
16 concerns here, that is, whether the utilities must buy
17 more power than they need on a must-buy federal program
18 or whether they maintain consumer indifference in the
19 avoided cost is really not addressed by this proceeding.
20 I think that those are concerns that have to be
21 addressed through the setting of avoided costs and what
22 power is displaced if you have a must-buy federal program
23 and ultimately might have too much power, so it just
24 leaves us with the question of incentive, and that's
25 what's being affected by this shortened proposal, this
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1 shortened contract proposal.
2 Rocky Mountain Power at page 10 of Mr.
3 Clements' rebuttal testimony set out their reasons for
4 shortening the contract term to less than 20 years, and
5 as I discussed with him on cross-examination, it's
6 because in his opinion it would expose customers to an
7 unreasonable price risk, and as I've indicated, this is
8 not a pricing -- this is not an avoided cost setting
9 hearing. This is a contract hearing which doesn't really
10 go to customer indifference. It goes to the
11 incentivization of the development of the industry.
12 The three reasons given at page 10 why he
13 believed that it was an unnecessary long-term, fixed
14 price risk were first, it exceeds the Company's current
15 hedging policies and practices, and I would point out
16 that the Company's hedging policies and practices where
17 it hedges its energy on the market is not part of the
18 federal mandate. It's not part of the program. It's not
19 even a part of the development of the avoided cost or not
20 a very significant part.
21 The second reason is that Rocky Mountain Power
22 feels that 20-year contracts are not consistent with the
23 Company's long-term planning approach, and that goes both
24 to incentive and traditional utility reluctance not to
25 purchase, but, again, it is not part of the federal
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1 mandate. It's not a federal reason. It's not a part of
2 PURPA, and the final reason is that the long-term
3 contracts are not consistent with the Company's RFP-based
4 approach to obtaining long-term power, and, again, that
5 goes directly to traditional utility reluctance.
6 That is one of the reasons PURPA was passed.
7 If utilities choose to develop capacity using other than
8 these renewable resources, then the Commission is
9 directed to be sure that there is an incentive not to
10 fulfill their needs that way, but literally to give a
11 preference to PURPA projects, so all three of the reasons
12 are not part of the federal mandate, and I would suggest
13 that all three of the only reasons given on this record
14 for expanding published as opposed to IRP avoided cost
15 rates are not reasons that are consistent with PURPA.
16 Thank you very much.
17
18 Otto.
19
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. OTTO: The Conservation League and the
20 Sierra Club believe the Commission should maintain the
21 20-year contract. At the same time, you should adopt our
22 proposal on pages 7 and 8 of Mr. Beach's rebuttal
23 testimony to include an adjustment to the energy
24 component at the midpoint of the contract. This is quite
25 similar to the proposal of Mr. Reading representing
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1 Simplot and Clearwater.
2 There have been many references to other paths,
3 paths other than PURPA, that could lead to development of
4 renewables, and while that may be true, PURPA remains the
5 law of the land, and the Commission has an obligation to
6 implement PURPA in a way that complies with that federal
7 law.
8 A structure of a long-term contract that
9 enables a QF to have a reasonable chance at financing,
10 allows the QF to operate long enough to avoid the need
11 for utility-built capacity, and allows a true-up of the
12 energy component to protect ratepayers is the proper
13 balance required by PURPA. That balance is to encourage
14 QF development while ensuring ratepayers are indifferent
15 to price.
16 As the Commission decided in Order 32697 and
17 confirmed recently in 33159 and Mr. Kalich testified to,
18 the IRP method is -- well, he said it's working. The
19 Order said the methodology compares the generation
20 profile of a QF to the utility's need for resources. The
21 Commission should take some pride that they've developed
22 a robust avoided cost methodology that is sensitive to
23 need and does reflect the utility's avoided hourly costs.
24 The core of this case, the utilities' position
25 in this case and backed by Staff is a claim that they're
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1 being flooded with QF contracts and have no need for
2 additional power. I encourage the Commission to look at
3 these facts before accepting this assertion. The fact is
4 the utilities are faced with a lot of inquiries, but
5 almost no actual contracts at this time.
6 The claim utilities don't need additional
7 resources is not as simple as they'd have you believe.
8 Idahoans need capacity when utilities are capacity
9 deficient, and under the current model, QFs are only paid
10 at that date. That date comes from the IRP process with
11 public participation and the Commission has the final
12 say.
