20150715Hearing Transcript Volume IV.pdf

BEFORE THE IDAHO PUBLIC UT]LITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITTON TO MODIFY
TERMS AND COND]TIONS OF PURPA
PURCHASE AGREEMENTS
CASE NO. IPC-E_15-01
IN THE MATTER OE AVISTA
CORPORATION'S PETITION TO MODIFY
TERMS AND CONDTTIONS OF PURPA
PURCHASE AGREEMENTS
CASE NO. AVU-E-15_01
IN THE MATTER OF ROCKY MOUNTAIN
POWER COMPANY'S PETITION TO
MODIFY TERMS AND CONDITIONS OF
PURPA PURCHASE AGREEMENTS
CASE NO. PAC-E-15-03
BEFORE
COMMISSIONER PAUL KJELLANDER (Presiding)
COMMISS]ONER KRISTINE RAPER
5,HPLACE: Commission Hearing Room -* G'
472 West Washington Street :;J!; k ,Boise, Idaho '"1i.,- r-- ..:-;'.:
|- :EDATE: June 30,2075 .'l s
'::- (*)
VOLUME IV - Pages 7 62 1,027
CSB REPORTING
C ertifrcd S h orthand Reporters
Post Offrce Box9774
Boise,Idaho 83707
csbreporting@heritagewifi . com
Ph: 208-890-5198 Fax: [phone]
Reporter:
Constance Bucy,
CSR
ORIGINAL
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CSB REPORTING(208) 890-s198
Eor the Staff:
Eor Idaho Power Company:
For Rocky Mountai-n Power:
Eor Avista Corporation:
Eor Cl-earwater Paper:
For Intermountain Energy
Partners:
For J.R. Simplot Company:
For Idaho Irrlgation
Pumpers:
APPEARANCES
Dona1d Howe1l, Esg.
and Daphne Huang, Esq.
Deputy Attorneys General
412 West Washington StreetBoise, Idaho 83120-0074
Donovan E. Dlalker, Esq.
Idaho Power Company
Post Office Box 10Boise, Idaho 83707-0070
Yvonne R. Hog1e, Esq.
Rocky Mountain Power
207 S. Main Street, Ste. 2400Salt Lake City, Utah 84111
l'lichaeI Andrea, Esq.Avista Corporation
Post Office Box 3121
Spokane Washlngton 99220
R]CHARDSON ADAMS PLLC
by Peter J. Richardson, Esq.
515 North 2'7LhL Street
Boise, fdaho 83102
McDEVITT & M]LLER
by Dean J. Miller, Esq.
420 West Bannock Street
Boj-se, Idaho 83102
RICHARDSON ADAMS PLLC
by Gregory M. Adams, Esq.
515 North 21Lh StreetBoise, Idaho 83102
RAC]NE OLSON NYE BUDGE
& BAILEY
by Eric L. O1sen, Esg.
Post Office Box 1391PocateIIo, Idaho 83204-\397
APPEARANCES
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CSB REPORTING
(208 ) 890-s198
A P P E A R A N C E S (Continued)
Eor Idaho Conservation
League & Sierra Club:
For Snake River
Al-liance:
For Renewable Energy
Coalition:(Of Record)
For Snake River
AII-iance:
For Micron Corportion:
Northside and Twin Falls
Canal- Compani-es:
For Ecoplexus:
Benjamin iI. Otto, Esg.
Idaho Conservatlon League
770 North 6th StreetBoise, Idaho 83702
KeJ,sey Jae Nunez, Esq.
Snake River Al-liance
Post Office Box 1731Boise, Idaho 83701
Williams Bradbury PC
by Ronald L. WiJ.J.iams, Esq.
1015 V{est Hays StreetBoise, Idaho 83702
-and-
SANGER LAW PC
by Irion Sanger, Esq.
1117 SW 53rd Avenue
Portland, Oregon 97215
Kelsey ,.Tae lilunez, Esq.
Snake River Alliance
Post Office Box !131Boise, Idaho 83701
HOLLAND & HART LLPby Frederick iI. Schmidt, Esq.
377 S. Nevada Street
Carson Ci-ty, Nevada 89703
ARKOOSH LAI/I] OFFICESby C. lom Arkoosh, Esq.
Post Office Box 2900Boise, Idaho 83701
FISHER PUSCH LLPby ilohn R. Hamond, iI?., Esq.
Post Office Box 1-308Boise, Idaho 83701
APPEARANCES
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CSB REPORTING
(208 ) 890-s198
INDEX
WITNESS EXAMINATION BY PAGE
Don Reading
(Clearwater/Simplot )
Mr. Richardson (Direct) 763Prefiled Direct Testlmony 7 65Prefiled Rebuttal Testimony 840Mr. Howel-I (Cross) 856Mr. Wal-ker (Cross ) 8 61
Commissi-oner Kj rellander 8 68
Yao Yin
( Staff )
Ms. Huang (Direct)
Prefiled Direct TestimonyMr. Richardson (Cross)Mr. Mill-er (Cross )
871
874
884
886
Rick Sterling
( Staff )
Mr. Howel1 (Directl 890Prefil-ed Direct Testj-mony 892Prefiled Rebuttal Testimony 924Mr. Richardson (Cross) 935Mr. Olsen (Cross) 956
Mr. Adams (Cross) 957Mr. Otto (Cross) 965Mr. Hammond (Cross) 968Mr. Nunez (Cross) 97LMr. Walker (Cross) 914
Mr. Andrea (Cross) 916
Commissioner Raper 977Mr. Howel-1 (Redirect ) 918
INDEX
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EXHIBITS
NUMBER DESCRIPTION PAGE
FOR IDAHO POWER COMPANY:
1. 1_1.Admitted 1026
FOR THE STAFE:
101. Expiration of PURPA Contracts Premarked
Over Time Admitted 1026
FOR J.R. SIMPLOT & CLEARV{ATER PAPER:
201-. CV for Dr. Don Reading Premarked
Admitted 7026
202. 18 C.F.R. S 292.304 PremarkedAdmitted 1026
203. Federal Register pages 72274 & PremarkedL2224-L2227 Admitted 7026
204. Redacted Rebuttal Testimony of Premarked
Gregory N. Duval1, 8/2/13 Admitted !026
205. Energy Sales Agreements Premarked
Terminat j-ons for C1ark Sol-ar L-4, Admitted L026with Attachment 1
FOR ICLISIERRA CLUB:
301. 305 Admitted L026
FOR INTERMOUNTAIN ENERGY PARTNERS:
401. 402.Admitted 7026
CSB REPORTING
Wilder, Idaho 8367 6
EXHIBITS
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EXHIBITS (Continued)
NUMBER DESCRIPTION PAGE
EOR SNAKE RIVER ALLIANCE:
501_.Admitted 1,026
FOR ROCKY MOUNTAIN POWER:
601.Admitted 1026
FOR AVISTA CORPORATION:
1101. - 1103.Admitted L026
CSB REPORTING
Wilder, Idaho
EXH]B]TS
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BOISE ]DAHO, TUESDAY JUNE 30 2015 9: 00 A. M.
COMMISSIONER KJELLANDER: WeII, good morning.
We'll reconvene and go back on the record as we continue
to proceed with the case. f won't go through the
laborious naming and numbering of it. We're al-l aware of
it by now. If you're in the wrong pIace, you can still
1eave.
As we l-eft things yesterday, we were going to
start with Don Reading and then move to Staff's final two
witnesses; is that sti11 okay with everybody?
MR. RICHARDSON: Itrs fine with us,
Mr. Chairman.
COMMISSIONER KJELLANDER: Excell_ent; so with
that, then, Mr. Richardson, my assumption is that you are
going to get Don Reading ready for us, So why donrt I
hand it off to you.
MR. RICHARDSON:
Clearwater Paper and J.R.
Dr. Reading to the stand.
Thank you, Mr. Chairman.
Simplot jointly woul-d call
MR. SCHMIDT: Mr. Chairman? Sorry, f wasn't
here yesterday and so I just wanted to enter an
appearance. Irm Fred Schmidt. Irm counsel for Micron
and f'11 be attending the remainder of the hearing on
CSB REPORTING
(208 ) 890-s198
762 COLLOQUY
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CSB REPORTING
(208 ) 890-5198
READING (Di)
Simplot /Clearwater
behalf of Micron. My partner Pamel-a Howland substituted
for me yesterday. Unfortunately, I was in a hearing for
the Nevada PUC, but I'm glad to be here today.
COMMISSIONER KJELLANDER: She warned us you'd
be herer so thank you for bringing that up.
DON READ]NG,
produced as a wltness at the instance of the Clearwater
Paper Corporation and the J.R. Simplot Company, having
been first duly sworn to tel-l- the truth, the whole truth,
and nothing but the truth, was examined and testified as
follows:
DIRECT EXAM]NATION
BY MR. RICHARDSON:
O. Good morning, Dr. Reading. Would you please
state your name and spell your last name for the
record?
A. Don Reading, R-e-a-d-i-n-9.
O. And are you the same Dr. Reading who has
prefiled direct and rebuttal testimony in this
proceeding?
A. Yes.
O. And are you the same Dr. Readi-ng who caused
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CSB REPORTING(208) 890-s198
READING (D1)
Simplot/Clearwater
replacement page No. 15 to be filed in this proceeding?
A. Yes.
O. And Dr. Reading, if I were to ask you the same
questions you were asked in your prefiled dj-rect,
rebuttal, and replacement page testimony, would your
answers be the same today?
A. Yes, they would.
O. And do you have any corrections or additions to
make to your testimony?
A. None I know of.
MR. RICHARDSON: Mr. Chairman, I would move
that Dr. Reading's testimony, prefiled testimony, and
exhibits -- what are the exhibit numbers 207 through
205 be marked for identification purposes and his
testimony be spread upon the record as if it were read in
ful-1.
COMMISSIONER KJELLANDER: That's what I had as
we11, so without objection, we will put the testimony
across the record as if read, both the direct and the
rebuttal, and mark and identify Exhibits 201 through 205.
Thank you, Mr. Richardson.
(The fol-lowing prefiled direct and rebuttal
testj-mony of Dr. Don Reading is spread upon the record.)
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Readlng, Di 1
Simplot/Cl-earwater
O. PLEASE STATE YOUR NAME AND BUS]NESS ADDRESS.
A. My name is Don Reading and my business address
is Ben Johnson Associates, 6070 Hill Road, Boise, Idaho.
I am Vice President and Consulting Economist for Ben
Johnson Associates.
o. HAVE YOU PREPARED AN EXHIBIT OUTLINTNG YOUR
QUAL]FICAT]ONS AND BACKGROUND?
A. Yes. Exhibit No. 201 serves that purpose.
O. ON WHOSE BEHALF ARE YOU TESTTFYING TN THIS
CONSOLIDATED DOCKET?
A. The J.R. Simplot Company (Simplot) and
Cl-earwater Paper Corporation (Clearwater) .
O. WHAT IS THE PURPOSE AND GENERAL CONCLUSION OE
YOUR TEST]MONY IN THIS CASE?
A. I have been retained by Simplot and Clearwater
to review the petitions fil-ed by the ldaho Power Company
(Idaho Power), Avista Corporation (Avista), and Rocky
Mountain Power (RMP) asking the Idaho Public Utilities
Commission (Commission, IPUC) to modify the terms and
conditions of Public Utility Regulatory Poficies Act of
!918 (PURPA) contracts. I will explain why the
recommendations of the three utilities is an unreasonably
overbroad approach. Both the Federal Energy Regulatory
Commission (FERC) and the Idaho Commission have correctly
stated that PURPA projects need contracts of duration
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longer than five years to all-ow for financing of a PURPA
generation facility. I will explain why the examples
used by Idaho Power to criticize PURPA are misleading,
and wil-l- demonstrate that Idaho Power's claim of a
"fl-ood" of incoming
Reading, Di 1a
Simplot /Clearwater
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Reading, Di 2
Simplot /Clearwater
PURPA contracts is misleading. It is far from certain
from the evidence provided that these projects will ever
be built. I recommend the Commission maintain the
current 2O-year contract length for qualifying facil-ities
(QEs) eJ-igible for the IRP methodology rates, or at a
minimum for non-intermittent QFs, and if adjustments need
to be made they should be through the calculation of
avoided cost rates and not limiting the term of the
contract.
O. YOU INDICATED YOU ARE TESTIFYING ON BEHALF OF
SIMPLOT. DOES SIMPLOT OPERATE OR INTEND TO DEVELOP QF
PROJECTS IN IDAHO?
A. Yes. Simplot currently operates an existing QF
project at its fertilizer plant in Pocatello, Idaho,
which utilizes a renewable fuel- in the form of waste heat
in an industrial cogeneration process and has a nameplate
capacj-ty of 15. 9 megawatts (MW) . It has sold the output
from that plant under a series of PURPA contracts, and
recently entered into a one-year replacement contract for
that PURPA facility. Simplot will need another
replacement contract within the next year. Although
Simplot has recently obtained QF contracts with published
avoided cost rates, it has also requested indicative
pricing under the IRP methodology and considered
increasing its generation well above 10 average monthly
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Reading, Di 2a
Simplot /Cl-earwater
MW on a consistent basis, which would require a contract
containing the IRP methodology avoided cost rates. In
recent years, I understand that Simplot has considered
contract lengths of up to seven years for this project.
Additionally, Magic Reservoir Hydroelectric QF
(Magic) is a wholly owned subsidiary of Simplot. Magic
is a nine MW hydro facility in Southern Idaho, and
currently has a 35-year contract to seII the output to
Idaho Power, which expJ-res in 2024.
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Simplot al-so recently contacted Idaho Power to
request indicative pricing for a cogeneration QE sized up
to 25 MW, to be developed at the new Idaho Project potato
processing facility in Caldwel1, Idaho. I understand
that Simplot faces dlfficul-ty even analyzing the
viability of this proposed facility without a fixed rate
schedul-e in excess of five years. ft is likely the
project wil-l not proceed if the Commission reduces the
maximum contract length to five years.
O. YOU ALSO TESTIFIED THAT YOU ARE TESTIFY]NG ON
BEHALF OF CLEARWATER. DOES CLEARWATER OPERATE OR INTEND
TO DEVELOP QF PROJECTS IN IDAHO?
A. Clearwater owns four generators at its wood
pufp, paperboard, and tissue manufacturing facility near
Lewiston, Idaho, which primarily utilize as fuel the
black Iiquor byproduct of the paper production process
and wood waste. These four generators are cumul-atively
capable of generating approximately 109 MW of electrical-
output. Although they primarily use a renewabl-e fuel in
the form of biomass, these facil-ities al-so use the steam
output as process steam in the production of pulp,
paperboard and tissue products, and are each certified as
cogeneration QFs. Cl-earwater has previously sol-d its
output from these generators to Avista under PURPA
contracts, and Cl-earwater has maj-ntained its QF
Reading, Di 3
Simplot /Clearwater
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certj-fication to allow it to again make sales under PURPA
j-n the future. Currently, Clearwater operates under a
2013 agreement whereby Clearwater uses its generators to
serve Clearwater's own load, and Avista compensates
Cl-earwater for its excess generation at the retail-
electricity rate. The 20L3 agreement remains in effect
until June 30, 2078, but provides Clearwater with a
limited right to terminate its energy sales to Avista
with 90 days notice.
Reading, Di 3a
Simplot /Clearwater
710
Addltionally, I understand from communications with
Cfearwater personnel- that Clearwater and Avista have had
periodic conversatj-ons over the last five years about the
viability of siting a large cogeneratlon project at
Cl-earwaterfs Lewiston facility. Given the large and
nearly constant steam demand at the Lewiston site, this
facility coul-d support a base-load plant of an
incremental 15 to 725 MW that would approach l)eo thermal-
efficiency depending on the sizes and types of prime
movers selected for the project. The net impact of this
project woul-d be an incremental Iowering of greenhouse
gas emissions for the western U.S. as it would displace
base-1oad coal plants and assi-st the State of Idaho to
comply with the E.P.A.'s recently proposed, and likeIy
promulgated, Section 111(d) carbon reduction rule. The
expected economics of such a project would 1ike1y require
non-recourse financing with terms of at least 15 years,
with 20 years being a more feasibl-e Lerm. A limitation
of a five-year power purchase agreement takes this type
of hiqh efficiency, greenhouse-gas-reducing project off
the tabl-e as an option at Lewj-ston. Cl-earwater does not
think this artificial l-imitation is in the best interest
of the ratepayers of Idaho.
O. AS]DE EROM PURPA OR SERVING THEIR OWN LOADS,
ARE THERE ANY OTHER VIABLE OPPORTUNTTIES TO SELL THE
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Reading, Di 4
Simplot /Clearwater
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Reading, Di 4a
Simplot /Cl-earwater
OUTPUT FROM PROJECTS LIKE SIMPLOT'S AND CLEARWATER'S IN
THTS REGION OF THE COUNTRY?
A. UnIike the three regulated utilities that
petitioned the Commissj-on in this docket, state l-aw bars
Simplot and Clearwater from selling el-ectricity at retail-
to any customer. This is al-so true of neighboring states
that largely bar the sal-e of electricity at retail.
Additionally, EERC has stated that Sectlon 210 (m) of
PURPA is intended to relieve
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Reading, Di 5
Simplot/Clearwater
utilities of their PURPA obligation if there is a
sufficiently competitive wholesale market for QFs to se11
power. But there is no such economically viable
wholesale market. for the sale of electricity that meets
PURPA's requirements in this region. Therefore, aside
from PURPA sal-es to util-ities, neither Clearwater nor
Simplot have a legal or economically viabl-e market,
retail- or wholesale, to seIl electricity.
O. IDAHO POWER SUGGESTS THAT THE IDAHO COMMISS]ON
HAS THE AUTHORITY TO REDUCE CONTRACT LENGTHS FOR EIXED
AVOIDED COSTS TO ANY LENGTH IT CHOOSES. WHAT IS THE
ORIG]N OF A LONG_TERM CONTRACT WITH FIXED AVO]DED COST
RATES ?
A. PURPA is a federal- law that directs FERC to
implement regulations that encourage cogeneration and
smal-l- power production f rom renewable resources. I have
incl-uded as Exhibit No. 202 a copy of the FERC regulation
regarding a QE's right to a legally enforceabl-e
obligation for a specified term, which is contained in 18
Code of Federal- Regulations Part 292.304. The FERC
regulatlon provides that each QF shall have the option:
(2) To provide energy or capacity pursuant to a
7ega17y enforceabfe obJigation for the deLivery of
energy or capacity over a specified term, in which
case the rates for such purchases shal-l-, dt the
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Reading, Di 5a
Simplot/Clearwater
option of the quaTifying faciTity exercised prior to
the beginning of the specified term, be based on
either:
(i) The avoided costs caJ-cuLated at the time of
deJivery; or
(ii) The avoided costs caTculated at the time the
obligation is incurred.l
1 Exhibit No. 202 (containinq l-8 C. r.R. S 292.304 (d) (2) .
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O. COULD YOU PLEASE STATE FERC'S EXPLANATION AS TO
THE INTENT OF THIS RULE, AS PROV]DED IN THE FEDERAL
REGISTER AT THE TIME FERC PROMULGATED THE RULE?
A. Yes. I have provided as Exhibit No. 203 an
excerpt of EERCTs Order No. 69, which was published in
the Federa1 Register on February 25, 1980, and explained
FERC's decision to adopt this regulation. FERC stated:
Paragraphs (b) (5) and (d) are intended to
reconciLe the requirement that the rates for
purchases equaT the utiLities' avoided cost with the
need for qualifying facil-ities to be abTe 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
js suppTied is Less than the price provided in the
contract or obliqation, the purchasinq utiTity wouTd
be required to pay a rate for purchases that woul-d
subsidize the quaTifying faciLity at the expense of
the utifity's other ratepayers. The Commission
recognizes this possibiTity, but js cognizant that
in other cases, the required rate wil-l- turn out to
be l-ower than the avoided cost at the time of
purchase. The Commission does not believe that the
reference in the statute to the incrementaf cost of
Reading, Di 6
Simplot /Clearwater
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alternative enerqy was intended to require a
minute-by-minute evaluation of costs which wouLd be
checked against rates estabLished in Tong term
contracts between quaTifying faciTities and electric
utilities.
Many commenters have stressed the need for
certainty with regard to return on investment in new
technol-ogies. The Commission agrees with these
Reading, Di 6a
S implot /Clearwater
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Reading, Di 1
Simplot /Clearwater
Tatter arguments, and bel-ieves that, in the Tong
runr'toverestimations" and "underestimations" of
avoided costs wiJ-l- baJ-ance out.
****
Paragraph (d) (2) permits a qualifyinq faciTity
to enter into a contract or other 7ega77y
enforceabLe obligation to provide energy or capacity
over a specified term. Use of the term "7ega71y
enforceabLe obl-igation" is intended to prevent a
util-ity from circumventing the requirement that
provides capacity credit for an eTigible qualifying
facility mereJy by refusing to enter into a contract
with the qualifying facility.z
O. I RECOGNIZE THAT YOU ARE NOT AN ATTORNEY AND
CANNOT PROVTDE A LEGAL OPINION ON FERCIS INTERPRETATION
OF ITS OWN REGULATION, BUT AS A MATTER OF ECONOMICS, IS
IT YOUR OPINION THAT A EIVE-YEAR CONTRACT TERM WILL, IN
EERCIS WORDS, ''PREVENT A UTIL]TY FROM C]RCUMVENTING THE
REQUIREMENT THAT PROVIDES CAPACITY CRED]T FOR AN EL]G]BLE
QUALIEYING FAC]Lf TY'' ?
A. No. The QF will not be able to cause the
utility to avoid future capacity additions if the
contract term is shortened to five years. One of the
ways a utility can avoid, or "circumvent" in FERC's
terminology, entering into a QF contract is to limit the
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Reading, Di 7a
Simplot /Cl-earwater
contract term to such a short period that being able to
finance the project becomes impossible. The contract
terms recoilImended by the three utilities in this case of
two, three, and fj-ve years
2 n*hibit No. 203 at 2 (containingiFERC Order No. 69, 45 Fed. Reg.
1,2214, 12,224 (Feb. 25, l-980)).