13 Ms. Grow confirmed with me that Idahoans need
14 energy every minute of every day, and the Commission has
15 found that the energy component of the avoided cost
16 focuses on that highest displaceable incremental avoided
17 cost being incurred in each hour, and as Mr. Dickman
18 testifies on page 2 of his testimony, his direct, this
19 means the generation from Company-owned resources or
20 displaceable power purchases. In sum, ratepayers win
21 when the resources deliver the least expensive power in
22 each hour and that's exactly what the avoided cost model
23 is doing.
24 Mr. Sterling and some of the utilities claim
25 it's not possible to accurately predict avoided costs
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1 over 20 years, but that's exactly what happens when you
2 approve long-term power purchase agreements with fixed
3 contracts, something that was confirmed to benefit
4 ratepayers. Long-term predictions are also what supports
5 putting a utility-built resource into rate base. While
6 the fuel costs may be updated in the power cost
7 adjustment, the capital costs and the fixed O&M costs are
8 not. They're in it for the life of the project never to
9 be trued up again if that resource decision looking
10 backwards maybe wasn't the right one.
11 Mr. Beach's testimony also contains two more
12 benefits that come from these long-term, fixed price
13 contracts. They can be a hedge against volatility and
14 they can reduce market prices. This hedge is an all-in
15 price. A QF contract, that's the total price that
16 customers are going to have to pay for that power. It
17 cannot be fairly compared to just the fuel price that is
18 the current hedging practice, and as far as market price
19 suppression, we see the utilities and their IRPs moving
20 more towards market purchases and as we do so, the
21 Commission should take efforts to keep market prices low,
22 not keep market prices high to support off-system sales.
23 So as I mentioned, the avoided cost and the IRP
24 methodology and the QF contracts, there is a rigorous
25 public process to all of these efforts. The methodology
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1 came from a fully contested case that we all remember
2 well. The capacity date comes from the IRP, again, a
3 public process with Commission approval. That same
4 process produces the basic inputs to the energy costs.
5 Both the energy and the capacity inputs are updated
6 annually. All of these are public processes with the
7 Commission approval. This is robust. While it may be
8 different than a utility-built resource, it still has a
9 layer, many layers, of public participation, review, and
10 annual assurances that these are accurate.
11 As Mr. Clements testifies, the Commission does
12 have a lot of discretion to implement any contract
13 length. Importantly, that discretion or those actions
14 have to be consistent with the FERC regulations, and the
15 key as Mr. Wenner explained, you have to look at the
16 regulations in the context of the statute as a whole, and
17 that was his recommendation and I think that's my
18 recommendation, too, as an Idaho attorney, I'll say that.
19 You should interpret a statute in the context of its
20 entire purpose and need and structure as recently
21 confirmed by the Supreme Court.
22 A contract length and structure that enables a
23 QF a reasonable access to financing while paying only the
24 utility's actual avoided cost for energy and paying for
25 capacity only when a utility identifies need, that's
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1 consistent with FERC regulations, so if the Commission
2 wishes to provide the utilities the opportunity to
3 true-up those energy costs over a long-term contract,
4 again, I urge you to support our proposal as laid out in
5 Mr. Beach's rebuttal testimony. That's the correct
6 balance the Commission should reach. You're encouraging
7 QF development while protecting ratepayers over the long
8 term. Thank you.
9
10 Hammond.
11
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. HAMMOND: I just have a few comments. I've
12 heard a lot of points made that I would agree with. In
13 terms of our client Ecoplexus, the concern obviously is
14 having the Commission develop a program out of this
15 docket that meets or helps comply with federal law. Now,
16 maybe in Idaho we hate the federal government telling us
17 what to do. There always seem to be that undercurrent in
18 much of our relationships sometimes with the federal
19 government; however, PURPA is the law and the Commission
20 has some important decisions to make regarding how to
21 comply with those obligations, and I believe the
22 testimony in this record has demonstrated or provided the
23 ability for this Commission to use its discretion to use
24 something other than simply shortening the length of
25 contract.
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1 I think shortening the length of contract in
2 the manner in which the utilities have proposed is a
3 hammer meant to kill PURPA development altogether. I
4 think the record or the history of PURPA development in
5 this state demonstrates at least to some extent
6 shortening that contract term will all but eliminate, or
7 almost eliminate, any PURPA development. I don't think
8 the Commission wants to eliminate PURPA development. I
9 think the Commission wants to find that pathway to find
10 reasonable good development that makes sense for the
11 State of Idaho.
12 I believe based on the record there are means
13 by which we can do that, either through the current
14 methodology or adopting modifications to it to adjust
15 price, as has been addressed by several of the closing
16 arguments, to adjust price over the term of the contract
17 if there is a need to have it more closely match what is
18 going on. That in and of itself or those changes could
19 help to regulate the amount of power that comes online
20 that would address some of the concerns the utilities
21 have, while at the same time helping the Commission
22 support or meet its obligations, potential obligations,
23 to encourage the development of PURPA power in the State
24 of Idaho.
25 With that I'd leave it to your discretion.
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1 Thank you very much for the opportunity we've had to
2 address these issues before you.
3 COMMISSIONER KJELLANDER: Thank you, Mr.
4 Hammond. How about Staff for the Public Utilities
5 Commission?
6 MS. HUANG: Thank you, Mr. Chairman. On behalf
7 of Commission Staff, my closing will address the limited
8 issue of the Commission's authority to address the length
9 of PURPA contracts in response to the legal analysis in
10 Mr. Wenner's testimony and also arguments made today by
11 Mr. Adams and Mr. Otto and others.
12 I would agree with Mr. Schmidt's closing
13 statements on this issue. Nothing in PURPA Section 210
14 or in FERC's PURPA regulations refer to, let alone limit,
15 the ability of this Commission to establish a standard QF
16 contract duration that it deems appropriate.
17 In FERC's policy statement regarding its
18 enforcement role under Section 210 of PURPA at 23 FERC
19 61,304, FERC provided that its regulations allow the
20 states "a wide degree of latitude in establishing an
21 implementation plan. Such latitude is necessary in order
22 for implementation to accommodate local conditions and
23 concerns so long as the final plan is consistent with
24 statutory requirements," and indeed as noted by more than
25 one expert in these proceedings, as well as counsel for
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1 various parties present today, other state commissions
2 throughout the West, including Washington and this
3 Commission here in Idaho, have set different contract
4 lengths to accommodate the local conditions and concerns.
5 In fact, Mr. Wenner did concede in his direct
6 testimony at page 5, line 7, that nothing in the FERC
7 rules specifies a specific number of years for contract
8 terms. Contrary to Mr. Wenner's claim, FERC has not
9 characterized QFs as having the right to a long-term
10 contract. The language that Mr. Wenner quotes at page 5,
11 line 22, to page 6, line 13, in his direct testimony,
12 he's quoting from FERC's Order 69, which was also
13 referenced by Mr. Adams, I believe, that quote on its
14 face fails to support the supposition that there is a
15 right to a long-term contract.
16 In fact, on the following page in FERC's Order
17 69, FERC states that it should leave to the states
18 flexibility for experimentation and accommodation of
19 special circumstances with regard to implementation of
20 rates for purchases. This, again, highlights that the
21 states be given wide latitude on these matters.
22 Further, Mr. Wenner's assertion that the Idaho
23 Supreme Court has also found a right to long-term
24 contracts in the CFRs is equally far-fetched. Neither
25 the quoted language that Mr. Wenner provides nor any
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1 other language in that Afton Idaho Supreme Court decision
2 supports his argument, and he has his quote in his direct
3 testimony at page 6, lines 6 through 13.
4 The quote that he cites from the Afton decision
5 is actually on page 785 rather than 786 as he cites. It
6 is found in Footnote 7 of that decision. The Afton
7 decision at Footnote 8 also includes the Court's comments
8 that the level of QF payments varies depending on the
9 length of the contract, and also the Commission's
10 ratemaking authority is intricately related to its
11 ability to define the term of the obligation, so in sum,
12 there is no legal authority that legitimately supports
13 the argument made by Mr. Wenner that this Commission
14 lacks the ability to establish the length of PURPA
15 contracts in Idaho in keeping with its duty to ensure
16 reliable service and just and reasonable rates in the
17 public interest.
18 As supported by Mr. Sterling's testimony today
19 regarding the capacity arguments that have been made, if
20 a QF provides capacity, then a utility must pay for it,
21 but there is no requirement that a QF be entitled to
22 provide capacity and be paid for it.