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are all too short to allow a QF to be economically viabl-e
or to provide, and be compensated for, the capacity
value.
o. AS A MATTER OF
THAT A FIVE_YEAR CONTRACT
FOR CERTA]NTY WITH REGARD
TECHNOLOGTES'' ?
ECONOMICS, IS IT YOUR OPINION
TERM WOULD SATISFY ''THE NEED
TO RETURN ON INVESTMENT ]N NEW
A. No. The only "certainty" that comes to mind
with a QF contract term of five years or less is that it
j-s very unlikely the project would ever be buil-t. This
conclusion is supported by the fact that utility
non-PURPA power purchase agreements are for terms much
longer than five years. Eor example, Idaho Power's Neal-
Hot Springs power purchase agreement is for a 25-year
term, and ldaho Power retained the right to extend the
term of that agreement. In his comments on the Neal- Hot
Sprlngs contract, IPUC Technical Staff, Rick Sterling,
identified the right to extend the term as one of the
"benefits" of that agreement in recommending its
approval. 3
O. ALL THREE OF THE UTILITIES ASK EOR A PURPA
CONTRACT TERM OE FIVE YEARS OR LESS. IF CONTRACT LENGTH
WERE ONLY FIVE YEARS OR SHORTER, ]S IT YOUR OPINION THAT
A QF PROJECT COULD RELY ON THE CONTRACT TO F]NANCE THE
DEVELOPMENT?
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A. No. The "Enron meltdown" provided an Idaho
example of the impact of shortening the term of QF
contracts to five years. As the Commission noted when
increasing the term limit from five years to 20 years
(after reducing them earlier), only one PURPA contract
was signed in ldaho with the shortened contract length.
At that ti-me, the Commission explaj-ned,
3 tpuC Staff Comments, IPUC Docket No. IPC-E-Og-34,
May 3, 2010) .
pp. 13-14 (fil-ed
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This Commission also cannot ignore the fact that
since reducing the eJigibility threshold to L W and
contract term to 5 years, there has been onTy one
PURPA contract signed in ldaho. A Tonger contract,
we find, better coincides with the amortization
period or pTanned resource life of the renewable or
coqeneration resources being offered, better
refl-ects the amortization period of generation
projects constructed by the utiTitzes themseJ-ves and
wi77 coincidently provide a revenue stream that wifl-
facil-itate the financing of QF projects.4
O. DOES THE IDAHO COMMISSION LIMIT UTILITY-OWNED
GENERATION RESOURCES TO A EIVE-YEAR TERM FOR COST
RECOVERY OE THE INVESTMENT?
A. No. Any utility-owned resources of any
significance that I am familiar with are approved by the
Commission with terms in some cases up to 50 years, and
are seldom shorter than 20. Of course , for a
utility-owned resource the ratepayer is on the hook for
provi-ding the utility with a return both of and on the
i-nvestment for the facility once it is put into rate
base. Treati-ng PURPA resources on an equal footing with
utility-owned resources would mandate they also should
receive longer-term contracts.
o. FERC ALSO REEERENCED "LONG TERM CONTRACTS." IF
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YOU WERE TO ASSUME THAT PURPA REQUIRES A LONG-TERM
CONTRACT, IN YOUR OPINION, IS EIVE YEARS A LONG TERM IN
THE CONTEXT OE A UTILITY-SCALE CAPITAL INVESTMENT?
A. No. When considering financing sj-gnificant
capital investments, such as utility generation plants,
"1ong-term contracts" would certainly mean more than five
years.
4 tpuc order No. 29029, at p. 1.
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O. IF I WERE TO TELL YOU THAT FERC'S RULES REQUIRE
THE COMMISSION TO IMPLEMENT LONG_TERM, F]XED AVOIDED COST
RATES THAT PREVENT THE UTILTTY EROM CIRCUMVENTING THE
NEED TO PAY FOR THE QF'S CAPACITY OR THAT ARE OF
SUFFIC]ENT LENGTH TO SUPPORT ]NVESTMENT IN A UTILITY
GENERATION FACIL]TY, IS IT YOUR OP]NION THAT A EIVE_YEAR
CONTRACT TERM MEETS THAT TEST?
A. No. Using such an unreasonably overbroad
approach of shorting the contract length so that QFs
cannot obtain financing is a way around FERC's rules.
Developing accurate avoided cost pricing is a more
rational- approach that meets FERCTs regulations.
O. HAS THE IDAHO COMMISSION ]TSELF MADE PINDINGS
REGARDING THE LENGTH OE CONTRACTS WITH A FIXED RATE THAT
IS NECESSARY TO ENCOURAGE QF DEVELOPMENT AND SUPPORT
FINANCING FOR A QF PROJECT?
A. Yes. Just a f ew years ago, the Idaho Commiss j-on
found:
We find that a 2)-year contract Tength, aTong with
other factors, has been beneficial- in encouraging
PURPA deveTopment in Idaho. Dle continue to beJ-ieve
that 2)-year contracts better coincide with the
usefuL Life of the renewabJ-e/cogeneration resources.
Whil-e it is not this Commission's responsibility to
ensure a contract Tenqth that aLl-ows a QF to obtain
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financing, we find that reducing maximum contract
Tength to five years woul-d unduly hinder PURPA
deveTopment. That is not the Commission's
objective. We beLieve that, by utiTizing other
tools to ensure an accurate and up-to-date avoided
cost vafuation,
Reading, Di 10a
Simplot /Cl-earwater
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we can continue to encourage the tTpes of projects
that were envisioned by PURPA whiTe maintaining the
transparency for ratepayers as PURPA requires.
Therefore, we find that a maximum contract Tength 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
O. THE COMMISS]ON STATED, ''WE FIND THAT REDUCING
MAXIMUM CONTRACT LENGTH TO FIVE YEARS WOULD UNDULY HINDER
PURPA DEVELOPMENT.'' DO YOU AGREE?
A. Yes, I believe Commission is correct. Real-
world economics dictate that a project wiII not get
financing with a contract length of five years unless the
investment has a five-year pay-back period. A five-year
pay-back is far shorter than generally understood to be
necessary for long-term utility-scale investments.
O. HAVE CONDITIONS CHANGED SINCE 201,2 WHEN THE
COMMISSION STATED THAT REDUCING THE CONTRACT LENGTH WOULD
UNDULY HINDER PURPA DEVELOPMENT?
A. No. The length of the QF contract has to do
with the ability to obtain funds in order to build the
project. Those conditions have not changed. The
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utilitj-es' avoided costs may have changed and that should
be the determining factor in whether projects are
developed, rather than an arbitrarily short contract term
that is designed to deprive financing and capacity
payments to the QF.
5 tPuc Order No. 32691, at p. 24.
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o. ARE
FOR ELECTRIC
A. Not
Power's most
Power issued
mature after
2O-YEAR CONTRACT TERMS OUT OF THE ORDINARY
UTIL]T]ES ?
at al-l-. For example, according to Idaho
recent 10-K filing, in April of 2072 fdaho
$75 mi1lion in first mortgage bonds that
30 years. Long-term financial- commitments
are routine in all util-ities' financing and planning.
O. DR. READING, WHAT PREC]PITATED THE
CONSOLIDAT]ON OF PETIT]ONS FILED BY THE THREE UTILITIES
IN THIS DOCKET?
A. ldaho Power filed a petition on January 30,
2015, to reduce the length of PURPA contracts to two
years. The Commission granted the Company interim rel-ief
temporarily reducing QF contracts from 20 years to five
years. On February 27 , 2015, Avista petitioned the
Commission for the same temporary and permanent rel-ief
that would be granted to Idaho Power and a five-year
contract length for wind and sol-ar QEs. Four days l-ater
on March 2, 20L5, Rocky Mountain Power filed its petition
seeking the same interim rel-ief and a permanent reducti-on
in the length of QF contracts to three years, along with
an adjustment in the method of calculating avoided costs.
The Commission consol-idated the three cases into a single
docket.I wlll discuss each of the utilities' petitions.
COULD YOU PLEASE TELL US IDAHO POWER'S REASONo.
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FOR FILING THE ORGINAL PETITION FOR THIS CASE?
A. According to the Companyrs petitj-on, it faces
what some have called a "tsunami" of wind and sol-ar PURPA
projects washing over Idaho Power's slstem.6 Idaho Power
proposes to l-imit contract terms for all QFs eligible for
lRP methodology rates to two years.
6 Idaho Power's Petition, IPUC Case No. 1PC-E-15-01, p. 21.
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O. WHAT IS IDAHO POWER'S RATIONALE FOR LIMITING
PURPA PROJECTS TO ONLY TWO YEARS IN DURATION?
A. Idaho Powerrs claim is that PURPA is imposing
"risk" and "harm" to ratepayers. Idaho Power's petition
largely discusses a probl-em with intermittent wind and
solar QFs that have the capability of creating an
oversupply probJ-em on Idaho Power's system during certain
periods of the year. According to Idaho Power's
subsequent pleadings, the problem is not just
lntermittent wind and sol-ar projects but PURPA itself in
obligating ratepayers to the Commission-approved rates
for a 2}-year period.T In an attempt to prove its case,
Idaho Power provldes "examples" of the price paid for
PURPA generatJ-on. Idaho Power claims customers must
purchase power at these higher PURPA prices when the
power is not needed to serve load or can be obtained in
the market at a cheaper price.
O. DO YOU BELIEVE TDAHO POWER MAKES A COMPELL]NG
ARGUMENT WHEN PRESENTING ITS EVIDENCE?
A. No. ldaho Power arrives at its conclusions by
only telling hal-f of the story. When valid comparable
evidence is presented, it shows the Company's own
generating resources commi-t the same "sins" as the PURPA
resources that they are asking the Commission to
discourage.
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o. coulD You PLEASE EXPLATN WHAT YOU MEAN BY ONLY
PRESENTING HALF THE STORY?
A. The first half of the story is tol-d when
comparing the cost of PURPA resources to Mid-Col-umbia
(Mid-C) prices. As shown in Exhibit No. 10 of Company
witness AIlphin's
1 Idaho Power's Answer to SinpTot/Cfearwater Joint/Cross Petition,
IPUC Case No. IPC-E-15-01, at p. 2 (filed March 1-9, 201,5) .
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direct testimony, historical Mid-C prices have been lower
than PURPA prices since 2002 to the present and are
projected by ldaho Power to be lower over the next 20
years. What this comparison fails to recognize is
capital costs are included in the PURPA per MWh price.
Mid-C prices are market prices and are more reasonably
related to the variable running costs of existing
generating resources that do not contain capital costs.
Both variable and capital costs are rol-led together in
the rates customers pay. When a utility's generating
resource is approved in rate base, the ratepayers are
"forced" to pay the capital costs of the resource over
the approved 1ife, even when the Company's own generating
resources are not needed to serve load.
o. WHAT DO YOU CONSIDER A MORE APPROPRIATE
CAMPARISON?
A. The cost of PURPA resources paid by Idaho Power
are passed through to customers i-n the retall- rates
customers pay. PURPA rates should be compared to what
Idaho Power's customers pay for power from the Company's
own generation facilities, which woul-d include the rate
based capital costs along with the fixed and variabl-e
running costs.
O. HAVE YOU MADE THAT COMPAR]SON V{HERE BOTH PURPA
PROJECTS AND TDAHO POWERIS GENERATING RESOURCES ARE
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MEASURED ON AN EQU]VALENT BASIS?
A. Yes, a reasonabl-e comparj-son can be made by
using Idaho Powerrs FERC Form 1 data for production costs
and Idaho Power's Responses to Simplot's di-scovery
request for the capital portion of the costs. Chart 1
bel-ow displays the results of including the estimated
capital costs along with the variable running costs of
Idaho Power's generating facil-ities on a per MWh basis
for 20L3, therefore comparing them on an equivalent basis
to the PURPA costs in retail rates. For 20L3, ds
expected, the market Mid-C prices are the
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lowest cost non-hydro resource on fdaho Power's system.
Two of the Company's coal resources have a lower cost
than PURPA resources with the other four thermal units at
a higher cost. This does not take into account the
additional costs that might be necessary for coal- plant
upgrades for environmental compliance for the Company's
non-PURPA resources that may be necessary in the near
future.
Chart I (Corrected)
ldaho Power Ratepayer Pourer Costs 2013 & Mid-C S/MWh
Bennetilt.r
ti Danskint'E
X1't-argnyeuUr"EE valmyt'ri5 PrrRPA.
g Boardman"E
$ JimBrktger.'
Mid{.
Srm
$/wh
Slso Szm
Source:
I R. Alphin E (hibit 10
t* AtbchrEnt 2 - Response to Sinrplods Request l{o. ,,3,2L]:3;,t{et plant' * .1g for Capacity;
ResponsetoSimplot's ReguestlS.5(d),annual retlrncrequirennntis 1816of capital Cosq
Production Expense' and 'Net Generation,, 2013 FERC Forrn I
O. DR. READTNG, ] DO
RESOURCES IN YOUR CHART 1.
FLOWS, IDAHO POWER'S HYDRO
NOT SEE IDAHO POWERIS HYDRO
SINCE, DEPENDING ON STREAM
RESOURCES MAKE UP HALF OF THE
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the Company's lowest cost resource with
rate base and very low variable running
depending on stream flow
/
a depreciated
cost. AIso,
Reading, Di 1-5a
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condj-tions the capacity factors will vary significantly
from year to year, and that woul-d in turn cause the cost
on a per MWh basis to also vary significantly. So the
year picked for the analysis could be misleading. Due
the above factors I felt looking at thermal resources
along with the market price would be a more reasonabl-e
comparison.
O. ARE THERE ANY OTHER REASONS TO EXCLUDE HYDRO
RESOURCES FROM YOUR ANALYSIS?
A. Yes. Idaho Power has been 1n the process of
relicensing its Hell-s Canyon Complex ("HCC" ) f or wel-l-
over a decade. It appears that the capital and variable
costs associated with the massive environmental-
remediation associated with that rel-icensing will
dramatically change the economics of the Company's hydro
resources as a whole and not just the costs assocj-ated
with the HCC. The final cost of rel-icensing HCC wonrt be
known for years; therefore it would be speculative for me
to inc]ude the unknowable i-ncreased costs of the
Company's hydro resources in my analysis.
O. DO THE OTHER TWO UTILITIES IN THIS CASE SUPPORT
COMPARING THE PRICE OF PURPA RESOURCES TO THE M]D-C
PRICES THAT DO NOT INCLUDE THE CONSIDERAT]ON OE CAPACITY
COSTS?
A. f don't know about Avista, but PacifiCorp has
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stated in Washington Utilities and Transportation
Commission (WUTC) cases that it is inappropriate to make
the comparison of PURPA resources with the Mid-C market
prices. I have provided as Exhibit No. 204 excerpts of
the testimony of Gregory Duvall- before the WUTC in recent
general rate cases. PacifiCorp witness Gregory Duva1l
states,
Readlng, Di L6a
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The incl-usion of capacity palanents in avoided costs
indicates that market prices aLone are not
equivalent to avoided cost prices.S
And the same PacifiCorp witness in a later WUTC docket
stated,
If avoided cost prices are greater than market
prices years after the PPA was signed, it does not
mean that the avoided cost prices in the QF PPA are
excessjve or otherwise vioJate PURPA's strict
requirements.
PURPA requires that the prices paid to QFs be
equal to a utiTity's avoided cost of energy and
capacity. Each state has an approved method for
calcul-ating these avoided costs, and the resulting
prices are heaviTy scrutinized and ultimately
approved by the respective reguJatory commissions.
The avoided cost caLcuLation is intended to ensure
that customers are indifferent to QF generation,
i.e., that the price paid to the QF is the same as
the price the util-ity wouLd otherwise incur it it
was generating the el-ectricity itseTf. Comparing QF
PPA prices for a singTe test year to the variabLe
cost of market purchases or the Company's existing
resources is insufficient to determine whether QF
prices are reasonabl-e and prudent from a ratemaking
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standPoint. 9
Subsequently, Mr. Duval-I further testified:
Eirst, simpTy relying on market prices does not
refLect Pacific Power's actual- avoided costs as
determined by the Commissjon because it faiLs to
account for the impact of a QF on the Company's
existing resources or the QF's abiLity to defer
8 uxhibit No. 204 at 1"1 (containing the Rebuttal Testimony of Gregory
Duval-f, WUTC Docket UE-130043, August 2, 20L3, p. 22) .
9 Exhibit No. 204 aL L'7 (containing Direct Testimony of Gregory
Duvall-, V'IUTC Dockets UE-140'762, -1,40617, -131384, -1,40094, May, 201-4,
p. 11).
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future capacity additions. PURPA requires the
Company to purchase energy and capacity made
avaif able by QFs.1o
As PacifiCorp's witness, Mr. DuvaII testifies in its
Washington jurisdiction that comparing market prices to
PURPA resource prices is inappropriate and mj-sleading.
O. IDAHO POWER CLAIMS THAT RATEPAYERS ARE HARMED
V'IHEN THE COMPANY IS FORCED TO PURCHASE PURPA POWER WHEN
IT 1S NOT NEEDED. DO YOU AGREE?
A. No more or less than when ratepayers are
"forced" to pay for the utilities' own generating
resources when they are not needed. Company witness
AIIphin presents a series of 24 separate graphs in his
Exhibit No. 6 for the first week of each month for the
years 20L6 and 2017. Each graph displaysr on an hourly
basis, total system load along with the Company's
"must-run" resources, "must-take" non-PURPA PPArs, along
with "must-take" PURPA resources. The "must-run"
Company-owned facilities are their hydro and coal
generation units at their minimum operational l-evels that
cannot be backed down further for environmental reasons
for hydro resources, or shut down for coal- generation
unj-ts. Market purchases and sales are excluded from the
Exhibit's graphs.
O. WHAT IS THE ]DAHO POWER W]TNESS ATTEMPTING TO
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DEMONSTRATE WITH THE SERIES OF 24 GRAPHS?
A. Again, Idaho Power j-s telling only half of the
story. According to Mr. Allphin's testimony,
This analysis shows the frequency with which ldaho
Power's system, when in a state where it cannot be
backed down any further, will- have qeneration
tesources
10 uxnilit No. 204 at 25-26 (containing Rebuttal Testimony of Gregory
Duval-l-, WUTC Dockets UE-140'1 62, -140617, -!40094, November, 2014, p.
14-15 ) .
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in excess of its system Load. This wi77 put the
system into an imbalanced, ovet-generation state
unl.ess some remedial- actions are taken to balance
the system. If remediaT actions are not avaiTable,
or not employed in a timely manner, then the Company
can have system reliabiJ-ity vioTations, events,
and/or outages and damage.ll
An examination of the monthly graphs over the two-year
period j-ndicates, as one would expect, a mix of
relatj-onshj-ps among the Company's load patterns over the
24 months considered, and the output of the power supply
depicted, indicating both an over and under supply of
power in various months.
O. COULD YOU BE MORE SPECIFIC AND PROVIDE EXAMPLES
EOR THE 24 GRAPHS THAT IND]CATE THE OVER AND UNDER SUPPLY
OE POWER ON ]DAHO POV{ERIS SYSTEM RELATIVE TO THE SYSTEMS
LOADS?
A. I have selected two months as examples that are
at the ends of the spectrum of when the graphs j-ndj-cate
first an oversupply relative to l-oads and second when the
situation is reversed and there is an undersupply. The
two example months are April and August of 2076 and
indicate there are times when both the Company-owned
resources and PURPA power contribute to filling part of
Reading, Di 19
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the gap when output is Iess than load and other times
when the Company's own "must-run" resources al-one are
producing power greater than system load needs.
O. COULD YOU PLEASE EXPLAIN WHAT YOU MEAN USING
THE APRIL 2016 GRAPH FOUND ON PAGE 5 OF 12 OE MR.
ALLPHINIS EXHIBIT NO. 6?
A. Below is copy of the April 20L6 Graph included
in Mr. Allphin's testimony.
11 Direct Testimony of Randy Allphin, Idaho Power, IPUC Case No.
IPC-E-15-01, pp. 9-10.
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ldaho Power Forccasted Load vs. Forecasted Must Run or Take Generation (MW)
rc MW ofPuRPA Solr
PURPA$h undarcont&t
PWA.rcl!dry Und .nd
$1,
-
rEo w& Mun T.h PPA!
lEoMul{un Ganardon
(Hydroed 265 W ot Co.l)
-lrco
LoJ Foracst
AF{,P[ A!.5,4$
Fl6ttl&elof the Mmth
As can be seen in the above graph for April, when loads
are relatively 1ow, system l-oads are l-ess than both the
"must runrr Idaho Power generation units as well as PURPA
resources. This woul-d mean that Idaho Power's "must run"
unj-ts are contributing aLone to the "system reliability
viol-ations, events, and/or outages and damage" unless
remedial action is taken in a timely manner, even if
there is no PURPA power being produced.
o. cou],D You PLEASE EXPLAIN THE OTHER END OF THE
SPECTURM, AUGUST 2076 WHEN BOTH IDAHO POWER'S RESOURCES
AT ''MUST-RUN'' AND PURPA RESOUSES ARE NOT SUFFICIENT TO
Reading, Di 20
Simplot /Cfearwater
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MEET THE SYSTEMS LOADS?
A. As can be seen bel-ow in a copy of Mr. Allphin's
graph for August 201,6, that is predicted to be a
relativlty high load month. In this graph, Idaho Powerrs
"must run" resources and PURPA are significantly below
system loads.
Reading, Di 20a
Simplot/Clearwater
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l&ho FourcrFqecastedtnd ys. Foreccidlirst Rrrror Eh C€nerdon(frwl
13rudma*md
IirtAS.L6a-ffi
-lrcAw
Im^-*"{[Wd*.
IEU&kI*.FAt
' Ele€-ard..!(l#E.d 2aa fl ct€cd,
-BHt€
.
r-.,,.;1r.. ..
514 ,q\8
F|sthctoadf, faotdt
This means PURPA generation is contrj-buting to the
Company's system load demands just as Idaho Power's
Company-owned resources are. The other monthly first week
graphs display a mix of over and under generation during
certain hours over the first week of each month.
o. Do You HAVE ANY ADDITIONAL OBSERVATIONS ABOUT
IDAHO POWER'S EXH]B]T NO. 6?