23 The Commission's authority to establish
24 contract length is consistent with FERC Order 69 and
25 Idaho Supreme Court decisions, and for those reasons, the
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1 Commission Staff respectfully requests that you find that
2 you do have jurisdiction and authority to set the
3 contract length in these proceedings.
4 COMMISSIONER KJELLANDER: Thank you. Let's
5 move to Avista.
6 MR. ANDREA: Thank you, Mr. Chairman. At the
7 outset, I do want to thank the Commission for its time
8 and consideration in this proceeding, recognizing that
9 the testimony has been long and it's sometimes not as
10 exciting as other things we may be doing, so appreciate
11 your attention and consideration.
12 Certain intervenors have attempted to read a
13 long-term contract requirement into FERC's PURPA
14 requirements and regulations. As Staff has just
15 presented and Avista agrees, there is no such requirement
16 and the attempt to read that in is misleading. The truth
17 of the matter is that FERC has left it to the states to
18 implement PURPA and has provided the states broad
19 discretion in the way that they do that, and that
20 discretion includes setting of the contract term.
21 The Fifth Circuit in fact has recently
22 recognized in the Exelon Wind 1 decision that the state
23 PUC, in that case the Texas PUC, had the broad discretion
24 to set the contract term to no long-term contract for
25 resources that could not provide the reliable,
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1 predictable power. That demonstrates that at least one
2 federal court of appeals has recognized the states broad
3 discretion to set the term.
4 Finally, I note that some have attempted to
5 point out that Avista does not have the volume of PURPA
6 contracts that are currently being experienced by Idaho
7 Power and PacifiCorp. That really is irrelevant here.
8 Irrespective of how many megawatts of solar are or will
9 be online at any of the utilities, this case has
10 demonstrated that no QF projects should be eligible for
11 long-term contracts due to price risks that are borne by
12 customers. Just because there's no flood does not mean
13 it is okay to pay too much even for a few contracts.
14 The arguments that have been presented in this
15 regard are asking the Commission to wait until the horse
16 has left the barn before shutting the door. The
17 utilities' customers will be harmed by such an approach.
18 Avista clearly has an interest in ensuring that any rules
19 implementing PURPA adopted by this Commission are equally
20 applied to Avista to ensure that it does not become a
21 magnet for PURPA projects that would otherwise sell to
22 another utility.
23 Avista's interest in this proceeding continues
24 to be to ensure there's a level playing field between all
25 of the utilities and that the terms that are required for
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1 any one utility are applied equally to all of the
2 utilities regulated by this Commission. Again, I thank
3 you for your time and consideration, and that concludes
4 my remarks.
5 COMMISSIONER KJELLANDER: Thank you. Let's
6 move to Rocky Mountain Power/PacifiCorp.
7 MS. HOGLE: On behalf of Rocky Mountain Power
8 and its customers, we appreciated the opportunity to
9 present our case here to you today. I mentioned our
10 customers because the utility will not benefit nor it
11 will be harmed from the decision that you make in this
12 case. As Mr. Schmidt stated in his closing statement, we
13 pass through 100 percent of the costs to QFs, of the
14 Company costs from the payments that we make to QFs for
15 their power.
16 We believe that through our application, direct
17 and rebuttal testimony, and live testimony presented
18 through the course of two days we have met our burden.
19 Mr. Clements testified that leaving the PURPA contract
20 term at 20 years would violate the ratepayer indifference
21 standard under Section 210 of PURPA, and that cutting it
22 to two, three, or five years violates no provision under
23 PURPA.
24 Contrary to what Mr. Adams stated in his
25 closing, two-, three-, or five-year PURPA contracts can
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1 include capacity payments. To the extent that a QF helps
2 the Company or the utility reduce firm power purchases
3 from another utility, then the rate for such a purchase
4 will be based on the avoided capacity and energy costs,
5 and that's from FERC Order 69 which has been quoted
6 extensively here today and yesterday, 45 Fed. Reg. 12214
7 and page 12216, February 25th, 1980. That's the specific
8 quote.
9 Rocky Mountain Power submits that the
10 incentives to encourage the development of alternative
11 resources are built into PURPA and include the
12 must-purchase obligation under Section 210 and in FERC
13 Regs part F, which is the exemption of QFs from the
14 Federal Power Act and many state laws and regulations to
15 which utilities are subject. The price and the term of
16 the contract are neutral and not in and of themselves
17 incentives.