Yes, for the casuaf observer, si-nce PURPA, other
PPAs and Company-owned resources are all defined as "must
run" in the Exhibit No. 6, PURPA could just as easily be
displayed along the horizontal axis first with the
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utility-owned resources on top. This could l-ead one to
assume the Company-owned resources are the problem of
Idaho Power being "forced" to receive power when it is
not needed, not PURPA resources. The graph below uses
the same data for April 2016 as used by in Exhibit No. 6
and only reorders how the resources are displayed in the
graph.
Reading, Di 2La
Simplot /Clearwater
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ldeho PowerForecastedLoadvs. Forecasted Must Run or Tah Generatim (Mwl
E tiv!?tJnE.nrT.e1
;d,!r . g i!5 !J 1! si ao. r
g, Vlt.it-'t?.S.:
.Jtrt bti rsrel*
:.::.nB &. i!$ *-{trl
: *eE.ltsnl. {!i
-,toudt.!.*r
M3,Dta S.pla
FirstWr.lotih" Month
As can be seen, reversing the display of the various
resources causes it to appear that Idaho Power's
"must-run" resources are the source of oversupply, not
PURPA. In truth, al-l- of the resources are aII part of the
same power supply system and contribute to over and
undersupply at any poi-nt in time.
O. ARE YOU IMPLYING THAT COMPANY-OWNED RESOURCES
AND PURPA RESOUCES ARE THE SAME THING?
A. No. There are important differences depending
on the type of resource, and both impose different risks
and provide benefits for ratepayers under different Ioad
Reading, Di 22
Simplot/Clearwater
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and resource and power market conditions. The off-system
price of power is currently relatively Iow, and the
Northwest currentl-y has a surplus of power. However,
history shows that power market prices in the Northwest
have been volatile and power surpluses and deficits can
change quickly. One thing that is certain is there wil-l-
be ups and downs in the future, and the current situation
will not stay the same as today over the next 20 years.
Reading, Di 22a
Simplot /Clearwater
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Reading, Di 23
S implot /Clearwater
O. CAN YOU PROVIDB AN EXAMPLE OE WHAT YOU MEAN BY
SAYING THERE CAN SOMETIMES BE RAPID CHANGES ]N POWER
MARKETS?
A. The most dramatic swing in market prices for
power in the Northwest in the recent past is the
so-cal-led "Enron mel-tdown" when Mid-C prices got as high
as $677 per MWh in June of 2000 on a daily basis.12 At
the same time, due to a variety of causes, utilities were
facing power shortages. With the then-dramatic swings as
background, the Commissj-on issued Order No. 29029 quoted
above and increased the length of PURPA contracts to 20
years from five years and raised the eligibility cap for
published rates.13
O. WHAT OTHER ACTIONS DID THE COMMISSION UNDERTAKE
IN TH]S VOLATILE MARKET TIME ERAME?
A. The Commission, j-n July of 2001, approved a
Certificate of Public Convenience and Necessity (CPCN)
for Idaho Power's peaking facility, the Mountain Home
Generation Station (Danskin). In its decision the
Commission said,
We note that the procedure foLLowed in this
case has l-inited the tpe and extent of review that
would otherwise occur in a certificate fiTing. The
price of power on the spot market, the shortage of
water for hydro qeneration and the Company's
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Reading, Di 23a
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projected inabiTity to serve native Toad
requirements with Company qeneration and contract
suppTies have al-l- joined to create the unique
factuaL situation presented and have aLso fashioned
the particular reguLatory treatment requested by the
Company.
12 https : //www.nwcouncil. org.Appendix
C El-ectricitv Price Forecast .pdf.
13 rpuc order No. 29029, at p. 1.
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hle are convinced that the volatility of the
eLectric spot market created a situation that
justified a deviation from the Company's 2000 IRP
and its actions in deveToping pTans for the Mountain
Home Station.T4
Faced with the upheaval in the powgr markets at this
time, the Commission reacted by increasing the length of
PURPA contracts to 20 years and approving a peaking plant
that was not included in Idaho Power's Near-Term Acti-on
PIan in its 2000 IRP. The point of the above example is
that over a time period of a just a few years unforeseen
circumstances can significantly impact market conditions
for both supply and price. Current power market
conditions today have no guarantee they will- remain the
same over a 2O-year period.
O. COULD YOU PLEASE EXPLA]N FURTHER WHAT YOU MEAN
BY SAY]NG BOTH UTILITY-OWNED RESOURCES AND PURPA
RESOURCES HAVE D]FFERENT R]SKS AND BENEFITS EOR
RATEPAYERS?
A. Utility-owned resources and PURPA supply costs
impact ratepayers in different ways. A PURPA project
will only get paid when it supplies power to the utility.
On the other hand, with a rate-based, utility-owned
resource, the capital portion of the plant is rol-l-ed in
customer rates even if the facility 1s idle. This means
Reading, Di 24
Simplot /Cl-earwater
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Reading, Di 24a
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for a utility-owned resource the capacity costs are
factored into retail- rates on a per-MWh basis, and they
can vary significantly as the capacity costs of the
facility are spread over higher and lower power output.
For a PURPA resource, the capital portion of the price is
included in the levelized dollars per MWh, and ratepayers
are charged only when the facility provides power.
14 tpuc order No. 28773, at pp. 1,L-12.
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Reading, Di 25
Simplot /Clearwater
Idaho Power says it 1s concerned that as QF
contracts get longer there is increased risk and
potential harm to ratepayers, without recognizing thej-r
own resources l-ock in ratepayers as wel-l- to pay for their
own generating resources. The Commission Staff asked
Idaho Power;
REQUEST NO. 18: On page 22, the Petition states that
". . . the risk and potentiaf harm increases, the
Tonger the price estimates are locked in." Does
Idaho Power beJ-ieve long-term, Tocked-in price
estimates coul-d potentiaTTy benefit ldaho Power in
some circumstances?
RESPONSE TO REQUES? AIO. 78: IVo.15
What Idaho Power is failing to acknowledge is that their
own plants are al-so "l-ocked in" for ratepayers for the
plant l-ife that is 20 or more years.
A. DOES TH]S EXAMPLE DEMONSTRATE ANY OTHER POINTS?
A. The above example also points out that PURPA
projects, even those with 20-year contracts, do provide a
risk hedge and a benefit to ratepayers. PacifiCorp's
witness Mr. Duval-l- agrees with this point and has
testified at length before the Washington Commission
regarding the extensive benefits of PURPA projects:
In addition to providing the capacity benefits
discussed above, the out-of-state QFs provide
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Reading, Di 25a
Simplot/Clearwater
significant benefits because they are renewabTe,
emis s ion-f ree generatots .
****
Emission-free resources may act as a hedge
against future carbon regulation, the exact nature of
which is currently unknown. In fact, the
15 Idaho Power's Response to IPUC Staff Production Request No. 18.
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Readj-ng, Di 26
S implot /Clearwater
Commission has acknowfedged that future carbon
reguTation may have a significant impact on the
Company's operations. The out-of-state QFs, l-ike alf
of the Company's renewabLe resources, wiLl- heTp to
nitigate that impact.t6
O. ARE THERE OTHER WAYS THAT PURPA POWER PROJECTS
CAN LOWER RISKS FOR RATEPAYERS THAT UT]LITY-OWNED
RESOURCES DON'T?
A. In addition to not requiring ratepayers to pay
for the capital portion of undelj-vered electriclty, PURPA
resources avoid the fuel cost risks ratepayers face from
a utility's own resources. Al-1 three utilities that are
part of thls case have some form of a power cost
adjustment mechanism that, oD an annual basis, alIows
them to recover the malority of their net power supply
expenses. This means the utility is able to pass onto
ratepayers any fl-uctuations in the costs of their fuel-
supplies so that it i-s the ratepayer, not the utility,
that assumes the risk.
O. THE THREE INVESTOR OWNED UT]LITIES ALL ARE
PROPOSING TO SHORTEN THE CONTRACT LENGTH FOR ALL PURPA
PROJECTS ABOVE THE ELIGIB]LITY RATE CAP, IDAHO POWER FOR
TWO YEARS AND ROCKY MOUNTAIN POWER THREE YEARS. AVISTA
RECOMMENDS F]VE YEARS AND BEL]EVES ]F A VERY EAVORABLE
OPPORTUNTTY WAS PRESENTED TO THE UTILITY IT SHOULD HAVE
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Reading, Di 26a
S implot /Clearwater
AN OPT]ON EOR A LONGER CONTRACT.IT DO YOU AGREE W]TH THE
RECOMMENDATIONS OF THE UTILITIES?
16 uxninit No. 204 aL 28-29 (containing Rebuttal- Testimony of Gregory
Duvall-, WUTC Dockets UE-140162, -740671, -131384, -L40094, November,
20]-4, p. 17-18).
17 Direct Testimony of Clint Kalj-ch, Avista Corporation, February 27,
2015, AVU-E-15-01, p. 3.
816
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Readi-ng, Di 27
Simplot /Clearwater
A. The Companies are advocating an unreasonably
overbroad approach by treating all types of PURPA
resources the same. Limiting the contract length will
cause al-l- types of PURPA projects to become uneconomic
due to the inability to obtain financi-ng, not just "wind
and solar. " The Idaho Commission has establ-ished
precedent for setting different terms and condj-tions for
different types of PURPA projects.
Recently, in Case No. GNR-E-10-04 the Commission
l-owered the eligibility cap for wind and sol-ar to 100 kW
while leaving the higher 10 average monthly MW cap for
al-I other project types. The Commission's rationale for
doing so was that wind and solar resources have unique
characteristics not found in other types of PURPA QFs.
Based upon the record, the Commission finds that a
convincing case has been made to temporariTy reduce
the eTigibility cap for pubTished avoided cost rates
from 70 aMW to 100 kW for wind and sol-ar onTy whiTe
the Commission further investigates the inplications
of disaggregated QF projects. We maintain the
eligibiTity cap at 70aMW for QF projects other than
wind and soJ-ar (including but not fimited to
biomass, sma77 hydro/ cogeneration, geothermaJ-, and
waste-to-energy). The Petitioners have not
convinced us that lowering the eLigibility cap for
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Reading, Di 27a
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these other QF technoTogies is necessary or in the
pubTic interest.
Wind and solar resources present unique
characteristics that differentiate them from other PURPA
QFs. Wind and soLar generation, integration, capacity
and abiTity to disaggregate provide a basis for
distinguishing the eTigibiTity cap for wind and sol-ar
from other resources.18
18 rpuc order No. 32L16, at p. 9.
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Readj-ng, Di 28
Simplot /Clearwater
Currently, the three utiLities have posted different
published avoided cost rates for different resource
types. Each of the utilities recognizes QFs have
different defining characteristics.
O. BOTH CLEARWATER AND SIMPLOT CURRENTLY HAVE
COGENERATION PROJECTS. DO YOU BEL]EVE THEY HAVE
CHARACTERISTICS THAT DISTINGUISH THEM FROM WIND AND SOLAR
AS WELL AS OTHER PROJECTS?
A. Cogeneration projects have "unique
characteristics" that are distinct from other types of
PURPA projects. They are more fuel- efficient than
tradltional- generation and support a stronger economy.
EERC defines a cogeneration facility as,
A cogeneration faciJ-ity is a generating faciTity
that sequentiaTTy produces el-ectricity and another
form of useful- thernaJ- energy (such as heat or
steam) in a way that :.s more efficient than the
separate production of both forms of energy. For
exampTe, in addition to the production of
el-ectricity, Targe cogeneration faciLities night
provide steam for industrial- uses in faciTities such
as paper nil-Ls, ref ineries , or factoties, or for
HVAC appJications in commercial- or residential
buiTdings -L9
FERC regulations also exempt cogeneration QFs from the 80
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MW cap imposed on other types of qualifying facilities,
and FERC has stated that,
1 t http : / /www. f erc . gov,/industries /electri c/ gen-inf o,/qual- f ac /
what-is. asp
Reading, Di 28a
Simplot/Cl-earwater
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Reading, Di 29
Simplot /Cl-earwater
Cogeneration facil-ities can use significantTy Tess
fuef to produce eLectric energy and steam (or other
forms of energy) than woul-d be needed to produce the
two seParatef7.20
According to an fowa State University doctoral
dj-ssertation,
o.
Cogeneration has a fuel- efficiency of 808 to 90 I
compared to the 338 fuel- efficiency of conventionaL
efectricity generation units.2l
YOU STATED ABOVE THAT COGENERAT]ON SUPPORTS A
STRONGER ECONOMY. WHY DO YOU SAY THAT?
A. Cogeneration supports the economic viability of
Idaho industrial- f acilities. While this is not l-inked
directly to a utility's avoided cost, it contributes to
the strength of Idaho's economy and employment, which in
turn helps make a stronger utility. AIso, cogeneration
facilities produce electric power without using
additional fuel or contributing additional- pollution,
which also benefits society. Cogeneration represents one
of the most effective approaches to energy conservation,
because it produces two types of energy at once
el-ectric power and thermal energy. Conventional- thermal
power generators typically range from 33% to 50%
efficient, with coal- plants in the lower end of the range
and combined cycle gas plants in the upper range. They
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essentially waste between 402 to 612 of the fuel- energy
whereas cogeneration facilities can achieve
efficiencj-es of 803. On top of that, cogeneratlon
facil-ities make the host manufacturing plant more
financially secure with all the attendant societal
benefits
20 faRC order 688, Docket RMO6-010, at p. 1,4 (oct. 20, 2006).
21 The Economic and Environmental- Performance of Cogeneration under
the Public Utility Regulatory Policies Act, DanieJ-, Shantha E., Iowa
State University, 2009, p. 4.
Reading, Di 29a
S implot /Clearwater
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Readi-ng, Di 30
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of having a more robust economy. Cogeneration al-so
significantly reduces carbon emissions, reduces business
costs, relieves grid congestion and improves energy
security.
O. ARE THERE OTHER CONSIDERAT]ONS RELATED TO THE
BENEFITS OE COGENERATION IN THE CONTEXT OE THIS
PARTICULAR CASE?
A. Yes. As I noted earlj-er, Idaho Powerrs
petition primarily points to a problem of oversupply of
generation that is occurring during certain times of the
year as a resul-t of j-ntermittent and relatively
unpredictable PURPA output from wind and solar projects.
Cogeneration QFs are base-load resources that do not
provide intermittent deliveries, and their output should
be more easily predicted and managed during these
over-supply periods.
O. WHAT IS THE POSITION OE THE THREE UTIL]TIES
RELATTNG TO THE PURPA PROJECTS PROPOSED IN THE]R
RESPECT]VE SERVICE TERRITORIES?
A. The perceived "flood" of PURPA projects varj-es
among the three utilities. ldaho Power states the Company
currentfy has 461 MW of PURPA solar capacity under
contract with an additional- 885 MW in the queue actively
seeking power safes agreemenls.22 Rocky Mountain Power
states it has had an "exponential increase in PURPA
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Reading, Di 30a
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contract requests" consisting of 97 projects totaling
1,553 MW in the last two years throughout its multi-state
Slstem.23
O. WHAT IS AVISTAIS POSITION WTTH REGARD TO QFS
SEEKING PURPA CONTRACTS ]N ITS SERV]CE TERRITORY?
22 ldaho Power's Petition, IPUC Case No. IPC-E-15-01, p. 18.23 Rocky Mountain Powerrs Petitj-on, lPUC Case No. PAC-E-15-03, p. 19.
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Reading, Di 31
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A. While Avista j-s not claiming there is a torrent
of PURPA projects in its service territory, its concern
is if a neighboring utility such as Idaho Power offers
only five-year contacts "sophisticated and motivated
PURPA developers" wil-I seek longer term contracts by
wheeling the QE output to Avista.24 Avista advocates
for the ability to contract for PURPA projects with terms
Ionger than five years in the event of a very favorabl-e
PURPA opportunity.zs Avista, however, does not offer
specifics on what a "very favorable PURPA opportunity"
means, and it does not state that it supports continuing
2O-year QF contracts for projects subject to the IRP
methodology.
O. DO YOU AGREE W]TH AVISTAIS POSITION THAT
UTILITIES SHOULD BE ALLOWED TO NEGOTIATE A TERM LONGER
THAN THE COMMISSION-AUTHORIZED TERM?
A. Yes. Under the Commission's long-standing
rules, utilities have always been allowed to negotiate a
term longer than the Commission-approved contract length.
I agree that regardless of the outcome of this proceedj-ng
the utility and the QF should be al1owed to agree to a
Ionger term under the appropriate circumstances.
O. DOES AVISTA PROVIDE ANY EVIDENCE THAT ANY QFS
HAVE TRIED TO WHEEL THEIR OUTPUT TO SELL IT TO AVISTA,
GIVEN THE OVERSUPPLY PROBLEM ON IDAHO POWERIS SYSTEM?
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A. No. Avista provides no
tried to whee1 its power to Avista
off-system. Avista only points to
by Kootenai El-ectric Cooperative,
wheel- its output away from Avista
evidence any QF has
to sell to it from
a single QE, operated
Inc., that sought to
and to Idaho Power.
24 DirecL Testimony of Cfint Kalich,
No. AVU-E-15-01, p.5.
25 ta. at pp . 2-3.
Avista Corporation, IPUC Case
Reading, Di 3la
Simplot /Clearwater
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Reading, Di 32
Simplot /Clearwater
O. DOES AVISTA PROVIDE ANY REASON TO BELIEVE THAT
THE LARGE NUMBER OF PROSPECTTVE SOLAR QFS DTSCUSSED IN
IDAHO POWER'S PETITION MAY SEEK TO SELL TO AVISTA
INSTEAD?
A. No. Avista's avoided costs for sofar resources
are lower than Idaho Power's avoided costs for sol-ar
resources because Avista has a different load profile
that does not lend itself to hj-gh avoided costs for solar
output. Avista's published rates for sofar projects are
currently set at $49.7 7 per MWh on a 2)-year levelized
basis for an onl-ine date in 2016, while Idaho Power's
comparable rate for a 20L6 online year is $66.85 per MWh.
I woul-d expect the IRP methodology rates may well be
lower than the $49.7 7 per MWh amount, plus the off-system
solar QF would need to pay to wheel- the output to Avista.
There is no reason to believe sol-ar QFs would be abl-e to
rely on the economics of those l-ow rates to finance a
solar QE.
o. IDAHO POWER, AS YOU POTNTED OUT ABOVE, STATES
IT HAS 461 MW OE PURPA SOLAR CAPAC]Y UNDER CONTRACT AND
AN ADDITIONAL 885 MW ]N THE QUEUE TO BE ON-LINE IN 2016.
DO YOU HAVE AN OPINION AS TO THE PROBABILITY THAT ALL
THOSE QF PROJECTS W]LL ACTUALLY BE CONSTRUCTED?
A. In Response No. 2 to the Idaho Conservation
League and Sierra Club's First Production Request Idaho
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Power stated,
As of the date of the response to th:.s Request, 380
megawatts ("Mhl") of the 527 Mbl of QFs under
contract, but not yet on-7ine, are in compLiance
with their respective agreernents; therefore/ Idaho
Power has no reason to assume they wiLl not come
on-Line as stated in their agreements. To date, 141
Mhl of the 527
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Reading, Di 33
S implot /Clearwater
MW are not in compJiance with their respective QF
agreements and Idaho Power is taking the appropriate
actions as a7l-owed within those agreements.26
Based on a copy of a letter provided to me by the
developer, Idaho Power has now terminated the four
projects with 141 MW of capacity, Clark Sol-ar 1 through
4. I have provided a copy of this letter as Exhibit No.
205. This means more than one-fourth of the capacity of
the signed QE contracts due to come on line in 2076 have
had their contracts terminated. At this point, the
status of the others under contract is uncertain.
The projects that do not have executed contracts
appear to be unlikely to ever obtain a contract or be
developed in the near future. Under Idaho Power's
Schedule 73, a developer must only provide basic project
information in writing to receive indicative pri-cing, and
must provide a few additional items, such as proof of
site control over the property underlying the project, in
order to obtain a draft contract. In response to Simplot
Production Request No. 4, Idaho Power indicates, of the
48 PURPA projects that comprj-se the 885 MW in the queue
requesting pricing or contracts, only one of the proposed
projects has provided sufficient information to receive a
draft energy sales agreement and 6LZ of the Idaho
projects have fail-ed to provide enough information to
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Reading, Di 33a
Simplot /Cl-earwater
receive indicative pricing. Idaho Power has provided no
documents supporting an assertion that most of these
projects provided anything more than a simple inquiry
through a telephone call.
In addition, if any of the solar projects fail to be
on-l-ine before the end of 2076, the investment tax
credits for capital costs wil-l- drop from 30% to 102.
Thus, there is
26 Idaho Power's Response to Idaho Conservation League,/Sierra Cl-ub
Production Request No. 4.
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Reading, Di 34
Simplot /Clearwater
suffi-cient evidence to doubt that the volume of solar
projects claimed by Idaho Power wil-l- actually be
producing electricity by the end of 2016, rf ever.
O. ARE THERE OTHER ISSUES FOUND IN ANY OF THE
UTILITIES' FILINGS?
A. Yes. Rocky Mountain Power proposes to change
the lRP methodology to better respond to a large infl-ux
of QFs. Rocky Mountain Power stated they are seeking the
Commj-ssion to approve,
Modification of the Company's avoided cost
methodology such that preparation of indicative
pricing for QFs refTects al-l- active QF projects in
the pricinq queue ahead of any newly proposed QF
requests for indicative pricing.2T
O. DO YOU AGREE WITH ROCKY MOUNTAIN POWER THAT THE
COMMISSION SHOULD CONSIDER REV]SIONS TO THE AVO]DED COST
PRICING METHODOLOGY?
A. Yes. Eor the reasons I will explain further
below, it would be appropriate to address the avoided
cost pricing methodology if the util-ities have truly
demonstrated that there is an oversupply problem.
However, unlike Rocky Mountain Power, I believe that
adjusting the pri-cing methodology to send accurate price
signals is the only step that needs to be taken to
rectify any problems with Idaho's implementation of
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Simplot /Clearwater
PURPA.
O. HAVE THERE BEEN SOME OTHER CHANGES IN THE
METHOD TO FIND AVOIDED COST SINCE THE COMMISSTON ]SSUED
rTS ORDER rN GNR-E-11-03, THE CASE THAT APPROVED THE
CURRENT METHOD?
A. Yes. When Idaho Power filed with the
Commission its PURPA contracts with Boise City Solar
(IPC-E-14-20) and Grand View PV Solar Two (IPC-E-14-19)
the Commission
27 Rocky Mounatain Powerrs Petition, IPUC Case Nol-. PAC-E-15-03, p.
4.
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Simplot /Clearwater
Staff fil-ed Comments stating they were correcting some
"errors" caused by the simplifying assumption in Idaho
Power's single-run method approved by the Commission.
Staff then recalcul-ated the rates offered by Idaho Power
for the two contracts.23 The two projects decided to
accept the l-ower rates based on Staff's methodological
changes that were subsequently corrected by Idaho Power.
Rocky Mountain Power's suggestion to update the resource
stack more quickly to respond to large influxes of QFs
may also be approprlate.
O. IDAHO POWER ASSERTS THAT IT HAS AN OVER-SUPPLY
PROBLEM DUR]NG CERTAIN T]MES THAT CAUSES IT TO SELL PURPA
POWER ON THE MARKET AT AN ECONOMIC LOSS. DO YOU KNOI/I OE
OTHER ADJUSTMENTS TO THE AVOIDED COST METHODOLOGY THAT
COULD POTENTIALLY BE EXAMINED?
A. Idaho Power is describing a situation where the
actual avoided costs during certain ti-me frames may be
negative because the Company states j-t woul-d incur an
economic loss by accepting the QF power. The
Commission's Staff Production Request No. l-4 asked if
Idaho Power's single-run IRP methodology accounts for
such instances by assuming excess PURPA generation wil-l-
be sol-d at a l-oss, and thus lower the overal-l- average
avoided cost over the term of the contract. The Company
responded,
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Reading, Di 35a
Simplot /Clearwater
Within the Incremental Cost IRP Methodology (IRP
nethodoTogy) the hourly price is assiqned based on
the highest increment cost displaceabl-e generation
resource operating in that hour. The dispJaceabJ-e
resources being ldaho Power-owned qeneration,
incfuding any must-run l-imitations and ldaho Power
market
28 LPUC staff comments,
31, 2014) .
IPUC Case No. IPC-E-14-20, p. 5 (filed Oct.,
834
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purchases. If there are no displaceabl-e
tesources avaiTabTe in a specific hour, the energy
rate is set to $0 in that hour. The methodoToqy does
not assume excess PURPA qeneration will be soTd at a
f oss -29
o.
A.
HOW DO YOU INTERPRET THE COMPANYIS RESPONSE?
Idaho Power indicated that the single-run
methodology does not address the circumstance where the
avoided costs are negative due to uneconomic off-system
safes during the over-supply event, and instead assigns
an avoided cost of zero when the actuaL avoided cost is
negative.
O. WHAT WOULD BE THE IMPACT OF CHANGING THE
METHODOLOGY SO THAT IT COULD ACCOUNT FOR NEGATIVE AVOIDED
COSTS?
A. The average avoided cost offered to the QF
would incorporate these j-nstances of negatj-ve avoided
costs, and the instance of negative avoided costs would
cause the overal-l average rate cal-culated over the term
of the agreement to be l-ower.
O. WHAT WOULD BE THE REAL_WORLD IMPACT OE A LOWER
OVERALL AVOIDED COST ASSOCIATED W]TH THE INSTANCES OF
NEGATIVE AVOIDED COSTS?
A. The impact wou1d be that the IRP methodology
rates offered to prospective QFs would be lower. That
Reading, Di 36
S implot /Clearwater
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Simplot/Clearwater
lower price signal wou1d, based on that QF's projected
output profile, determine whether the project could be
economically developed. In this example, I would expect
that a fower avoided cost rate would have the impact of
deterring PURPA development.
29 Idaho Power's Response to IPUC Staffrs Production Request No. 18.
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Reading, Di 3'7
Simplot /Clearwater
O. ]N YOUR OPINION, IS AN ACCURATE PRICE SIGNAL A
BETTER WAY TO ADDRESS THE ALLEGED PURPA PROBLEM IDAHO
POWER TDENTIF]ED THAN A SHORTER CONTRACT TERM?
A. Yes.
O. DO YOU HAVE ANY OTHER COMMENTS ON THE
LIMITATIONS OE THE CURRENT S]NGLE_RUN METHODOLOGY?
A. The prior double-run methodol-ogy would have
accurately taken into account the instances where
off-system sal-es caused the avoided costs to be negative,
and in my opinion woul-d send more accurate price signals.
O. YOU HAVE JUST D]SCUSSED POTENTIAL ADJUSTMENTS
THAT HAVE BEEN MADE OR COULD BE MADE TO THE CALCULATION
OF AVOIDED COSTS. ARE YOU RECOMMENDING ANY OF THESE
CHANGES BE MADE AND APPROVED BY THE COMM]SS]ON?
A. No, not without considering other potential
adjustments to send accurate price signals. In a fully
litigated case deal-ing with avoided cost methodologies,
there woul-d no doubt be changes to the method of
calculating avoided costs that wouLd cause resulti-ng
increases and decreases to QF prices offered by the
util-ities. What I am suggesting is that correct pricing
should be used rather than an arbitrarily short contract
length that wi1l, oD its own, discourage PURPA
development. If the price is not sufficient to make a
project profitable at the utility's avoided costs, the
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length of the contract is irrel-evant and projects will
not be bui1t. The key is to properly price the avoided
costs at the utility's avoided costs. This is what PURPA
was intended to do and will- only encourage projects when
they meet a threshold price of the project being
economical.
Reading, Di 37a
Simplot/Clearwater
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O. WHAT ARE YOUR RECOMMENDATIONS EOR THE
COMMTSSION?
A. Because limiting the term of contracts to five
years or less wil-I essentially eliminate a1l- types of
PURPA projects includj-ng those that are envj-ronmentally
sound, fuel- efficient, and contribute to the economy of
the state, I recommend the Commission maintain the
current 2l-year contract length for QFs eligible for the
fRP methodology, or at a mj-nimum for all- non-intermittent
QFs. If adjustments need to be made to the Commission's
implementatj-on of PURPA, they should be made through the
calculation of avoided cost rates and not arbitrarily
limiting the term of the contract to a length that is
intentionally designed to prohibit financing or otherwise
ensure that no QE receives capacity payments.
o. DoES THrS END YOUR TESTIMONY AS OE APRIL 23,
20L5?
A. Yes.
839 Reading, Di 38
Simplot /Clearwater
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Reading, Reply 2
S implot /Clearwater
O. PLEASE STATE YOUR NAME AND BUS]NESS ADDRESS.
A. My name is Don Reading and my business address
is Ben Johnson Associates, 6010 Hill Road, Boise, Idaho.
I am Vice President and Consulting Economist for Ben
Johnson Associates.
O. ARE YOU THE SAME DON READING WHO PREFILED
DIRECT TESTIMONY IN THE CURRENT DOCKET ON APRTL 23RD,
20L5?
A. Yes.
O. WHAT IS THE PURPOSE OF YOU REPLAY TESTIMONY?
A. The following Reply Testimony is to provide
comments on the fntervenor testi-monies of Rick Sterling
and Yao Yin of the Commission Staff (Staff), Adam Wenner
and R. Thomas Beach for Idaho Conservation League and the
Sj-erra Club (ICLISierra), Anthony J. Yankel for the Idaho
Irrigation Pumpers Association (IIPA), John R. Lowe of
the Renewabl-e Energy Coal-ition (Coalition), Ken Miller of
the Snake River Alliance (SRA), and Mark Van Gulik of the
Intermountain Energy Partners (IEP)
Intervenors filed Direct Testimony
Each of the above
IN response to the
petitions filed by Idaho Power Company (Idaho Power),
Avista Corporation (Avista), and Rocky Mountain Power
(RMP) (colIectlvely the "Utilities") asking the Idaho
Publ-ic Utilitles Commission (Commission, IPUC) to modify
the terms and conditions of Public Utility Regulatory
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Pol-icies Act of 7978 (PURPA) contracts.
Five of the seven non-util-ity parties including
Simplot/Cl-earwater that filed di-rect testimony three
weeks ago strongly urged the Commission not to shorten QF
contract lengths from the current 20 years. The IIPA
witness Tony Yankel proposed a
Reading, Reply 2a
Simplot /Clearwater
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Reading, Reply 3
Simplot /Clearwater
temporary two year contract length as a "stopgap" in
order to allow time to correct errors he identified in
the Commission's avoided cost model. The Commission Staff
recommends maintaj-ning a 20 year contract length for
PURPA projects that currentl-y qualify for SAR-based rates
and a maximum five years for QEs subject to the IRP based
rates.
In our reply testimony, Simplot/Clearwater
recommend a compromise proposal pertaining to PURPA
contract length for QFs ineligible for standard rates.
We propose that capacity and energy be treated slightly
dj-fferently within the term of a 20-year contract. We
recommend the Commission mai-ntain a 2)-year contract
Iength with the capacity component of the rate fixed for
the entire 2O-year term. However, as a compromise, the
energy portion of the rate would only be fixed for the
first 10 years of the contract. After the first 10
years, the energy component would be reca1cu1ated each
year adhering to the Commission approved method for the
remainj-ng term of the contract. Simplot/Cl-earwater still-
bel-ieve the current 2O-year term, for reasons stated in
my direct testimony, should be maintained. However, as
descrlbed below, this al-ternative proposal- addresses some
of the concerns of the other parties.
O. YOU ARE RECOMMENDING THE ENERGY COMPONENT OF
842
THE 2O-YEAR CONTRACT BE UPDATED ANNUALLY OVER THE SECOND
TEN YEARS. ARE THERE CURRENT PURPA CONTRACTS IN IDAHO
THAT THE ENERGY PORT]ON IS UPDATED ANNUALLY?
A. Yes. There are approximately 25 PURPA
contracts that are adjusted periodically based on coal
costs. The commission uses the vari-abl-e costs associated
with the operation of Colstrip, a coal--fired generation
facility located in southeast Montana, for an annual
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Reading, Rep1y 3a
Simplot /Cl-earwater
843
adjustment of the adjustable portion of avoided costs for
those contracts. These projects had their rates set
using an older coaf SAR methodology. So there is ample
precedent for adjusting PURPA contracLs on an annual-
basis.
O. Are YOU AWARE OF OTHER PURPA CONTRACTS APPROVED
BY THE IDAHO COMMISSTON WHERE CAPAC]TY IS EIXED FOR THE
TERM OF THE CONTRACT AND ENERGY IS ADJUSTED PER]ODICALLY?
A. There are approximately 43 PURPA contracts tied
to Idaho Power's Schedul-e 89 where the energy rate is
adjusted when Net Power Supply Expenses (NPSE) are
changed in the Company's base rates. For these projects
the capacity component was fixed for the life of the
contract, however the utility's variable costs, including
fuel and variable operation and maintenance costs, are
adjusted when these expenses change in the Company's base
rates, most often in a general rate case filing. This
approach was intended to minimize potential overpayments
and underpayments. The Commission's rati-onal for
establ-ishing these contracts was:
Idaho Power appears particularTy sensjtive to
f l-uctuations in avoided energy costs. ATTowing
energy pagents derived from annuaL estimation of
avoided costs may obLigate the Conpany to paymentsin excess of the actual- avoided costs. Conversely,
annuaL estimates of avoided energy costs may aTso
al-l-ow the QF too LittLe. UnderpaTrments are Likely to
occur from this scheme during poor water years orduring nearly every year for those faciLitjes whoseproduction coincides with the months of high avoided
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Reading, Reply 4
Simplot /Cl-earwater
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Reading, Reply 4a
Simplot /Clearwater
energy costs. In the Tong runt a policy based on
Idaho Power's estimated avoided costs at delivery
time reduces the financial risk to both the utiTity
and the QF.l
If the Companies were filing periodic rate cases or
updates to base rates then the energy costs would be
adjusted every few years.
1 Order No. 15745, Docket No. P-200-72.
845
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Reading, Rep1y 5
Simplot /Cl-earwater
O. YOU STATED ABOVE YOUR ALTERNATIVE PITOPOSAL
ADDRESSES SOME OE THE CONCERNS OF THE OTHER P'\RTIES.
COULD YOU PLEASE BE MORE SPECIFIC?
A. The majority of the intervenors focused on the
inabil-ity of a PURPA project to receive financing with
shortened contracts on the one hand, and on the other
hand the Util-ities and Staff focused on the risks
ratepayers face from the utillties signing fi><ed-price
Iong-term contracts. As I explained 1n my direct
testimony, I do not agree with the latter contention of
ratepayer risk, however the alternative proposal offered
here addresses that issue by adjusting the energy
component annually during the second ten years of the
contract.
o. You SAID MOST OF THE TNTERVENORS ARii CONCERNED
ABOUT THE INABILITY OE PURPA PROJECTS TO OBTAIN FINANCING
USING SHORT_TERM CONTRACTS. COULD YOU C]TE SOME
EXAMPLES?
A. Without repeating the logic used by the
intervenors, the crux of their positions was made
clear in their direct testimony. The shorter the
contract length the more difficult it is to obtain
financing for a PURPA project. Eor exampfe, "The
consequence of a Commission order l-imitinq enerqy saLes
agreements to two or five years woul-d be to bring any
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Reading, RepIy 5a
meaningful PURPA deveTopment in ldaho to a halt."2 The
Renewable Energy Coalition witness John Lowe stated, " In
addition, imposinq a poTicy change l-ike a shortened
contract term on existing QFs coul-d have significant and
unnecessary harm on these projects, the utiLitres, and
ratepayers. l And,
This need for long tetm assurance of capitaTrecovery is the same for QFs as it ls for a utiTitythat proposes to buiLd a new power pTant and seeks
Commission
2 Direct Testimony of Mark Van Gul-ik, Intermountain Energy
Partners, March 23, 2075, IPC-E-15-01, p. 2.
847
Simplot /Clearwater
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Reading, Reply 6
Simplot/Clearwater
approval for Tong-term recovery of the plant's costs
by including them in rate base. This history
suggests that, without Tong-term/ 2)-year contracts,
QFs wiLL not be deveToped in ldaho.3
The Commission Staff, while recommending five year
contracts for IRP method based PURPA contracts, also
acknowledged,
O. But won't a five-year Linit on maximum contract
Tength, if approved, Timit the ability of projects
to obtain financing, thus making extensive project
deveTopment unlikely?
A. Yes, I agree that deveTopment wouLd Tikely sl-ow
considerabJy, at Least under PIJRPA.4
Also Snake River Al-l-iance witness Ken Mil-l-er said,
I think this application, if approved, wi77 cause
further migration of soLar deveTopers away from
Idaho, as the proposed reduction in contract terms
to two years -r.s tantamount to a freeze on future
solar PURPA projects.5
O. DR. READING, I REALIZE YOU ARE AN ECONOM]ST NOT
A LAWYER, BUT DID ONE OF THE ]NTERVENORS BXPRESS SOME
LEGAL CONCERNS ABOUT SHORTER CONTRACTS EAIL]NG TO MEET
FERCIS PURPA REQUIREMENTS?
A. Yes. ICL/Sierra witness Adam Wenner stated in
his direct testimony,
In the eLectric utility industry, and as djscussed
in ny testimony, a two-year term fails to permit a
QF to estimate, with reasonabl-e certainty, the
expected return on its potential- investment in a QF,and wouLd frustrate the requirement of section 210
of PURPA that FERC's ruLesr ds impTemented by staLe
commissions I encouraqe coqeneration and smal-7 power
production.6
B4B
1
2
3
3 oirect Testimony of R. Thomas Beach, Idaho Conservation
League and Sierra CIub, March 23, 20L5, IPC-E-15-01, p.10.4 oirect Testimony of Rick Ster]ing, Idaho PubIic Utilities
Commission Staff, March 23, 20]-5, IPC-E-15-01, p. 8.5 Direct Testimony of Ken Miller, Snake River AII-iance, March
23, 2015, IPC-E-15-01-, p.10.
6 oirect Testimony of Adam Wernner, Idaho Conservation League
and Sierra CIub, March 23, 20L5, IPC-E-15-0L, p. I0.
Reading, Reply 6a
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849
Simplot /Cl-earwater
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Reading, Rep1y 7
S implot /Clearwater
The al-ternative proposal offered here is aimed at finding
a balance among the parties' concerns about a QF's
ability to obtain financing, FERC's lega1 requirements
under PURPA and the risks of longer term fixed contracts
in an uncertain world.
o. you JUST usED THE TERM "BALANCE" AMONG THE
VARIOUS VIEWS OE THE PARTIES. WHY DO YOU BELIEVE YOUR
ALTERNATIVE PROPOSAL HELPS ALLEVIATE SOME OF THOSE
CONCERNS?
A. The alternative proposal offered here maintains
a fixed capacity component of the rate for the full
2)-year duration, whi-ch more closely matches the fixed
capacity J-ength of a utility-built facility. A QE, under
current Commission policy, does not receive capacity
credlts until- the utilityrs IRP shows a capacity deficit,
therefore putting a QF resource and a utility buil-t
resource on relatively equal footing. The energy
component, on the other hand, will be updated annually
over the last ten years of the contract, reducing the
perceived risk to ratepayers from fluctuating fuel costs.
Because the contract length would remain at 20 years and
have a fixed capacity component, it should give
financiers an additional- sense of confidence and al-so
addresses EERC's legal requirements. Of course the most
important aspect of this compromise is the incorporation
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Reading, Reply '7 a
Simplot /Cl-earwater
of a variable component for energy, the most volatile
portion of a utility's avoided cost.
O. YOU MENTIONED ABOVE YOU WANT TO ADDRESS, IN
ADDITION TO YOUR PROPOSED ALTERNATIVE, A SPEC]FIC ASPECT
OF A PARTY'S DIRECT TESTIMONY. V(HAT ASPECT WOULD YOU
LIKE TO ADDRESS?
A. Commission Staff wj-tness Rick Sterlj-ng stated,
O. Do you bel-ieve PURPA is an effective
mechanism for util-ities to acquire new
generation?
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A. No, I do not. I bel-ieve PURPA was intended
to permit reLativeTy smaJ-L, non-utiTity-owned
projects to be deveToped and to compete on an
equal footing with utifity owned facil-ities. I
do not bel-ieve PURPA was ever intended to serve
as the prinary, or even a major, mechanism for
utiTity acquisition of new resources.T
I fundamentally disagree with Mr. Sterli-ng's statement
that PURPA was "intended primarily to permit relatively
small non-utility-owned projects to be developed. "
Util-ities can, and do, develop PURPA projects. It is
true that in the early days, utilities could only own 50%
of a PURPA project, but that restrictj-on was repealed ten
years ago. PURPA, arising out of the energy crises of
1970's was part of National- Energy Act enacted in 1,978.
The l-aw was aimed at both relatively small renewabl-e
energy projects and large projects with no limit as to
size. These projects provide electrical energy at a more
fuel- efficient al-ternative to tradi-tional fossil fuel
utility base l-oad plant.
In addition, it appears at odds with Staff's
recommendations in this docket and Staff witness
Sterling's statement that PURPA was intended to a1low
these projects to "be developed and to compete on an
equal footing with utility owned facil-ities. " Eor
Reading, Reply 8
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example, Idaho Power's certificate of public convenience
and necessity (CPCN) for Langley Gulch does not expire
after five years with capacity rates adjusted to lower
ratepayer risk over the depreciated l-ife of the p1ant. I
would expect Idaho Power would have difficulty financing
the project with a CPCN that expired after five years.
One of the concepts behind the creation of PURPA is
that the market (a.k.a developers) could provide electric
power at prices that are competitive with regulated
utilities' resources. This has been proven to be true as
I demonstrated in my direct
7 Direct Testimony of Rick SterIing, Idaho Publ-ic Utilities
Commission Staff, March 23, 2015, IPC-E-15-01, p. 24.
Reading, Reply 8a853
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testimony. In addition as these facil-ities are added to
a utility's resource stack, they delay or eliminate l-ess
fuel efficient future utility-built generation p1ant.
PURPA therefore is indifferent to who provides the
generation of electric power, the utility or a
non-util-ity generator, only the avoided cost of providing
the power should be the determining factor.
O. DO YOU AGREE WITH MR. STERLINGIS STATEMENT ON
PAGES 20-21 THAT ''AVOIDED COST RATES HAVE EXCEEDED
COMPARABLE MARKET PRICES THROUGHOUT MOST OF THE HISTORY
OE PURPA IN IDAHO''?
A. No I do not. As I poJ-nted out in my direct
testimony comparing long-term avoided cost estimates with
current market prices is, from an economist's poi-nt of
view, inappropriate and mi-sl-eading. Long-term marginal
cost rates (avoided cost rates) are not the same as
short-term market prices. V0hen this Commission approved
the Langley Gul-ch plant for inclusion in Idaho Power's
rates, it did so using long-term cost estj-mates over the
expected life of the plant. Had the Commj-ssion used
current market prices as the benchmark, that plant would
probably not have been built.
o. WHAT ARE YOUR RECOMMENDATTONS EOR THE
COMMISS]ON?
A. While still- maintaining the recommendation put
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Reading, Reply 9a
forth in my direct testimony Simplot,/Cl-earwater are
offering an alternatj-ve proposal shoul-d the Commissj-on
decide alter the length of PURPA contracts. The
alternative recommendation is that capacity and energy be
treated differently within the term of a 20-year
contract. Capacity would remain fixed, however the
energy component would be recal-culated each year
beginning in the 11th year for the remainj-ng 10 years of
the contract.
O. DOES THIS END YOUR TESTIMONY AS OF MAY L4,
20\5?
A. Yes.
855
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READING (X)
Simplot /Cl-earwater
(The following proceedings were had in
open hearing. )
MR. RICHARDSON: Mr. Chairman, Dr. Readlng is
availabl-e for cross-examination.
COMMISSIONER KJELLANDER: Thank you very much.
Letrs begin with Staff.
MR. HOWELL: Thank you, Mr. Chairman.
CROSS-EXAMINATION
BY MR. HOWELL:
O. Good morning, Dr. Reading. I just have a few
questions, mostly about your direct testimony.
A. Okay.
O. On page 2 around about line 17, you address
Simplot's QF project at its fertilizer plant in
Pocatel-l-o
A. Yes.
a. and you say it has sold the output under a
serj-es of PURPA contracts. Do you know when Simplot
began selling its output to Idaho Power with PURPA
contracts?