18 Based on the foregoing, Rocky Mountain Power
19 respectfully requests that you grant our petition for a
20 permanent reduction of maximum contract terms of PURPA
21 contracts to three years and modification to the
22 Company's avoided cost methodology as set forth in our
23 application and our testimony. Thank you very much.
24 COMMISSIONER KJELLANDER: Thank you. Let's
25 move to Idaho Power.
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1 MR. WALKER: Thank you, Mr. Chairman and
2 Commissioner Raper, and I too wish to thank you for the
3 opportunity here to make a closing and during this
4 hearing and for bringing this matter to a fairly rapid
5 hearing and conclusion and ultimately your decision, and
6 I'd like to say up front that these are contentious
7 matters among the parties and certainly, I'm passionate
8 about representing the Company and its customers.
9 Hopefully, none of the contentiousness certainly was
10 meant with no disrespect to this Commission, no
11 disrespect to Dr. Reading, Mr. Miller or Mr. Richardson
12 or any of the other parties here, but these are serious
13 matters and understand that we're passionate about our
14 positions.
15 Now, a good place to start, I think, is always
16 why are we here, why are we doing this and, you know,
17 this case is -- this case is not about fossil fuels or
18 the retirement of coal plants or C02 emissions or other
19 externalities of environmentalism. What this case is
20 about is the mandatory purchase requirement and
21 obligation of PURPA and the just and reasonable terms and
22 conditions of that mandatory purchase for the State of
23 Idaho established by this Commission under its proper and
24 lawful authority.
25 Now, PURPA requires the utilities to purchase.
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1 It does not require the utility and its customers to
2 provide risk-free financing to QFs. It requires the
3 customers be held neutral and be held harmless in such
4 transactions. None of the parties opposing the requested
5 reduction in maximum contract term here have really
6 addressed the larger issues related to need for
7 additional generation resources and the disproportionate
8 amount of risk that long-term, fixed rate, unchangeable
9 QF contracts place upon Idaho Power's customers without
10 the benefit of this Commission's or the public's scrutiny
11 of their acquisition of which the Company's own -- the
12 Company-owned resources must endure.
13 Now, the State of Idaho, in the State of Idaho,
14 we have a chosen authorized and constitutional system of
15 regulation that's designed to protect the interests of
16 the citizens of the State of Idaho and to allow for
17 companies like Idaho Power to reliably provide a vital
18 service to the public. This is a system that has served
19 us all very well since the time of Idaho Power & Light
20 versus Blomquist in 1914. This is a system that's
21 enabled us to today to continue to enjoy some of the
22 lowest electricity prices, retail prices, in the nation.
23 Now, the continued creation of 20-year term
24 contracts places an undue risk on customers at a time
25 when Idaho Power has sufficient resources to meet
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1 customer needs. The Company's required integrated
2 resource planning process is filed and updated every two
3 years. Non-PURPA purchase and sales transactions are
4 limited to less than two years pursuant to the Company's
5 approved risk management hedging policy, and avoided cost
6 rates themselves are updated at least every year, and
7 consequently, Idaho Power requests that the required term
8 for any prospective PURPA energy sales agreements above
9 the published rate eligibility cap also coincide with
10 that two-year time period.
11 Now, to also take some notice of very recent
12 U.S. Supreme Court decisions, the parties here would have
13 us ignore the substantial risks associated with 20-year,
14 fixed rate contracts without full evaluation of the cost
15 impact to society and to Idaho Power's customers. A lot
16 of talk about what's in the record, well, here's
17 something that's in the record, $2.7 billion, that's the
18 estimated obligation for over 1,300 megawatts of proposed
19 QF solar projects on Idaho Power's system.
20 $1.2 billion, that's the estimated cost of the
21 320 megawatts that are currently under contract for
22 construction in 2016; and finally, $2.6 billion, that is
23 the obligation of the existing 781 megawatts that are
24 currently constructed and operating on Idaho Power's
25 system. That's -- and yes, that's a total possible
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1 impact to customers of over $6 billion, and is that real?
2 You bet it's real.
3 I believe this Commission is very familiar with
4 concepts of legally enforceable obligations and many of
5 the projects on that very list currently seek legally
6 enforceable obligations and yet come in here and say
7 well, never mind, we're really not going to develop, that
8 doesn't have a chance, but oh, by the way, we all want
9 legally enforceable obligations for rates in place at the
10 time we're making these requests. You can't have it both
11 ways.