A. Oh, wow. A while ago. That's as close as I
can come.
O. Maybe you can answer this question: During the
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READ]NG (X)
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time that 1t sold power under PURPA contracts, has
Simplot ever had a 2)-year contract with Idaho Power for
PURPA?
A. The Magic Va11ey -- Magic Reservoir was a 24
35-year.
O. And that contract, since you brought it up,
Magic Va11ey or Magic Reservoir, Simplot wasnrt the
initial party in that case, was it?
A. I do not know.
O. Wel-I, in Order No. 27358, it says the
Commission on July 10, 1987, approved an Order for firm
energy sal-es between Idaho Power and Cook Electric, Inc.
Is Cook Electrj-c, Inc. Simplot?
A. Not to my knowledge.
O. Later in Case IPC-E-98-L4, the Commission i-n a
notice of modified procedure said or described that Magic
Reservoir Hydroelectric, Inc. was the successor to Cook
Electri-c.
MR. RTCHARDSON : Mr . Cha j-rman , if counsel f or
the Staff could make these documents he's referring to
avaiIab1e to the witness, it might be helpful for the
witness to respond.
COMMISSIONER KJELLANDER: Mr. Howel-l.
MR. HOWELL: That ends my questj-ons about
whether Idaho Power and Simplot were the original parties
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CSB REPORTING
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in the hydroelectric project.
COMMISSTONER KJELLANDER: It sounds ].iKe he
surrendered.
O. BY MR. HOV{ELL: So can you tel_l- the Commission
whether Simplot at its Pocatel-l-o facility has ever had a
1S-year contract?
A. Not to my knowledge.
O. Has it ever
A. I know they've had a series of contracts of
varying lengths. Beyond that, I will yield to your
research of how long the history of the contracts are.
O. Can you tel-I the Commissj-on what the longest QF
contract was between Simplot?
A. The longest that I can remember, I think, was a
five-year, but subject to check, I'd have to Iook through
the records.
O. All right, thank you. I'd like to move on now
to Clearwater's QF contracts and has Clearwater or its
predecessor Potlatch ever had a 20-year QF contract with
Washington Water Power or Avista?
A. Not to my knowledge.
O. Has it ever had a 15-year contract?
A. I do not know the history of the length of the
contract for Clearwater's cogeneration facility.
O. And on page 3, line !9, you talk about the
READING (X)
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current contract that was entered into in 201-3. Is that
contract a PURPA contract?
A. I think its current status is not PURPA.
O. And on l-ine orr excuse me, on page 4 of your
direct testimony, line 9, you state that Clearwater is
considering constructing a new cogen facility that woul-d
assist the State of Idaho in complying with EPA's
proposed 111(d) rule. Can you te1l the Commission if
that rule is final-?
A. As we al-l- know, it is not final.
0. And have you read Idaho's comments to that
proposed rule?
A. Bits and pieces.
O. And can you te11 the Commission what the
prj-mary recommendatj-on of the State of fdaho was in
response to the proposed rul-e?
A. The general tone of it was the who1e thing
shoul-d go away.
O. Would it be fair to characterize that the State
of Idaho said that the proposed rule shou1d not apply to
Idaho because fdaho's generation mix is already very low
and the second l-owest in the nation?
A. I woul-d yield that is there. There's also lots
of discussions around l-11(d) that it shoul-d be a regional
sol-ution, and the reason for that is, of course, and why
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READING (X)
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Idaho has such a l-ow carbon footprj-nt, for want of a
better word, is that physically within the boundaries of
the stater w€ don't have any coal facilities; however,
about, I think, Idaho Power hal-f of the consumption in
Idaho Power's territory is from coal- plants, so the
surroundj-ng states are certainl-y moving ahead with trying
to have a regional sol-ution and have the decision of the
carbon footprint based on something like consumption
rather than the physical- location of the individual
plants.
O. And when you talk about regional solutions, are
you talking about states entering into multi-state plans
on a state-by-state basis?
A. Yes, I am.
O. And what do you think the likelihood of the
State of Idaho or Oregon entering into a contract?
A. I don't know. That's speculative and sort of
what witnesses are never supposed to, but moving ahead
where you're going with this l-ine
O. I'm happy if you just say it's speculation.
A. Okay, and specul-ation and explain what I mean
by speculation, 111(d) may go away. The mu1ti-state
compact may go away. Given what the Supreme Court
decided yesterday on mercury emissions, the courts may go
away. Given al-l- of that speculation, I firmly believe
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READING (X)
Simplot /Clearwater
that down the road, maybe sooner than later, there will
be higher costs for carbon, whatever kind of rules or
l-aws or whatever that will be lmposed on all states in
the U.S., primarily from ol-der coal plants, so we can say
l-l-1(d) is not going to work, Wyoming and Idaho will never
get together except hunting el-k or something, but Irm
convinced that there will- be a carbon penalty for
electric generation in the next five, ten years.
MR. HOWELL: Al-1 right, thank you. I have no
further questions.
COMMISSIONER KJELLANDER: Thank you, Mr.
Howell-. Let's move to Idaho Power.
CROSS-EXAM]NAT]ON
BY MR. WALKER:
o.
A.
Good morning, Dr. Reading.
Good mornj-ng.
O. So Dr. Reading, I see from your experience and
credentials that you were on Staff at the Idaho Pub1ic
Utilities Commission from '81 to '86; is that correct?
A. Correct.
O. So coul-d you teI1 usr Dr. Reading, you used the
acronym CPCN in your testimony, can you tel-l- usr what
does "CPCN" stand for?
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READ]NG (X)
Simplot /Clearwater
A. Did I misspell that?
O. No, CPCN.
MR. RICHARDSON: Do you have a specific
citation to where in hls testimony you're referring?
MR. WALKER: No, just generally.
MR. RICHARDSON: You don't have any idea where
you're referring to?
MR. WALKER: Throughout his rebuttal-
testimony.
MR. RICHARDSON: Can you give us an example?
MR. WALKER: I don't think he needs an example
to answer a general question of what the acronym CPCN
stands for.
MR. RICHARDSON: So you don't know where in his
testimony you' re referring?
MR. WALKER: I'm referring to his rebuttal
testimony.
MR. RICHARDSON: What page? What line?
MR. WALKER: That's not necessary.
COMMISSIONER KJELLANDER: Mr. Richardson and
counsel- for fdaho Power, I feel- comfortable enough that
the witness does have the ability to respond to a general
question about that acronym, and if he doesn't know, he
can say he doesn't know. Let's move on with this and if
the witness would respond one way or the other.
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READTNG (X)
Simplot /Clearwater
THE WITNESS: frm sure what I meant to say is
certificate of public convenience and necessity. Being
slightly dyslexic, it doesn't surprise me I would have
that mixed up.
O. BY MR. WALKER: So can you tel-I us based on
your experience, including your work at the Public
Utilities Commission, whatrs the meaning of that
certificate of public convenience and necessity?
A. That means that the Commission approves the
building of a generation facility for the utility that is
applying for it.
O. And is a CPCN required in Idaho in order for a
utility to build a genegation resource?
MR. RICHARDSON: Mr. Chairman, he's calling for
a legal concl-usion. Dr. Reading is not an attorney.
MR. WALKER: Dr. Reading is a former Staff
member of the Commission and I believe his experience, he
can speak to what a CPCN means and if it's required.
MR. RICHARDSON: It calls for a 1egal
conclusion, Mr. Chairman.
MR. WALKER: Actual1y, on page 8 of his
rebutta1 testimony and page 9, he discusses the
requirements of a CPCN in relation to the Langley Gul-ch
generation plant, So I would l-ike to explore his
understanding of that.
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READ]NG (X)
Simplot/Clearwater
T
;
COMMISSIONER KJELLANDER: As a recommendatj-on,
why not refer directly to those lines and that page
number within the construction of your question and I
think you can probably get to where you want to go.
O. BY MR. WALKER: Mr. Reading, on page I of your
rebuttal-
MR. RICHARDSON: Dr. Reading, not mister.
MR. WALKER: He's not a mister?
COMMISSIONER KJELLANDER: Gentlemen, might f
just for purposes of trying to move forward, there
appears to be just a level of combativeness that perhaps
is unnecessary. We recognize that Dr. Reading has
wonderful credentials and not being impugned here. We're
simply getting to the bottom of this, So let's just move
forward and see if we can't get through this in a very
civil- f ashion.
MR. WALKER: Certainly.
O. BY MR. WALKER: On page 8, Iine 16 and line L9,
and page 9,Iines 9 through 15, you have some discussion
about a CPCN, and an opinion that Idaho Power, line 18
through 19 on page 8, that Idaho Power would have
difficulty financing a project with a CPCN that expired
after five years, and my question was, is a CPCN required
for a utility to buil-d a generation facility?
A. Just a moment. I would like to find that so I
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CSB REPORTING
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can read what we I re talking about. ttilould you give me the
references again?
O. Page 8 of your rebuttal.
A. Okay. Okay, repeat the question.
O. Is a CPCN required in ldaho for a utility to
build a generation facility?
A. My understanding is that -- being a non-lawyer,
my understanding is that it is.
O. And is a CPCN required before a utility is
required to purchase a QF's output?
A. No.
O. And if a QF purchase had to meet the same
requirements as a utility to build a resource, would that
QF purchase be approved today under today's
circumstances?
A. It would depend on what it is and what the
price is and what the impact is. I canrt answer that
without knowing specifically what kind of project it
is.
O. lilhat if it was an 80 megawatt solar QF project?
A. Would it be approved by the Commission?
O. We1l, 1et me rephrase in this manner: If the
1r 336 megawatts of proposed QF solar were instead
proposed for construction by Idaho Power in a CPCN
proceeding, do you think that would be approved under
865 READTNG (X)
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READING (X)
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today's circumstances?
A. I would doubt it. It would depend on what the
price is. It woul-d depend on various things, but I will
add that, and I can't remember whether it's in my direct
or my rebuttal-, during the Enron meltdown, the Commission
approved the Danskin project which a year before wou1d
have never got approved. In that Order, the Commission
said that due to all of these unusual- circumstances that
we'fl waive the fact that it wasn't in the IRP and did
rapid approvalr so your generic question is whether a
who1e bunch of sol-ar would be rubber-stamped and approved
through a certificate process, I would certainly doubt it
right now, but that doesn't mean that for whatever
reason, whether it l-eads back to Mr. Howel-l-'s discussion
of carbon, things often change and I certainly would
be1ieve that if Idaho Power proposed a sol-ar project of
whatever size and was able to cost justify it, then the
Commission wou1d approve it.
MR. WALKER: I have no further questions.
COMMISSIONER KJELLANDER: Thank you. Let's
move now to Avista Corporation.
MR. ANDREA: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you.
PacifiCorp.
MS. HOGLE: PacifiCorp has no questions. Thank
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you.
COMMISSIONER KJELLANDER: Thank you. Let's
look to anything from the Idaho Conservation
League/Sj-erra Club?
MR. OTTO: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you, Mr. Otto.
Intermountain Energy Partners, Mr. Mil-l-er.
MR. MILLER: No, thank you.
COMMISSIONER KJELLANDER: Ms. Nunez.
MS. NUNEZ: No questJ-ons.
COMMISSIONER KJELLANDER: MT. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Sanger.
MR. SANGER: No questions.
COMMISSIONER KJELLANDER: Yourre sort of hiding
out over there. Good to see you. Mr. Hammond.
MR. HAMMOND: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Arkoosh.
MR. ARKOOSH: No, Mr. Chairman, thank you.
COMMISSIONER KJELLANDER: Mr. Schmidt being new
to the process, do you want to weigh in?
MR. SCHMIDT: Boy, itrs tempting, but I'11
pass. Thank you.
COMMISSIONER KJELLANDER: Fair enough. Are
there questions from the Commission?
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READING (Com)
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EXAMINATION
BY COMMISSIONER KJELLANDER:
O. I just have a littl-e bit before we get to
redirect and j-t's nothing heavy and if it's something
that you'd feel uncomfortabl-e in responding to, just say
so and we'11 stop, unless you say you're uncomfortable
with it before I ask. You've been around for a long
time. You've testified in front of us multiple times and
a lot of it tied to PURPA-related cases, and part of
where I'm going with this is that we've had one public
hearing and we've got another telephonic hearing coming
up this evening, and the general impression that we get
from a lot of people who testify publicJ-y is that there's
a perception or at l-east the illusion of a perception,
perhaps my illusion of my interpretation of what they're
saying, is that there seems to be some underlying belief
that the only way renewables will be developed is through
PURPA. In your experience, are there other options that
a utility can util-ize to develop renewable resources?
A. Correct.
O. And among them there are RFPs?
A. Yeah, RFPs.
O. Sel-f -builds ?
A. Se1f-build, yes.
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O. And if you were to look down the road and
hearing your testimony earlier, there was some futuristic
projections of what you see happening, and one way or the
other I think we all probably come to a singular
conclusion that the likel-ihood of there being any new
coal-fired generat.ors built is slim to none; would that
be your assessment?
A. That woul-d certaj-nly be my assessment, y€s.
O. So assuming that you and I are on the same page
with that, what are the next resources, then, that a
utility would look at, whether they're PURPA resources or
whether they're RFP resources? If they need to serve
future load, what are their opti-ons?
A. The current option of choice is gas plants,
because their emissj-ons, their carbon emissions, are
about half of what a coal plant is, and I'I1 put a
footnote on that that, you know, the general assumption
is that gas j-s rock bottom and gas will- always stay rock
bottom, and I have enough gray haj-r that once we all
agree that something is going to happen, that te1ls me
that that is not going to happen.
O. Yeah, I have gray hair, too. I remember the 10
and $14.00 per megatherm prices.
A. Right, for instance, you know, fracking, I
wouldn't be shocked if we had a major problem with
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fracking somewhere, whether it's earthquakes or fires or
whatever
O. So if I cou1d interrupt, then, we 're probably
in agreement that natural gas is a resource that today
looks like the next viabl-e resource, but the volatility
that we've seen in pricing coul-d alter that, so what
else ?
A. So then we do move to the "renewable
resources, 'r such as wind and solar and biogas and those
kj-nds, so I think looking down the road, if f were to
forecast and knock on wood I'm goi-ng to be around to see
it, that the utility mix in the future for utilities
would be a much higher percentage of renewables and I
believe that whether Idaho Power ever I mean, the
State of Idaho ever gets RPS standards or not, that's
where the el-ectric generation worl-d is moving.
O.So then if I coul-d sum this up and you can
agree or disagree or add to it, regardless of whether
it's PURPA, an RFP or self-build, it's your perception
that renewabl-es will be in Idaho Power's future, Rocky
Mountain Power's future, and Avista's future
A. Yes.
O. as it relates to serving future l-oad?
A. Right, and I think specifically to the cl-ients
that hired me for this case, I think CHP is going to
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CSB REPORTING(208) 890-s1-98
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become even more j-mportant because of its use of already
generated it's so fuel efficient relative to a regular
gas plant or a coal plant.
COMMISSIONER KJELLANDER: Thank you. Redirect?
MR. RICHARDSON: Thank you, Mr. Chairman. I
have no redirect.
COMMISSIONER KJELLANDER: Thank you. Thank
you, Mr. Reading, always a pleasure to see you.
(The witness left the stand. )
COMMISSIONER KJELLANDER: Let'S move now to
Staff for the Public Utillties Commission.
MS. HUANG: Thank you, Mr. Chairman. The Staff
would call Dr. Yao Yin.
YAO YIN,
produced as a witness at the instance of the Staff,
having been first duly sworn to tel-l- the truth, the whole
truth, and nothing but the truth, was examined and
testified as follows:
DIRECT EXAI{INATION
BY MS. HUANG:
O. Good morning, Dr. Yin.
A. Good morning.
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O. Woul-d you please state your fuII name and spe11
your last name for the record?
A. Yao Yin, Y-i-n.
a. By whom are you employed and in what
capacity?
A. I rm employed by the Idaho Public Utilities
Commission as a utilities analyst.
O. Are you the same Yao Yin who f11ed direct
testimony in this matter on April 23rd, 2015?
A. Yes, I am.
O. Do you have any changes you'd like to make to
your testimony, changes or corrections?
A. I do. On page 9 of my testimony, line 24, the
word "avoid" should be changed to "avoided. "
O. And do you have any other changes to your
testimony?
A. I do not.
O. If I were to ask you those same questions that
are set forth J-n your direct testimony with that change,
wou1d your answers be the same today?
A. Yes.
MS. HUANG: Mr. Chairman, I would move that Dr.
Yin's testimony be spread on the record.
COMMISSIONER KJELLANDER: And wi-thout
objection, we wil-l spread the testimony of Dr. Yin across
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the record as if read.
(The fol-l-owing prefiled testimony of Dr. Yao
Yin is spread upon the record. )
YIN (Di)
StaffCSB REPORTING
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O. Please state your name and business address for
the record.
A. My name is Yao Yin. My business address is 472
West Washington Street, Boise, Idaho.
O. By whom are you employed and in what capacity?
A. I am employed by the Idaho Public Utilities
Commission as a Utilities Ana1yst.
O. What is your educational and professional
background?
A. I received a Bachelor of Science in Biol-ogical
Sciences from Shandong University in 2006. Later, I
earned a Master of Science in Molecular Cellular Biology
(2007), a Master of Public Policy in Environmental Policy
(2009), and a Ph.D. in Environmental Science (2071), al-I
from Oregon State Unj-versity. I will be attending the
Practical Regulatory Training for the Electric Industry
Course held May 17-22, 20L5 by the Center for Public
Utilities at New Mexico State University.
Prior to joining the Commj-ssi-on, I worked for
Energy Biosciences Institute at Universi-ty of Il-Iinois at
Urbana-Champaign as a Postdoctoral Research Associate.
Later, I worked for the Energy Polj-cy Institute at Boise
State Universj-ty as a Research Assistant Professor. I
joined the Commission in May 20L4.
O. What is the purpose of your testimony in this
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proceeding?
A. The purpose of my testimony is to review Rocky
Mountain Power's proposal to change its indicative
pricing practice in the Integrated Resource Planning
(IRP) methodology so that it may provide more accurate
avoided cost rates to proposed QF projects.
O. What do you mean by "proposed QF prolects"?
A. "Proposed QF projects" are projects for which a
QF developer has requested indicative avoided cost
prices, and is actively pursuing or negotiating a power
purchase agreement (PPA) with a utility.
O. Do the "proposed QF projects" j-ncl-ude QE
projects that are seeking SAR-based published rates?
A. No, not in the context of my testimony as
discussed here. SAR-based projects that are seeking
published rates (those that are smaller than the
published rate eligibility cap) may request the current
published rates approved by the Commi-ssion.
O. Are you proposing changes to the Integrated
Resource Planning process?
A. No. SAR-based projects, IRP-based projects,
and other long-term non-PURPA contracts w1l-I continue to
be incl-uded in the IRP planning process as contracts are
signed.
My testimony addresses a change to the practice
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of giving indicative pricing to proposed QF project that
are negotiating IRP-based avoided cost rates as part of
the IRP metho&legI.
O. Does the term "proposed QF project" refer to
projects that make general inquiries about procedures for
obtaining a PURPA contract?
A. No. Typically, a QF is considered a proposed
QE when it is seriously pursuj-ng a power purchase
agreement (PPA) and makes it to the stage of requesting
indicative avoided cost prices. Projects at earlier
stages, such as the general- inquiry stage, are typically
not considered as proposed projects.
O. What are j-ndicative prices?
A. Indicative prices are preliminary estimates of
avoided cost rates which serve as the starting point for
negotiations between QEs and a utility. They may differ
from the final- prices in a contract (i.e., contract
prices).
O. What do QE projects need to do before
requesting indicative prices from a utility?
A. Idaho Power's Schedul-e 73 and Avista's Schedule
62 specify the information a project needs to submit
before requesting indicative prices. Rocky Mountain
Power does not have a simil-ar schedul-e in Idaho, although
I recommend it propose one so that QF projects can have a
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better idea of the procedures for requesting indicative
prices in fdaho.
O. Please descrj-be the current indicative pricing
practice approved by the Commission.
A. Currently, proposed projects are not placed in
a queue but are instead treated for pricing purposes as
if they are all the first project to receive the next
indicative prices. In other words, the first proposed
project, the second proposed project, the third proposed
project...wil-l all be treated the same as the first
project for purposes of receiving indicative pricl-ng.
The indicative prj-ces, however, can be
recalculated (before they become contract prices) if an
ear.l-ier contract is signed, or if a signed contract is
removed.
O. Which Commission Order approved of this
practice?
A. In Case No. GNR-E-11-03, the Commission stated
that "1ong-term contracts shall be considered in IRP
Methodology calculations at such time as the utility and
QF have entered into a signed contract for the sale and
purchase of QF power." Order No. 32691 at 22. (Emphasis
added) .
O. Are there practi-caI concerns with this
practice?
A. Theoretically, this practice may result in
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accurate avoided cost rates by allowing indicative prices
to be recalculated when an earlier contract is signed.
In reality, however, it can be very difficul-t to
recalculate rates for proposed projects in a timely
manner when there are many projects seeking indicative
prices at the same time. As Rocky Mountain stated on
page I of its Petition in this case (PAC-E-15-03), "the
currentl-y approved requirement that the Company's avoided
cost rate modeling can only be updated to account for
signed QF contract Is] wiIl resul-t in PURPA Icontracts]
. based on indicative pricing that becomes inaccurate
. . " The inability to update indicative pricing
"will- result in payments to QEs that exceed avoided costs
. ." (Rocky Mountain Petition at 33.)
In addition, a QF may not want to re-negotiate
the new updated rates, because the new indicative prices
may be lower than the original ones. New indicative
prices may be l-ower because, under the IRP methodology,
each successive QE displaces l-ower-cost resources in the
utility's dispatch stack
O. V'lhy were these concerns not much of an issue 1n
the past?
A. The current indicative pricing practice works
wel-I when individual project sizes are smal-l-, cumulative
project sizes are small-, and multiple projects are not
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being proposed at about the same time, because the
resulting indicative prices are accurate and rarely need
to be recalcul-ated. Today, however, PURPA project sizes
are much larger, both individually and cumulatively, and
multiple projects frequently seek indicative prices at
the same time. Under this circumstance, the sequence of
projects, which determines every project's avoided cost
rates, needs to be established to reflect how each
project actually displaces the utility's resources and
contributes to the utility's capacity. UnIess indicative
pricing is abl-e to reflect the actual- impacts of each
project, inaccurate avoided cost rates may result.
PIease describe the new indicative pricing
practi-ce proposed by Rocky Mountain.
A. The new indicative pricing practice would offer
more accurate indicative prices to QFs by putting all the
proposed projects into a gueue based on the times they
request indicative prices. As Rocky Mountain describes
the proposed change on page 38 of its Petition, the
proposed modified indicative pricing practice "reflects
all active QF projects in the pricing queue ahead of any
newly proposed QF requests for indicative pricing. "
O. Are there advantages to the newl-y proposed
practice?
A. Yes. When all proposed projects are placed in
a.
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a queue, rather than being treated as the first project,
each project wil-l- receive different indicative pricing,
depending on its position in the queue. Generally, the
higher the position in the queue, the higher the avolded
cost rates. Using a queue wil-l allow indicative pricing
to refl-ect how each project actually displaces the
utility's resources and contributes to the utility's
capacity at the start of the negotiation process.
a. Can you give an example to show how the new
indicative pricing practice would impact contract prices?
A. Rocky Mountain witness Dickman provides an
example on page l-0 of his direct testimony. There he
states "[t]he Company cal-cul-ated the impact on the IRP
Method avoided costs of including roughly 3,000 MW of
proposed QEs Igeneration] (located in Idaho, Utah,
Wyoming, Oregon) prior to the next Idaho QF. Accounting
for these proposed QFs rather than just those QFs with
signed contracts reduces avoided costs for the next Idaho
QE in the pricing queue by approximately $18 per MWh on a
2)-year levelized basis . . "
If proposed projects are not placed in a queue,
there could be substantial- overpayments in avoided cost
rates to the QFs.
O. Indicative pricing using this methodology
assumes that the proposed projects wil-1 be built
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eventually, but what if a proposed project drops out of
the queue?
A. If projects drop out of the queue, utilities
will recal-culate the indicative prj-ces for projects
succeeding the dropped one, and the parties would
negotiate based on the new rates. Obviously, the new
rates wil-L be higher than the original rates, because all-
the projects that are situated lower in the queue wil-l be
bumped up to displace higher-cost resources and have
better opportunity to contribute to the utility's
capacity need. Because the remai-ni-ng projects will
receive higher avoided cost rates, they wil-1 financially
benefit and should readily accept the new, higher rates.
O. Under the proposed indicative pricing practice,
is it 1ike1y that in order to get higher indicative
prices, projects will try to request indicative prices as
soon as possj-ble to save an earl-ier spot in the queue
even if QFs are not ready to seriously negotiate an
IRP-based PURPA contract?
A. Both Idaho Power's Schedule 13 and Avista's
Schedule 62 require projects to provide specific
information about each project before the util-ities
provide indicative pricing. Al-so, the schedules specify
timeline milestones for QFs to meet as projects and
negotiations progress.
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Staff recommends that Rocky Mountain should
file a simj-lar tariff schedule to Iay out the PURPA
negoti-ating process and prevent projects from prematurely
requesti-ng indicative pricing.
a. If a QE changes significant detail-s about its
project, will the QF remain 1n the queue?
A. Yes, but not in the same queue position. Rocky
Mountain Power states in its response to Staff's first
producti-on request that "j-f the QF changes significant
details about the prolect (such as site location, online
date, or project size), the QF is removed from the queue
and then re-enters the queue at the bottom as a new
request with the new project description. " I agree with
Rocky Mountain's approach, but believe specific criteria
may need to be developed for management of the queue,
such as rules for QF entry, re-positionJ-ng, and removal
from the queue.
O. What is your recommendation regarding Rocky
Mountain's request to change its indlcative pricing
practice?
A. I recommend that the indicative pricing
practice provided to proposed QF projects be updated to
place all the proposed projects in a queue, thereby
providing more accurate and up-to-date avoided costs.
The Commissj-on should dj-scontinue the "signed contract"
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requirement in Order No. 32697 for purposes of giving
indicative pricing to IRP-base projects. Fina11y, Rocky
Mountain should be direct.ed to file a tariff schedule
outl-ining its PURPA contracting procedures in Idaho.
O. Does this conclude your direct testimony in
this proceedj-ng?
A. Yes, it does.
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CSB REPORTING(208) 890-s198
YrN (X)
Staff
(The following proceedings were had in
open hearing. )
MS. HUANG: Thank you, Mr. Chair. Dr. Yin is
now available for cross-examination.
COMMISSIONER KJELLANDER: Let's just move down
the l-ist and keep it simple for me. Idaho Power.
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. ADAI4S: No questions from Simplot.
COMMISSIONER KJELLANDER: Mr. Richardson.
MR. RICHARDSON: Just one, Mr. Chairman.
CROSS-EXAMINATION
BY MR. RICHARDSON:
O. Dr. Yi-n, on page I of your direct testimony on
Iine 3, you talk about projects dropping out of the
queue?
A. Yes.
O. Do you have any proposal or system in mind for
how projects are dropped out of the queue?
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CSB REPORTING(208) 890-s198
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A. How they drop out of the queue?
O. Right, because it seems to me that you could
accumulate projects that are not serious projects in the
queue that a utility might leave in the queue in order to
artificially lower the avoided cost rate, so is there
some sort of system for dropping projects out of the
queue you had in mind?
A. I think right now we don't have specific rules
for queue management and I think the util-ities should
come up with specific management rules to deal with
situations like dropping out, repositioning, reentering
into the queue r ot removal from the queue. I think we
shoul-d in the near future develop specific rules.
0. And I think you testified that PacifiCorp does
not have a tariff on fil-e in Idaho. What is your
recommendation for PacifiCorp in terms of filing a tariff
for setting the procedures for QFs to get in the queue
and fal-l out of the queue or whatever?
A. Two points. I think, first of all, PacifiCorp
should fil-e a simil-ar tariff schedul-e si-milar to ldaho
Power's Schedule 73 and Avista's 62 to specify the
specifJ-c procedures for the QF to be able to request
indicative prices and also as to the specific rules for
queue management. I think it's a different order or
different j-ssue so that I don't envision two things
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CSB REPORTING
(208 ) 890-5198
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combined in the same order.
O. And do you recall in the last generic avoided
cost case, thj-s Commission ordered al-l- the three
utilities Lo file such a tariff?
A. Say your question again.
0. Do you recall that in the last generic avoided
cost docket, this Commissj-on ordered all three utilities
to file a queue management tariff?
A. f donrt think I was hired.
MR. RICHARDSON: Okay, thank you.
COMMISSIONER KJELLANDER: The other response is
it's beyond my pay grade, they both work. Letrs see, who
is next? Mr. Ott.o.
MR. OTTO: No questions, Mr. Commissioner.
COMMISSIONER KJELLANDER: Mr. Mi1ler.
MR. MILLER: Thank you, Mr. Chairman, just one
or two.
CROSS-EXAMINATION
BY MR. MILLER:
O. Good morning, Doctor.
A. Good morning.
O. Ir{elcome to the wor1d of public utility
testifying.
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CSB REPORTING(208) 890-s198
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A. Thank you.
O. I hope itrs not a too burdensome experJ-ence for
you. I always say it's no worse than your standard root
canal, right. I just have one questj-on on page 9 of your
testimony.
A. Okay.
O. At the very bottom on the last two lines, you
suggest that the Commission discontinue the signed
contract requirement for purposes of giving indicative
pricing. Are you recommending that with respect to the
Idaho Power method of computing or providing indicative
pricing or just PacifiCorp?
A. The proposal- that PacifiCorp is proposing is
the queuing methodology and Idaho Power has adopted it in
the 13 sofar parties.
a. Currentl-y the Idaho Power methodol-ogy is based
on signed contracts; right?
A. No. It's based on PacifiCorp's methodology
that it is proposing.
O. I'm sorry, I couldn't quite hear you.
A. Idaho Power has already applied the method
PacifiCorp is proposing.
O. And 1t uses a signed contract?
A. No, PacifiCorp is proposing the queued
methodology, the queuing.
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CSB REPORT]NG
(208 ) 890-s198
YrN (X)
Staff
O. So you're not proposing, then, afly change to
the Idaho Power methodology as you understand it?
A. Can you say the question again?
O. Your proposal here to el-iminate the signed
contract requirement is not intended to modify the
existing Idaho Power methodol-ogy?
A. Define "existing Idaho Power methodology. " Can
you define the exj-stj-ng Idaho Power's methodology for me,
please ?
O. Give me a second here. Going back to page 4 of
your testimony, you reference the Commission Order 3269"7
in Case GNR-E-11-03.
A. Riqht. That's the methodology in the Order and
I'm proposing we shoul-d change that methodol-ogy.
a. With respect to Idaho Power?
A. With respect to Idaho Power, Idaho Power has
already adopted this methodology in their 13 sol-ar
projects. n
O. So is it your understanding that ldaho Power
has already moved away from signed contracts?
A. Correct.
O. Is that what you're saying?
A. Uh-huh.
MR. MILLER: Al-l- right, I think that clarifies
it i-n my mind, I think.
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THE V{ITNESS: Thank you.
MR. MILLER: That's all I have.
COMMISSIONER KJELLANDER: Thank you,
Mr. Miller. Ms. Nunez.
MS. NUNEZ: No questions. Thank you.
COMMISSIONER KJELLANDER: Thank you. Mr.
Olsen.
MR. OLSEN: No questions.
COMMISSIONER KJELLANDER: Mr. Sanger.
MR. SANGER: No questions.
COMMISSIONER KJELLANDER: MT. Hammond.
MR. HAMMOND: No questions, Mr. Chairman.
COMMTSSIONER KJELLANDER: MT. ATKoosh.
MR. ARKOOSH: No, thank you, Mr. Chairman.
COMMISSIONER KJELLANDER: And Mr. Schmidt.
MR. SCHMIDT: No, thank you.
COMMISSIONER KJELLANDER: Any questj-ons from
members of the Commission? WelI, you've been baptized.
You are now are officialfy a witness at the PUC.
Oh, Irm sorry, redirect. One chance for your
worst enemy, your own attorney, to ruin your day.
THE WITNESS: Okay.
MS. HUANG: No redlrect, thank you.
COMMISSIONER KJELLANDER: You got off easy.
THE WITNESS: Thank you.
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CSB REPORTING
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STERLTNG (Di)
Staff
(The witness l-eft the stand.)
COMMISSfONER KJELLANDER: Al-l- right, Staff
would call their final witness.
MR. HOWELL: Thank you, Mr. Chairman. We would
call Rick Sterling to the stand.
RICK STERLING,
produced as a witness at the instance of the Staff,
having been first duly sworn to teII the truth, the whole
truth, and nothing but the truth, was examined and
testified as follows:
DIRECT EXAMINATION
BY MR. HOWELL:
O. Cou1d you state your name and spe1l your last
for the record, please?
A. My,name is Rick Sterling, S-t-e-r-1-i-n-9.
O. And Mr. Sterling, whom are you employed by and
in what capacity?
A. I'm employed by the Idaho Public Utilities
Commission as an engineering supervisor.
a. Are you the same Rick Sterling that fil-ed
direct testimony dated April 23xd and rebuttal testimony
dated May 14th in this matter?
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CSB REPORTING
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STERLING (Di)
Staff
A. I am.
O. Do you have any changes or corrections to
either your direct or rebuttal testimony?
A. No.
O. Are you al-so the same person that prepared
Staff Exhibit 101?
A. Yes, I am.
O. Do you have any changes or corrections to the
exhibit?
A. No, I do not.
O. And if I were to ask you the questions set out
in your direct and rebuttal- testimony, would your answers
be the same today?
A. Yes, they wou1d.
MR. HOWELL: With that, Mr. Chairman, I woul-d
move that Mr. Sterlingrs direct and rebutta1 testimony be
spread upon the record as if read and his Exhibit 101 be
marked for identification.
COMMISSIONER KJELLANDER: And without
objectlon, so ordered.
(The following prefiled dlrect and rebuttal
testimony of Mr. Rick Sterling is spread upon the
record. )
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O. Please state your name and business address for
the record.
A. My name is Rick Sterling. My busj-ness address
is 472 West Washington Street, Boj-se, Idaho.
O. By whom are you employed and in what capacity?
A. I am employed by the Idaho Public Utilities
Commission as the Engineerj-ng Supervisor.
O. What is your educational and professional
background?
A. I recej-ved a Bachelor of Science degree in
Civil Engineering from the University of Idaho in 1981
and a Master of Scj-ence degree in Civil Engineering from
the University of ldaho in 1983. I worked for the ldaho
Department of Water Resources Energy Division from 1983
to 1994. In 1988, I became licensed in Idaho as a
registered professional Civil Engineer. I began working
at the Idaho Pub1ic Utilities Commission in 7994. My
duties at the Commission i-nclude analysis of a wide
variety of electric and large water utility appllcations.
I have been the lead staff member on aIl- Public Utility
Regulatory PoIicj-es Act (PURPA) dockets at the Commission
since L994. In addition, I lead the Engineering Section
and supervise a staf f of engj-neers and util- j-ty analysts.
O. What is the purpose of your testimony in this
proceedi-ng?
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A. The purpose of my testimony is to address the
petition of Idaho Power to reduce the maximum contract
length for lRP-based (Integrated Resource PIan) PURPA
contracts from the current 20 years to two years. I wilf
also address similar requests by Avista and PacifiCorp
for reduced contract lengths. In addition, I will make
recommendations for maximum contract length for SAR-based
(Surrogate Avoided Resource) PURPA contracts, including
replacement contracts.
O. What do you believe is the real issue that.
needs to be addressed in this case?
A. I bel-ieve the real- issue is the risk exposure
to ratepayers that can occur due to long-term PURPA
contracts. Long-term contracts, by themselves, would not
necessarily be problematic if the long-term avoided cost
rates contained in those contracts fairly represented
avoided costs over the enti-re duration of the contract.
Unfortunately, however, I do not believe any avoided cost
calcul-ation can prove to remain accurate over a 20-year
period. Absent any mechanism to periodically adjust
avoided cost rates throughout the term of the contract,
shorter contract lengths appear to be one of the only
viabl-e and effective ways to reduce the risk exposure to
ratepayers.
O. Why donf t you believe avoided cost cal-culations
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can prove to remain accurate over a 20-year period?
A. Under the IRP method, avoided cost rates are
computed, in large part, using an hourl-y dispatch model-
that dispatches generation to meet load in each hour at
the lowest possible cost. The dispatch models require
extensive information about each of the generation
plants, typi-ca1J-y throughout the western U.S., as well- as
long-term forecasts of loads and fuel prices. While
forecasts can be prepared and assumptions can be made
easily enough, it is extremel-y unlikely that those
forecasts and assumpti-ons will remain accurate over a
long period of time. Consequently, it is equally
unlikely that the avoided cost rates that emerge from the
dispatch models wil-l- remain accurate. It is possible
that the avoided cost rates will be too high at some
times and too l-ow at other times. It is also possible,
however, that the avoided cost rates wil-I be too high or
too 1ow throughout the entj-re contract length.
Regardless of whether the avoided cost raLes are too high
or too low, 100 percent of the risk of actual prices
deviating from forecasted avoided cost rates is borne by
ratepayers and none of the risk j-s borne by QFs.
0. Has the Commission Staff taken a position
recently on maxj-mum contract length for PURPA contracts?
A. Yes, in Case No. GNR-E-11-03, f recommended
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that the Commission reduce maximum contract length to
five years for contracts containing rates computed under
the IRP methodology. This recommendation supported Idaho
Power's request in that case.
O. Did the Commission accept your reconimendation?
A. No, the Commission did not. The Commission
stated the followi-ng in Order No. 32691 z
We find that a 2O-year contract length, along withother factors, has been beneficial- in encouraging
PURPA development in Idaho. We continue to bel-ievethat 2)-year contracts better coincide with theuseful life of the renewabl-e/cogeneration resources.
While it is not this Commj-ssion' s respons j-bility toensure a contract length that al-l-ows a QF to obtain
financi-ng, we find that reducing maximum contractlength to five years woul-d unduly hinder PURPA
development. That is not the Commission'sobjective. We believe that, by utiliz:-ng othertools to ensure an accurate and up-to-date avoidedcost valuation, we can continue to encourage thetypes of projects that were envisioned by PURPA
whil-e maintainlng the transparency for ratepayers as
PURPA requires. Therefore, w€ find that a maximumcontract length of 20 years is appropriate. Theparties to a power purchase agreement are free tonegotiate a shorter contract if that would be mostsuitable for the project. As in the past, this
Commission wiII consider contracts of more than 20years on a case-by-case basis.
O. The passage from Order No. 32691 you have
quoted above reflects the Commission's position less
than two and a half years ago. Why do you believe
the Commission shoul-d consi-der a dlfferent position
today?
A. In the short two and a hal-f years since the
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Order was issued, Idaho Power has signed agreements for
46L MW of new sofar generationr l and, as stated in its
Petition, has received pricing requests for 885 MW of
additional solar generation. In response to Staff
production requests, Idaho Power states that it has
recej-ved additional requests for solar contracts of
approximately 120 MW since the filing of thls case on
January 30, 20L5. PacifiCorp has received pricing
requests for 275.5 MW of new solar generation according
to its Petition. Contrary to what was contemplated j-n
the Order, it would not appear that PURPA development
needs further encouragement at this time.
Order No. 32697 suggested that other tools
should be used to ensure accurate and up to date avoided
cost rates, but I belj-eve there are now few other tool,s
available. Avolded cost rates can be calculated
accurately at the beginning of a contract term, but no
matter how accurate they may be to start, they are bound
to become inaccurate over a 2)-year period for a long
term contract.
O. Is the sj-gnifj-cant increase in the cumulative
amount of PURPA power a recent phenomenon?
1 The Commi-ssion was recently informed by Idaho Powerthat four solar contracts representing 141 MW have been
terminated for failure to post security.
(Di) s
STAFF
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Yes, as shown in Idaho Power's Exhibit No. 7,
the total- amount of PURPA power began its significant
increase from 276 MW in 2008, to an estimate of 2781 MW
in 2018.2 From 7982 to about 2001, Idaho Power had less
than 200 MW of PURPA generation, primarily hydro. For
approximately the first 25 years, the average size of
PURPA projects was only about 2.5 MW.
O. Has the Commission ever before limited
contracts to five years or l-ess?
A. Yes, it has. The Commission's policy with
regard to contract length has evolved over the years.
From 1980 when PURPA was first implemented in ldaho,
through 7987, utilities were obligated to offer QFs up to
35-year contracts. The reason for the 35-year maximum
contract length was that 35 years was the amortization
period allowed for similar util-ity-owned facil-ities. A
contract length that matched the project's amortization
schedule made financing easier, and in effect, helped
encourage QF development.
fn 7981 (See Case No. U-1500-170, Order No.
2!630) the Commission shortened the standard contract
2 Note that the total- estimate for 2018 includes 885 of
proposed contracts. In addition, it includes 451 MW ofsigned contracts. The Commission was recently notifiedthat 141 MW of signed contracts have defaulted, and thecontracts have been terminated.
A.
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length to 20 years reasoning that risk and uncertalnty
inherent in long-range forecasting increases dramaticalty
with time and that a shorter contract term would reduce
that risk. The Commission rul-ed that contracts longer
than 20 years would be avail-abl-e to QFs only upon a
persuasive showing of need.
Nine years Iater, in 1996, the Commission again
reexamined the issue of contract length. In Order No.
26516 in Case No. IPC-E-95-9, the Commission further
shortened the maximum required contract length from 20
years
'1 00?
length
than 1
No. 21
to five years for projects 1 MW and larger. In
the Commission extended the five-year contract
limitation established for large QFs to smaller
MW QFs as welI. (See Case No. IPC-E-11-9, Order
111 )
In 2002, the Commission increased maximum
contract length from 5 years back to 20 years. The
Commissj-on explained that when it earlier had reduced
maxi-mum contract length to five years, there was an
expectation of widespread deregulation, more competitive
markets, and greater reliance on short-term market
purchases. However, by 2002, the Commission recognJ-zed
that each of Idaho's regulated electric utilities were
constructing or had recently constructed long-term new
generation resources.fn restoring 20 years as the
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maximum contract length, the Commission reasoned that a
longer contract better coincides with the planned
resource life of renewable or cogeneration resources
being offered, better refl-ects the amortization period of
generation projects constructed by the utilities
themselves and will- coincidentally provide a revenue
stream that wilI facil-itate the fj-nancing of QE projects.
(See Order No. 29029)
O. During the approximately five and a half year
period when contract length was limited to five years
(September, 1996 through May, 2002), weren't very few
PURPA contracts signed?
A. Yes, there was only one PURPA contract signed
in Idaho duri-ng this tj-me frame. However, at the ti-me,
the eligibility threshold for published rates was also
l-imited to facilities one megawatt or sma1ler. In
addition, published rates were also quite low at this
time, primarily due to low natural gas prices.
Furthermore, most PURPA hydro and cogeneration projects
had already been developed, whil-e wind, soLar and bj-ogas
technology had yet to fully develop. The combinatj-on of
al-I of these factors, not shortened contract length
alone, caused very few PURPA projects to be developed in
Idaho during this tj-me period.
O. But wonrt a fi-ve-year limit on maximum contract
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Iength, tf approved, limit the ability of projects to
obtain financing, thus making extensive project
development unl-i kely?
A. Yes, I agree that development would Iike1y slow
consj-derably, at least under PURPA. However, facilitles
could still be developed under other mechanisms. Eor
example, if a utility ldentified a need in its IRP and if
certai-n renewables or cogeneration possessed the
characteristics and costs maklng it part of a preferred
portfolio, then the utility cou1d acquire renewables or
cogeneration with long-term contracts in response to
utility requests for proposal. Thls was the mechanism
employed by fdaho Power 1n signing power purchase
agreements (PPAs) with the Neal Hot Springs and Raft
River geothermal projects (35 MW), and the Elkhorn wind
project (101 MW) . Simil-ar1y, Avista secured a PPA for
the Pal-ouse wind project in the same way. Fina11y,
PacifiCorp has either signed multiple PPAs or acquired
ownership of wind projects 1n the same manner.