12 What else do we know about that list? Well, we
13 know that nobody has dropped off of that list of proposed
14 projects from the time we filed until today, and in fact,
15 that list has grown even during the pendency of this
16 case. It was 885 megawatts in January, today it's over
17 1,300.
18 There's also been discussion of Section
19 292.304, Order No. 69, and selected portions of FERC
20 direction with regard to an LEO and let's look at that
21 section briefly. What does it require? Well it gives us
22 guidance on what pricing is available to a QF. It can be
23 priced for a term or it can be priced at the time of
24 delivery. Order No. 69 in its discussion about an LEO, I
25 think it's very clear that FERC's direction there with
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1 regard to an LEO was meant to address situations when a
2 utility is refusing to contract with a QF. It was not
3 meant as a guarantee to get capacity payments no matter
4 what and certainly not when the utility is in a capacity
6 Now, and I'm almost done, I promise, so we
5 sufficient position.
7 really don't need a lot of fancy calculations or complex
8 analysis here to figure out that anything paid for
9 something that is not needed is too much and it's
10 potentially harmful to customers. The required term of a
11 mandatory QF purchase is within the authority and
12 discretion of this Commission to determine and set, and
13 in fact, the Commission has modified the required
14 contract term for PURPA purchases as discussed several
15 times in the past, including previous terms limited to
16 five years.
17 Idaho Power currently undisputably has no
18 identifiable need to acquire any additional generation
19 resources potentially for the next 10 years, and
20 additionally, the planned Boardman to Hemingway
21 transmission line would serve additional growth beyond
22 that without adding any new power plants. The
23 acquisition of Company-owned resources, generation
24 resources, as well as the Company's purchase and sale of
25 non-PURPA generation is either limited to terms less than
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1 two years or it's subject to very intensive Commission
2 and public participation, scrutiny process, and
3 proceedings to all determine that the Company is acting
4 prudently, in the public interest, fulfilling a need in
5 the least cost and most reliable manner possible.
6 Now, all of these requirements, particularly
7 that of establishing need for the resource, are absent in
8 the mandatory PURPA QF purchase, and the further
9 constraint imposed by PURPA that eliminates contract
10 reopeners or any ability to modify or change those prices
11 that are locked into the contracts regardless, in FERC's
12 own words regardless, of whether all costs were included
13 at the time or regardless of whether those costs varied
14 from the actual costs and conditions as they may have
15 changed or varied over the duration of that contract.
16 That makes long-term contracts, you know, at
17 best a risky proposition and here damaging and harmful to
18 customers, and further, with all the uncertainties, I
19 think everybody in the case talked about many of the
20 uncertainties into the future that all can impact the
21 costs to customers, can affect the rate. With that
22 uncertainty, it really is unreasonable to continue to
23 require our customers to shoulder all of that risk, and
24 Idaho Power asks that the Commission reduce the maximum
25 term as we've requested.
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1 COMMISSIONER KJELLANDER: Thank you. I believe
2 we got all the parties. Did I miss anyone? Okay, a
3 couple of procedural items. All the exhibits that have
4 been marked and identified to these proceedings will now
5 be admitted.
6 (All exhibits previously marked for
7 identification were admitted into the record.)
8 COMMISSIONER KJELLANDER: I believe that I
9 mentioned earlier in the proceedings that it's our intent
10 to have the requests for intervenor funding in very near
11 term and so I'm going to pick a 10-day window, which
12 would be Friday, July 10th, so hopefully, that's an easy
13 date to remember, and we'd like to see those requests for
14 intervenor funding in as soon as we can so that we can
15 proceed quickly towards our deliberative process.
16 As a reminder, this evening we have a
17 telephonic hearing that begins at 7:00, and so while
18 you're out enjoying the wonderful, lovely weather in
19 Boise, we'll be in here wishing that we were here because
20 it's not as bad as outside. That said, is there anything
21 else that needs to come before the Commission? If not,
22 this component of our proceedings is complete. We
23 appreciate your willingness and desire to help us develop
24 the record and, again, we look forward to getting out a
25 timely Order once we have all of the matters in front of
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1 us for appropriate deliberations and with that, thank you
2 and we'll see you all soon, hopefully, in another case.
3 (The hearing recessed at 12:30 p.rn.)
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