QFs coul-d al-so seIl their output to other
utilities outside of Idaho, just as some out of state
projects currently sell their output to Idaho utilities.
In addition, projects cou1d be developed in Idaho and
sel-l their output to out of state buyers, not as QEs
under PURPA, but as Exempt Whol-esale Generators. At
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least one large wind project in eastern Idaho sel1s its
output to Southern California Edison in this fashion. In
fact, this is a very common mechanism for project
development throughout other parts of the country.
Al-ternatively, projects could also sign PURPA
contracts and replace them every five years (or whatever
maximum contract length the Commissj-on decides) as long
as PURPA remains in effect.
O. Do you believe that the Commission shoul-d
shoulder some responsibility for ensuring contract
lengths are long enough to enable QFs to obtain
financing?
A. No, not necessarily. Where the Commission
desires to boost development of PURPA projects, long-term
contracts may accomplish that goaI. However, currently,
Idaho utilities, particularly Idaho Power, are being
j-nundated with more projects than they need or can
accommodate. fn Order No. 32697, the Commission stated
that it is not the Commission's responsibility to ensure
contracts are long enough to enabl-e projects to obtain
fJ-nancing. Because the Commission must also regulate the
reasonableness of customer rates and the rel-iability of
power, it is ul-timately a matter of policy-how the
Commission wishes to weigh its various considerations.
O. Is a 20-year maxj-mum contract lengthinconsistent with PURPATs objectives?
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A. Yes, it can be. One of the Commission's
primary duties under PURPA is to set avoided cost rates
that are just and reasonable to customers, j-n the public
interest, and not dlscriminatory to QFs. Such rates must
not exceed incremental costs to the utility. The concern
arises when contracts extend for many years and the
forecast of avoided cost becomes inaccurate. Long-term
contracts based on forecasted rates create greater risks
for customers because the rates in the later years are
not ref l-ective of avoided costs.
O. Are there any specific requirements under PURPA
regarding contract length?
A. No, EERC's regulations implementing PURPA are
silent on contract length. Furthermore, I am not aware
of any FERC case or court decision involving a
requirement for a minj-mum contract length.
However, FERC rul-es do appear to contemplate
less than 20 year contracts. Section 292.302 of the FERC
rules implementing PURPA, requires util-ities to make
availabl-e information from which avoided costs may be
derj-ved. For energy, util-ities are required to estimate
the energy component of avoided costs by year for the
current year and each of the next five years. For
capacity, the utility must make availabl-e its plan for
the addition of capacity by amount and type, for
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purchases of firm energy and capacity, and for capaci-ty
retirements for each year during the succeeding 10 years.
Thus, these component forecasts are much l-ess than the
20-year contract.
In Idaho, utilities do not actually submit such
information to the Commission because FERC rules permit
states to require different lnformation for derj-ving
avoided costs. Nonetheless, I think the mere mention of
five year estimates for energy and 10 years for capacity
suggests 20 year maximum contract lengths are not
necessarily expected.
O. Are there other reasons why you bel-ieve that
maximum contract length should be shortened to five
years?
A. Yes, there are. When the surrogate avoided
resource (SAR) was changed from a coal-fired resource to
a gas-fired resource in 1995, fuel became a much larger
portion of the avoided cost rate. By comparison, fuel- is
a far more substantial portion of costs for a gas-fired
resource than for a coal--fired resource. In fact , for
the gas-fired combined cycle combustion turbine (CCCT)
now used as the SAR, fuel represents approximately two
thirds of the project costs. The fuel- component of costs
must be estj-mated based on 21-year forecasts. As history
has demonstrated, it can be extremel-y difficult to
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accurately forecast gas prices just a few years into the
future, let
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al-one 20 years j-nto the future. Similarly, under the IRP
methodology, much of the cost upon which PURPA rates are
based is driven by fuel prlces. Gas-fired generation is
on the margin much of the hours of the year;
conseguently, electric market prices are frequently
closely tied to natural gas prices. A five year contract
all-ows contract rates to be adjusted regularly to more
accurately reflect current fuel prices.
Moreover, a fixed price contract is more risky
than one in which prices are adjusted frequent.Iy. A
long-term fixed price could possibly be accurate just
once during its term - at the beginning of the contract
when the rates are first established. The shorter the
term of the contract, the more frequently prices can be
adjusted to ensure they accurately represent the true
value of the power. A shorter term contract helps to
minimize risk to ratepayers.
O. Some people have argued over the years that
PURPA projects, because the prices are establ-ished at the
start of the contract term and are fixed for the 20 years
of the contract, present l-ittle or no fuel-price risk
compared to gas-fired generation acquired by utilities.
Do you agree?
A. No, I do not. Although there may be no price
uncertainty associated with long-term PURPA contracts,
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that is not the same as having no price risk. Prices
establj-shed at the start of a long-term contract coul-d
prove to be too high or too Iow compared to other
alternatives or to market prices in effect throughout the
term of the contract. A long-term contract locks in
those prices, regardless of what happens with market
prices. Because 100 percent of PURPA costs are passed on
to customers through PCAs, ratepayers are fuJ-1y exposed
to the risk that PURPA rates prove to be too high.
Fuel costs associated with utility-owned
resources are also passed on to customers, partly through
base rates and partly through PCAs. However, fuel costs
are tracked annually and rates are adjusted accordingly.
Consequently, while customers are exposed to fuel price
risk for both PURPA and utility-owned resources, the
annual adjustment of rates for utility-owned resources
exposes customers to less risk for utility-owned
resources than for PURPA resources.
O. You stated earl-ler that ratepayers bear 100
percent of the risk when prices in PURPA contracts
deviate from actual values of the power over the life of
the contract. Why shouldnrt ratepayers bear 100 percent
of the risk? Donrt they bear 1-00 percent of the risk for
utility-owned resources?
A. Ratepayers do bear nearly aII of the risk of
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utility-owned resources, except for relatively smal-l-
portions that may be borne by the utilities through cost
sharj-ng mechanisms buil-t into PCAs. However, because of
the annual power cost adjustment mechanisms, the risk for
utility-owned resources is less. In other words, the
annual- adjustment allows costs to be bracketed more
accurately.
PURPA resources, on the other hand, receive
revenue at fixed rates over long contract terms. I can
think of few investments made by private j-nvestors in
which the rates are fixed and the entire revenue is
guaranteed for 20 year periods. Private businesses must
almost always make thei-r own assessment of the risks and
rewards for new long term investments. I don't think it
should be much different when private businesses invest
in PURPA projects.
O. Do you agree that a long-term PURPA contract
provides long-term price protection, or a "hedge" against
high prices that can benefit ratepayers?
A. It is certainly possible that this could occur,
but it is also possible that long-term price certainty
coul-d lock in high prices to the detrj-ment of ratepayers.
As I stated, price certainty and price protection are not
necessarily the same thing.
O. Do you support Idaho Power's request to limlt
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contract length under the IRP met.hodology to two years or
PacifiCorp's request to l-imit it to three years?
A. Although I agree with all- three util-ities'
rationale for two or three year maximum contract lengths,
I think it could potentially be so short that QFs who did
sign contracts woul-d nearly be in perpetual- negotiation
to renew conLracts. For some QFs, the negotiation
process can take months or even more than a year. If
many QEs signed short two or three year contracts, it
coul-d be administratively difficult for both the
util-ities and the Commission to review, approve, and
manage these contracts. Therefore, for practical- reasons,
I think a five year maximum contract length woul-d be more
reasonable. Moreover, the risk associated wlth 2O-year
contract is greatly reduced when using a contract of five
years.
O. Do you support Avista's request to limit
contract length under the IRP methodology, similar to
Idaho Power, but all-ow Avista the option to sign
contracts for more than five years in length if a very
favorabl-e opportunity arises? (Reference Kal-ich, Di at
p. 3, l-ines 2-4) .
A. For the same reasons just stated for ldaho
Power and PacifiCorp, I think a maximum contract length
of five years is more reasonable and manageable for all
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three utilities. With regard to Avistars request to be
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sign contracts for a perlod of longer than five years in
certain circumstances, I bel-ieve that option has always
existed. I am not opposed to that option contj-nuing to
be available for al-l- three utilities, provlded that
contracts longer than five years can be justified, will
benefit ratepayers, and are only used in very rare
circumstances.
O. What contract length have QEs historically
chosen, both under the SAR and the IRP methods?
A. The vast malority of QFs in the past have
chosen the maximum contract length available at the tj-me,
whether they were SAR or IRP contracts. Some QFs have
chosen shorter contract Iengths, generally less than five
years, in most cases because they did not want to be
Iocked into certain rates for long periods of time. In
some cases, QFs had some expectation that rates would
i-ncrease in the future, but wanted to be able to be paid
for generation in the meantime until a longer term
contract coul-d be signed at more attractive rates.
O. Do you know what the maximum contract length is
for PURPA contracts in other states?
A. I am not famifiar with all other states in the
U.S. in which there is significant PURPA activity, but I
do know that maximum contract length is currently 20
years j-n Oregon, Utah, and Wyoming. It is 25 years in
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Montana, but only five years in Washington. In areas
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STAFF
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STAFE
utility generators have ready access to wholesale power
markets such as PJM, ISO New England, New York ISO,
California ISO, Southwest Power Pool and ERCOT, there is
no mandatory purchase obligation under PURPA, thus, Do
maximum contract length.
a. Do you believe
besides reducing contract
the problem?
there may be other options
Iengths that could afso address
A. The Commission, in Order No. 32691 suggested
that. it believed other tools, besides shortened contract
lengths, could be utilized to ensure an accurate and up
to date avoided cost valuation. However, the Commission
stopped short of suggesting what those tools shoul-d be.
Trying to determine accurate avoided cost rates from the
beginning of the contract is, obviously, a first step.
Although I bel-ieve avoided costs are reasonably being
computed today under the IRP method, I also bel-ieve that
there may be additional- factors that are currentl-y not
being considered. For example, sofar projects are
currentl-y eligible for tax credits val-ued at up to 30
percent of the prolect cost. PresumabJ-y, the value of
these credits is being real-ized by the owners or
financiers of the projects, but is not being passed on to
the utility or its ratepayers. If a utllity acquired a
comparable solar project or its output through a
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competitive solicitation, I woul-d assume the value of any
tax incentives would be reflected in the purchase price
and therefore passed on indirectly to ratepayers.
Currently, tax incentives are not accounted for in the
IRP methodology, yet they provide tremendous benefit to
QFs.
There could be other potential changes to the way in
which avoided cost rates are calculated, but none would
adequately address the real problem-rates becoming
inaccurate over long contract lengths.
O. Do you believe a periodic rate adjustment
mechanism coul-d work, while maintaining QFs' option to
choose 2l-year contracts?
A. In theory, periodically adjusting rates
throughout the term of the contract, say at two to five
year intervals, could help to ensure that avoided cost
rates in the contract remain accurate and reflect the
proper value compared to the market or other
alternatives. Similarly, indexing prices 1n the contract
based on electric market indexes or fuel prices could
accomplish the same thing.
O. Do you believe QFs would find periodic rate
adjustments acceptable?
A. No, f do not. I expect QFs would view
adjustable rates, either through reopeners or indexing,to be nearly comparable to short term contracts. Because
rPC-E-15-01
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STAFE
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STAFF
prices are the slngle most important element in a
contract, periodic adjustment of those prices cou1d be
functionally equivalent to signing a new contract to QF
owners and financiers.
A. Do PURPA or FERC rules all-ow periodic rate
adj ustments ?
A. FERC and various courts have made clear that
avoided cost rates contained in a PURPA contract cannot
be modified after the contract has been signed, although
neither the Idaho nor the U.S. Supreme Courts have hel-d
as much. However, FERC rules do not specifical-ly address
whether adjustable rate contracts are acceptable in
instances in which the contracting parties agree in
advance to an adjustment method and frequency.
Consequently, I am uncertain as to whether FERC would
find adjustment mechanisms acceptable. Because of this
uncertainty, and because I believe QEs would view
periodic rate adjustments as functionally equivalent to
new contracts, I think shorter contracts are the best
approach to reduce the financial or price risk of
long-term contracts.
O. Do you agree that PURPA projects will always be
paid too much under 2O-year contracts?
A. No, not necessarily. While it is true that
avoided cost rates have exceeded comparabl-e market prices
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STAFE
throughout most of the history of PURPA in Idaho, there
have been times when this was not true. For example,
during the extreme electrj-city price spikes in l-ate
2001-2002, market price far exceeded avoided cost rates
for extended periods of time.
Price compari-sons at any single snapshot in
time are generally not valid projections over a long
period of time. Contractual- avoided cost rates will
nearly always be higher or l-ower than comparable market
prices over the long-term such as 20 years. What is
important is that the prices are close over the entire
course of the contract term.
Now that a few contracts have reached or are
nearing their 20 or 35-year expiration, a comparison can
perhaps be made. However, in my opinion, if avoided cost
rates in any contracts have proven to be accurate over
time, it has been just by chance, not by design.
A. Do you think it is fair for utilities to be
permitted to develop or acquire long-term generation
assets, but to only be obligated j-n the case of PURPA
resources to two, three, or five year contracts?
A. Whenever a utility acquj-res a resource or slgns
a long-term PPA for new generatJ-on, it must identify the
need in its IRP, evaluate a range of alternatives, and
procure the resource or contract through a competitive
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STAFE
process. Throughout the entire process, the utilityrs
decisions are subject to j-ntense scrutiny by the
Commission, intervenors, and other interested parties,
including customers. If the utility cannot first
demonstrate a need and second justify the cost-effective
resource, it does not receive Commission approval to
pursue the project.
As examples of utility acquisit.ions of
non-PURPA renewable projects, Idaho Power's Neal Hot
Springs and Raft River geothermal PPAs and its Elkhorn
Wind PPA were signed as a resul-t of geothermal and wind
resources being identi-fied as preferred resources in the
utility's IRP. Similarly, Avistars Pal-ouse Wind Project
PPA and several PacifiCorp wind projects and PPAs were
identified through the IRP process and acquired through
subsequent competitive procurement processes.
O. Was the procurement of thermal projects by
utilities, such as Idaho Power's Langley Gul-ch project,
PacifiCorp's Lakeside II, or Avistars Lancaster PPA any
dj-fferent than the acquisitj-on process employed for
renewables? Aren't those examples of long-term
commitments that bind ratepayers for very long periods of
time?
A. Just like the renewabl-e projects previously
discussed, the utllities' thermal facil-ities mentioned
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STAFF
above also had to pass intense scrutiny before the
utilities were permitted to procure them. While it is
true that util-itles are permitted to sign long-term
contracts and secure long-term financing, for most
projects there is no guaranteed complete cost recovery at
fixed rates. For example, in the case of Idaho Power's
Langley Gulch project, various costs of the facility are
included in base rates for recovery over the life of the
plant. However, fuel- costs, which can represent as much
as two thirds of the total- cost over the facility's
l-ifetime, are subject to annual- adjustment to the extent
actual costs vary from what is included in base rates.
Moreover, most of these thermal generating facilities
provide other benefits such as dispatchability, varj-abl-e
ramp rates, reserves and other ancillary servj-ces.
PURPA projects, on the other hand, are treated
differentty. They are currently entitled to long-term
contracts at fixed rates. The utility is obligated to
sign contracts at Commission-approved rates, with no
consideration of need, with no competitive procurement
process, and without regard to cost-based pricing.
Recovery of PURPA contract payments by the utility is
through a combj-nation of base rates and PCAs, but always
at 100 percent. There 1s no adjustment to the avoided
cost rates or to the amount authorized for recovery from
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STAFE
ratepayers throughout the entire term of the contract.
O. Can PURPA cogeneration projects l-ike Simplot or
Clearwater present additional- rj-sks over non-cogeneration
PURPA projects?
A. Perhaps. Cogeneration projects are always
associated with some other industrial process besides
generating electricity. Consequently, they face business
risks independent of their el-ectric production. If the
thermal- host for a cogeneration facility goes out of
business, then the el-ectric productlon cannot continue.
Some examples of this have been the Magic West facility
in Glenns Eerry and the Yellowstone Power project at
Emmett.
O. Do you believe PURPA is an effective mechanlsm
for utilities to acquire new generation?
A. No, I do not. I believe PURPA was intended to
permi-t relatively smal-l, non-utility-owned projects to be
developed and to compete on an equal footing with
utility-owned facilities. I do not believe PURPA was
ever intended to serve as the primary, or even a major,
mechanism for utility acquisition of new resources.
Instead, at l-east for ldaho Power and perhaps PacifiCorp,
PURPA resources have become major resources, forced upon
them with no planning whatsoever. PURPA projects
entirely circumvent the planning process and sometimes
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cause the utility to plan around them rather than
planni-ng for them.
r PC-E-1 5-0 1
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(Di) 24a
STAFF
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(Di) 2s
STAFF
This creates a very awkward and inefficj-ent planning
process and can lead to a poorly conceived generation
fleet that is not in the best interests of ratepayers.
Therefore, I do not support long-term contracts to
encourage PURPA at a time when util-ities would not
otherwise be making long-term commitments for non-PURPA
generatlon resources.
0. Each of the utilities' petitions in this case
have asked to reduce the maximum length of only IRP-based
contracts; however, SAR-based contracts contj-nue to be
eligible for 20-year contracts. Do you believe 20-year
maximum contract lengths should contj-nue to be availabl-e
to SAR-based contracts?
A. Yes, I do. Twenty year contracts should
continue to be avaj-lable for wind and solar projects
smal-Ier than 100 kW, and for all- other project types
smaller than 10 aMW.
a. If maximum contract lengths are reduced to l-ess
than 20 years in this case for IRP-based contracts, are
you concerned about the difference in contract length
between SAR-based and lRP-based contracts?
A. No, f am not. Although there woul-d be a
difference between maximum contract length for IRP and
SAR-based contracts, I belj-eve such a difference is
reasonabl-e. In the past, there have been instances in
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STAFF
which contract rates and/or terms were much more
favorable for SAR-based than for IRP-based contracts, and
it has 1ed to QE devel-opers strongly preferring one
contract type over the other. One recent example was the
disparity in rates (either real- or perceived) between IRP
and SAR rates, which led to disaggregation of large wind
farms into smal-l-er 10 MW projects.
In this case, most new PURPA projects are
Iike1y to be solar, and the size l-imit or eligibility cap
for SAR-based solar contracts is 100 kW. Because this
cap is 100 kW, I be1ieve it is unl-i-keJ-y a QF would be
disaggregated into such small pieces in order to qualify
for SAR-based rates, ot more importantly, for 20-year
contracts. The same would 11ke1y be true for wind
proj ects .
In addition, SAR-based projects do not
represent a significant portion of the cumul-ative amount
of PURPA generation. For example, wind and sol-ar
projects (both under contract and proposed) account for
more than 7973 MW of Idaho Power's PURPA projects
according to Idaho Power Exhibit No. 1. Thus, the impact
of SAR-based projects is very smal-l- in comparison to the
magnitude of fRP-based projects.
O. Does your proposal to maintain 2)-year
contracts for new SAR-based projects also apply to
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STAEF
SAR-based contracts that will- be expiring and that desire
new contracts?
A. Yes, it does.
O. Please discuss the number and timing of
expiring SAR-based contracts.
A. In the coming years, many existing PURPA
contracts wil-l- expj-re and will- be seeking replacement
contracts. Exhibit No. 101 depicts graphically the
timing and number (but not the amount of generation) of
QF contracts that will be explring. Each line on the
graph represents a different contract. In the coming 10
years, 94 contracts will expire and could choose to be
renewed.
O. Why should SAR-based contracts be permitted
longer contracts than IRP-based contracts?
A. Nei-ther SAR-based nor lRP-based rates are
Iikely to remain accurate over a 2)-year period. On a
per kW basis, the risk for SAR-based contracts is exactly
the same as for IRP based contracts. However, SAR-based
contracts, because the project sizes are individually and
col-Iectively small-, present much l-ess risk if contract
rates prove to be too high or too l-ow compared to the
actual value of the power.
O. Should SAR-based replacement contracts be
permi-tted 2O-year terms?A. Yes, I recommend that all SAR-based contracts
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STAFF
be eligible for 20-year contracts, regardless of whether
they are for new projects or for replacement contracts.
SAR-based projects that are renewi-ng contracts wil-l
receive the then current energy rates and capacity rates.
Even though projects seeking replacement contracts
presumably have already been financed and retired their
debt, for consistency sake I think 1t is reasonable that
all SAR-based contracts follow the same rules.
Contracts that were initial-ly SAR-based, but at
the time of contract replacement exceed the size
threshold for SAR-based rates, should be treated as new
IRP-based contracts but eligible for capacity payments
throughout the entire contract term.
O. Please summarize your recommendations.
A. I recommend that the maximum contract length
for standard IRP-based contracts be five years for Idaho
Power, Paci-fiCorp, and Avista. I also reconrmend that the
maximum contract length for SAR-based contracts remain at
20 years, both for new and for replacement contracts.
O. Does this conclude your direct testimony in
this proceeding?
A. Yes, it does.
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(Reb) 1
STAFF
O. Please state your name and business address for
the record.
A. My name is Rick Sterling. My business address
is 472 West Washington Street, Boise, Idaho.
O. By whom are you employed and in what capacity?
A. I am employed by the Idaho Public Utilities
Commission as the Engineering Supervisor.
O. Are you the same Rick SterJ-ing that previously
submitted testj-mony in this proceeding?
A. Yes, I am.
O. What is the purpose of your rebuttal- testimony?
A. The purpose of my rebuttal- testimony is to
address several issues raised by Clearwater/Simplot
witness Dr. Reading and ICL/Sierra Club witness Beach.
O. Various witnesses have suggested that there is
unequal treatment between QFs and utility-owned
resources. Do you agree?
A. I wou1d agree that QFs and util-lty-owned
resources are not treated the same. However, much of the
different treatment is because PURPA requires it. A
significant difference is the pricing of QF generatj-on.
PURPA dictates that the price or rate a utility pays for
the purchase of QF power be based on the avoided cost of
the utility-not the QEs cost of producing the power. In
particular, a QE that places its facility lnto service
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(Reb) 2
STAFF
bef ore January t, 20L7 wil-l- receive a 30 percent tax
credit. This substantial tax credit is not reflected in
the avoi-ded cost rate.
Furthermore, most of the different treatment is
to the benefit rather than the detriment of QFs. For
example, the utility has a "must purchase" obligatj-on
under PURPA whereas utilities may engage 1n arms-length
bargaining when acquiring resources. In addition, QFS
are entitled to contracts regardl-ess of a utilityrs need,
whereas utility-owned resources must obtain a Certificate
of Publ-ic Convenience and Necessj-ty, which requires a
showing of present or future need and competitj-ve cost
compared to other al-ternatives. Utility-owned resources
must be competitively procured and are subject to
cost-based pricing, whereas QF contracts are not subject
to competition and non-negotiated pricing. Utility-owned
resources are dispatched based on market prlces or the
cost of al-ternate resources, but QF power must be
accepted by the utllity whenever offered. Final1y, the
fuel- and variabl-e costs of util-ity-owned resources are
subject to annual adjustment through PCAs, but PURPA
prices are fixed for the entj-re duration of the contract.
O. Various witnesses (Reading pp. 25-26; Beach pp.
2L-25) have also suggested that PURPA projects, because
of their fixed pricing, provide a val-uable risk hedge and
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STAFF
a benefit to ratepayers Do you agree?
A. No, not entirely. QE pricing, because it is
locked in for 20 years, mdy el-iminate price volatility,
but it does not completely eliminate risk. QF prices
that prove to be too high can be locked in to the
detriment of ratepayers. Conversely, QF prices that
prove to be too l-ow can be locked in to the benefit of
ratepayers. In either case, ratepayers are stil-l- exposed
to the same risk. PURPA projects can help to limit risk
when market prices rlse to extreme l-eve1s, but they can
also limit opportunities to take advantage of very low or
declining prices for the benefit of ratepayers. Like all
hedges, the critical- question is how much protection do
you need and how much should you be willing to pay for
it. Utillty-owned resources, on the other hand, are
economically dispatched. In other words, they are only
run when they are l-ess costly than other al-ternatives or
when their output can be sold at a profit.
O. On pages 10 and 11 of Dr. Reading's direct
testimony, he quotes a passage from Commission final
Order No. 32691 in the GNR-E-11-03. In that Order, the
Commission declined to adopt a contract length l-ess than
20 years. Are the circumstances of the 207I case the
same as in this case?
A. No, they are not. fn the GNR-E-11-03 case,
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Idaho Power proposed that the maximum contract length for
all PURPA contracts be reduced from 20 years to 5 years.
Tr. at 487, 489, 524 ("Idaho Power recommends that the
fi-ve-year contract term apply to al-l- PURPA QF power sale
contracts. " ) . In the GNR-E-11-03 case, Staff's position
was that PURPA contracts be limited to five years for
only those contracts util-izing the IRP methodology (i.e.,
above the SAR-based eligibility cap) . I testified that:
"Twenty-year contracts shoul-d continue to be available to
QFs under the SAR methodology." Tr. at 1107-08.
So the Commission's statement quoted by Dr. Reading
was also responding to Idaho Power's position that all
PURPA contracts should be reduced to five years,
regardless whether they used the SAR-based methodology or
IRP-based methodology. In the present case, all the
parties have agreed to continue 2)-year contracts for
SAR-based contracts. In other words, the parties have
agreed that SAR-based PURPA contracts will be unaffected
by the reduction in contract length recommended for
IRP-based contracts.
O. Are there other reasons for the Commission to
re-examine the length of IRP-based PURPA contracts?
A. Yes, there are. Eirst, the Commission is a
regulatory agency that performs legislative functions and
re-examines regulatory policies from time-to-time. The
(Reb) 4
STAEF
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STAFF
Commission is not bound to deci-de future cases in the
same way as in past cases. As I recounted in my direct
testimony, since PURPA was first implemented j-n Idaho,
maximum contract length has gone from 35 years, to 20
years, to five years, and back to 20 years. The
Commisslon can and should change policy as circumstances
change.
Second, at the time the Commission j-ssued its
Order No. 32691 in the GNR case in December 2012, Idaho
Power had less that 800 MW of nameplate PURPA power.
Since the GNR case, Idaho Power reported that it had 467
MW under contract from sol-ar developers (including the
1-41, MW of recently terminated contracts in the Clark
Solar I -4 projects) and an additional 885 MW of proposed
solar development. See Idaho Power Ex. 1. Simply put,
Idaho Power claims that it has more than !200 MW of
contracted and proposed sol-ar projects in this case.
This compares with the Company's peak l-oad of 3,400 MW,
its minimum system load of L,073 MW, and its average
system load of 1,800 MW. (Grow, Dir at 3; 20L3 IRP
Appendix A).
O. On pages 14 and 15 of Dr. Reading's direct
testimony, he created a chart and purportedly compares
the costs of Idaho Power's generating resources to the
costs of PURPA projects. Do you agree with therepresentations made in his Chart No. 1 on page 15?
928 STERLING, R
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(Reb) 6
STAFE
A. No, I do not. In Chart 1 on page 15 of Dr.
Reading's direct testimony, he compares the PURPA costs
to the estimated capital and running costs of various
Idaho Power-owned thermal- generation resources. While
the comparison may be numerically accurate, it is
extremely misleading because the resources being compared
are very different types of resources. More
specifically, when resource costs are compared on a cost
per MWh basj-s, and certain resources generate
substantially different amounts of MWhs, peaking
resources, such as Bennett Mountain and Danskin, wj-11
appear far more costly than baseload resources such as
Jim Bridger. Peaking resources, because they are used
infrequently and generate few MWhs, will always appear
far more "costly" than baseload resources when measured
on a cost per MWh basis. Conversely,
basis, peaking resources will always
than baseload resources.
on a cost per MW
be less expensive
In addition, Dr. Reading acknowledges that he
omitted Idaho Power's l-owest cost resources-its hydro
resources-from his cost comparison. He cou1d have
incl-uded the hydro data by using an average over several
years or normalized data. He also omitted hydro cost due
to , in his words, "massive envj-ronmental remediat.ion."
(Dir at 16). The failure to include hydro costssignificantly misstates the Company's power costs,
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especially where L,709 MW of hydro is inc1uded in 3,500
MW of nameplate capacity (Grow, Dir at 5).
Fair and reasonable di-rect comparj-sons between
the costs of different resources can only be made for
resources with comparable capacity factors, and when the
comparisons are made over the same periods of time.
Comparisons either on a cost per MW or a cost per MWh
alone basis (capacity or energy) should never be used to
judge the cost effectiveness of particular resources.
Similarly, cost comparisons in which only a portion of
the duration of a contract are consi-dered are also
usually inappropriate. Differences between PURPA
contract rates and market prices may exist in specific
years, but there is no certainty that those differences
witl persist for the duration or remainder of a contract.
O. On page 4, Dr. Reading has asked whether there
are other viable opportunities for projects l-ike
Simplot's and Cl-earwater's to sell their output to other
buyers in the regj-on. Do you agree with his statement on
page 5 that "aside from PURPA sal-es to utilities, neither
Clearwater nor Simplot have a IegaI or economically
viable market, retail or wholesale, to sel-I el-ectrlcity"?
A. No, I do not. Conspi-cuously absent in his
answer and anal-ysis is the possibility of either of these
two entities selling their output to other util-ities in
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the region. Cl-earwater and Simplot may be abl-e to
operate in a similar fashion to exempt wholesal-e
generators (EWGs) and sell- their output to other
util-ities. For exampfe, Clearwater currently se1ls its
output to Avista using a non-PURA contract.l Other
renewable projects have sold their non-PURPA output to
other utilities such as the wind farm in eastern Idaho
(Goshen North Wind Farm) selling to a Cal-ifornia utility;
Lucky Peak selling its hydro output to Seattle City Light
or Palouse Wind selling its wind generation to Avista.
Other renewabl-e generators have been successful in
selling their output to utilitj-es without resorting to
PURPA contracts including the Neal and Raft Rj-ver
geothermal projects to Idaho Power and the Elkhorn wind
project to Idaho Power in Oregon.
O. CouLd Clearwater sell- 1ts output to another
utility other than Avista under either a PURPA or
non-PURPA agreement?
A. Yes. As Dr. Reading notes on page 3 of his
direct testimony, Cl-earwater's current 2013 agreement
"provides Clearwater wi-th a l-imited right to terminate
its
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1 on May 13, 2075, Avista filed an Applicati-on seeking
Commission approval of an amendment to Avista's contractwith Clearwater. The amendment proposed to extend thecurrent agreement by three additional years, in additionto permitting Avista to purchase incremental energy from
Cl-earwater at negotiated prices when j-t j-s beneficial toboth partJ-es.
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energy sales to Avista with 90 days' notice." (Reading,
Dir at 3). Under the terms of its current power purchase
agreement wlth Avista, Section 1 on page 2 of the
agreement provides that:
lf, during the Term of this Agreement, IClearwater]desj-res to sell- the output of the Generation to anythird party, IC]-earwaterl shal-l- terminate this
Agreement by providing Avista wrj-tt.en noti-ce oftermination at l-east 90 days prior to suchtermination. The sale to the third party shal1 not
coflrmence until- the date on which this Agreement is
terminated. In the event that [Clearwater] desj-resto sell the output of the Generation to any thirdparty(ies), IClearwater] sha1l be responsibl-e for
making all necessary arrangements to facilitate thesale of the output of the Generation to such third
party (ies) .
The Commission approved this contract in Order
No. 32841 issued June 28, 2073 By the terms of this
agreement, Cl-earwater clearly preserved the opportunity
to seII j-ts output to a party other than Avista.
o.
fl-aw in
unable
Dr. Reading on p. 36 suggests that there is a
the IRP computation methodology because it 1s
to account for hours when market prices are
negative and that the model instead assigns a price of
zero when the actual avoided cost j-s negative. Do you
agree that the model is flawed?
A. I wou1d agree that the model should not be
assigning a price of zero when prices are negative
However, I would also point out that, despite
possible
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misconceptions, that the AURORAxmp model used to generate
energy prices can, in fact, generate negative prices
under certain circumstances. The Idaho Power spreadsheet
that uses AURORAxmp prices as input shou1d then, in turn,
be able to capture the effect of negative prl-ces.
Nonethel-ess, while the capability to account
for negative pricing existsr no negatively priced hours
appeared in the AURORAxmp output used for pricing the 13
recent Idaho Power solar contracts, primarily because
negative pricing is currentl-y not Iikely under average
conditions used for PURPA pricing.
O. Does this conclude your rebuttal- testimony in
this proceeding?
A. Yes, it does.
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CSB REPORTING(208) 890-s198
STERLING (X)
Staff
(The followj-ng proceedings were had in
open hearing. )
MR. HOWELL: And Mr. Sterling is available for
cross-examination.
COMMISSIONER KJELLANDER: Let's begin with
Mr. Richardson.
MR. RICHARDSON: Thank you, Mr. Chairman.
CROSS_EXAMINATION
BY MR. RICHARDSON:
O. Good morning, Mr. Sterling.
A. Good morning.
O. At page 1 and line 18 of your prefiled direct
testimony, you describe your duties at the Commission as
belng "the lead Staff member on al-l PURPA dockets at the
Commission since 1,994." Do you see that?
A. Yes, I do.
a. So you're the guy who j-s responsible to shape
Staff's positions on PURPA cases?
A. f don't do it by myself, but f rm the lead
person, I have been.
O. So you're in charge of deciding what the
Staf f 's position will- be?
A. No, T wouldn't quite put it that way. We
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CSB REPORTING
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Staff
collectively as a Staff discuss issues and discuss
positions and come to agreement.
0. But what does it mean to be the lead Staff
person?
A. Itrs one of my primary responsibilities. I
have been a witness in nearly every PURPA case where
Staff has participated in a hearing.
O. And you're the Staff's policy witness?
A. I'm the Staff witness and I can speak to some
policy questions, yes.
O. So reading your testimony, your direct and
rebuttal Lestimony, sort of at the 35,00O-foot 1eve1,
would it be fair to conclude that you would prefer to see
the must-buy provisions of PURPA repealed?
A. No, I haven't taken a position on that in my
testimony.
O. Well, dt page 24, l-ine L3, you were asked, "Do
you believe PURPA is an effectj-ve mechanism for utilities
to acquire new generation?rr Do you see that?
A. Yes, I do.
O. And what was your response to that question?
A. No, I do not.
O. So if you don't believe PURPA is an effective
mechanism for utilities to acquire new generation, what
is your position on the must-buy provision of PURPA
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CSB REPORTING
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forcing utilities to buy QF power in light of the fact
that you don't think it's an effective mechanism to
acquire new generatlon?
A. WeII, PURPA is a federal law that we must
comply with. We don't create the federal law, 'rwe'r the
Idaho Public Utilities Commlssj-on. We simply implement
ir.
A. Right, and I was asking you what your opinion
1s on the must-buy provj-sion of PURPA. Is it a good Iaw
or is it a bad l-aw in your opi-nion?
A. If structured and implemented properly, I think
it can be a good 1aw.
O. So you're aware, are you not, that federal law
requires state commissions to encourage the development
of QE projects?
A. Yes, I am aware of that.
O. So isn't that a bit awkward for you given your
position that PURPA is a not an effective mechanism for
utilities to acquire generation and you're the lead
policy person on the PUC Staff implementing PURPA?
A. No, I don't see the a conflict there.
O. AII right; so on page 4 of your direct
testimony, you quote from the Commission's Order in the
generj-c avoided cost docket 1n which the Commission
rejected your proposal to go to a five-year contract for
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PURPA projects, and then you are asked basically what has
changed in the two-and-a-hal-f years since that Order was
issued such that the Commission should now adopt the same
five-year contract limit that it rejected just a short
time dgo, and your answer over on page 5 is that the
recently rejected five-year contract term should now be
adopted because Idaho Power has signed up 461 megawatts
of new solar and has 885 new megawatts of pricing
requests, and then you poi-nt out that PacifiCorp has
recei-ved requests for 120 megawatts of new solar and has
pricing requests for 275.5 megawatts. Do you see that?
A. Yes.
O. It'lou1d you agree with me that one thing that
hasn't changed since the last avoided cost case where
your recommendation for a five-year contract limitatj-on
was rejected is your belief that the five-year contract
term should be adopted?
A. No, that hasn't changed. I took a position
of five years should be the maximum contract length in
the
O. And that's stil-I your posi-tion today;
correct?
A. Yes, it is.
O. So looking back at your answer on page 5, again
to the question of what has changed, does it strj-ke you
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CSB REPORTING(208) 890-s198
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as significant that there is no mention of Avista
Corporation in your answer?
A. No.
O. What are the equj-valent numbers for Avista on
new solar and pricing requests?
A. To my knowledge, Avista has no proposed QFs,
sol-ar QEs, that are pending or proposed.
O. So on the bottom of page 8 to the top of page 9
of your direct testimony, you were asked whether a
five-year contract term would limit QEs' ability to
obtain financing and thus make extensive project
development unlikely, and you respond in part by noting
that facilities could still be developed by other
mechanisms; correct?
A. Yes.
O. Well, you would agree wj-th me, wouldn't you,
that it's still- illegal in Idaho for me to generate and
seIl el-ectricity to my neighbor?
A. You're not allowed to sel-l retail without being
regulated as a utj-1ity.
O. On page J.t, beginning on line !1, you state
that EERC rul-es do appear to contemplate less than
2O-year contracts. Do you see that section?
A. Yes, I do.
O. In fact, if you go to l-ine 19 on page 11 and
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put a quote mark in front of the word 'rtorr and then go
down to line 20 and change the word "information" to
"data" and then go down to line 27 and put a quote mark
after the word "derive, " you would have a verbatim
word-for-word quote from 18 CFR 292.302(b); correct?
A. I donrt have the FERC regulations in front of
me.
O. WeIl, you quoted the FERC regulatj-ons in your
testimony, did you not?
A. I donrt know if the wordsmithing that you
suggest would exactly match without seeing them side by
side.
O. I didn't bring the CFRs with me, but woul-d you
accept, subject to check, that that's a verbatim
word-for-word quote from CER -- 18 CFR 292.302(b)?
A. Subject to check, yes.
a. And on line 24, if you put quotes in front of
the word "pIan" and over on to page 72, l-ine 2, if you
put quote marks after the word "yearsr" that's a verbatim
word-for-word quotation from 18 CFR 292.302(b) (2) .
Didn't you quote the EERC regulations in your
testimony?
A. I may have come very close to that. I
didn't put quotation marks around --
O. Wel-l-, subject to check, if you put quotes
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CSB REPORTING
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STERL]NG (X)
Staff
around the words f just said, it's a verbatim
word-for-word quotation. Is that a coincidence or did
you just quote the FERC regulations without citating
them?
A. It ' s j ust a co j-ncidence, I suppose .
O. It's just a coincidence, okay; so are you
saying that because EERC requires five years of energy
data to be made available that it is contemplating a
five-year PURPA contract term?
A. No, that's mischaracteriztng my testimony.
O. WelI, what is your testimony saying about
contract terms and the FERC regulations that you
coincidentally quoted?
A. I think it's very clearly l-aid out in my
testimony, if you'd like to refer me to a specific line.
O. I'm talking about page 7L, l-ine Ll , through
page L2, line 2. "EERC rules do appear to contemplate
Iess than 2)-year contracts, " so what term do FERC rules
contemplate? Something l-ess than 20, perhaps five?
A. Less than 20 is what I state in my testimony.
O. Eor energy I'm quoting you at page LL, l-ine
21, "For energy, util-ities are required to estimate the
energy component of avoided costs by year for the current
year and each of the next five years. " What's the
relevance of that statement in terms of contract
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CSB REPORTING
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STERLTNG (X)
Staff
length?
A. I think it's a suggestion that FERC was
contemplating terms that are less than 20 years.
O. Perhaps five?
A. Perhaps.
O. Okay, thank you. Then it is also true that in
Section 18 CFR 292.302 (b) (2) that you quote
coincldentally that because 10 years of energy and
capacity data has to be made available that FERC is also
contemplating a 1O-year contract term; correct?
A. Yes.
O. So over on page L2 at l-ine 72, you were asked
if there are other reasons why you believe that the
maximum contract should be shortened to five years. Do
you see that?
A. Yes, I do.
O. And you respond with a discussion of the larger
fuel risk associated with a gas-fired SAR as opposed to
the prior coal-fired SAR; correct?
A. Thatrs correct.
O. But this is not a new argument, is it? In
fact, you just cut and pasted your fuel risk argument
from your generic avoided cost testimony two years agoi
correct?
A. I don't recaII.
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CSB REPORTING(208) 890-s198
STERLING (X)
Staff
O. So I have a copy of your testimony in the
generic avoided cost case from two years ago and I coul-d
read that into the record and would you accept, subject
to check, that it's essentially identical?
A. Subject to check, yes, I would.
O. Okay; so nothing has changed, has it, in your
reasoning about the fuel risk argument since this
Commission rejected that argument just two years ago?
A. For the fuel risk argumentr Do, nothing has
changed.
O. Okay, then on the bottom of page 13, you were
asked about the price risk associated with a long-term
contract as yet another reason to adopt your recommended
five-year contract term, but, agaj-n, you made the same
argument two years ago and it was rejected by this
Commission, and in fact, this section of your testimony
is largely just cut and pasted from your testimony two
years o9o, so my questi-on to you is but nothing has
changed in your price risk argument between now and when
it was rejected two years d9o, has it?
A.
o.
A.
No, f wouldn't agree.
What has changed?
We have hundreds or thousands of megawatts
collectively amongst the three utilities that are
proposing sol-ar contracts. The price risk associated
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CSB REPORTING
[phone]
STERLING (X)
Staff
with those contracts is much greater now than it ever has
been, and I've explained that in my testimony.
O. So going over to page 18 at line 6, you're
asked, "Do you believe there may be other options besides
reducing contract lengths that could al-so address the
problem"; so when you refer to "the problem, " is it fair
to return to page 2 of your testimony at line 72 where
you state, "I believe the real- issue is the risk exposure
to ratepayers that can occur due to long-term PURPA
contracts"; is that what the "problem" is?
A. In my opinion, y€s.
O. But in your answer to that question on page 18,
Iine 6, you spend most of your answer talking about ways
util-ities could possibly capture solar tax credits from
developers. Can you explain what the relati-onship is
between tax credits and contract length?
A. There have been suggestions in the case that we
should address cost j-ssues, avoided cost pricj-ng j-ssues,
rather than contract length and I'm responding to that
suggestion that has been made by various witnesses that
pricing is the real issue here, not contract length, and
that's the contexL in which this portion of my testimony
was offered.
O. So pricing j-s the real issue, not contract
Iength?
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CSB REPORTING(208) 890-s198
STERLING (X)
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A. It's a combination of the two, but prici-ng is
an issue that other witnesses have brought up, and so Ifm
simply speaking to that.
O. Did I mishear you say that pricing is the real
issue, not contract length?
A. It's a combination of the two.
O. If you solve the pricing j-ssue, does the
contract length issue go away?
A. They're both issues, because as I state in my
testimony, I don't think for a 2)-year contract that you
can maintain accurate pricing.
O. Right, but
A. If you could possibly maintain accurate pricing
for 20 years, then contract length may not be an issue,
but I don't believe that you can do that; therefore, I
think pricing and contract length both together are
issues.
O. So if you have a pricing mechanism that you can
true-up on a periodic basis, does that sol-ve the contract
length j-ssue?
A. It could.
O. And Dr. Reading proposed a contract pricing
readjustment mechanism, did he not?
A. I believe he did in his rebuttal testimony.
O. Towards the bottom of page 3, line L9, I think
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CSB REPORT]NG(208) 890-5198
STERL]NG (X)
Staff
that's your rebuttal, right, it's your rebuttal-
testimony, page 3, l-ine 19, you were asked whether the
circumstances of the recently concluded generic avoided
cost docket where the Commission rejected your five-year
contract argument are the same as in this case, and over
the next two pages you respond. You first point out that
in the generic docket, there was a dispute over whether
the contract }imitation shoul-d apply to al-l- or only
IRP-based PURPA contracts, and you note that in this case
itrs different because we have agreed that we're only
discussing IRP-based contracts.
Then you point out that the Commission can and
does change its mind from time to time, and thatrs on
page 4, line 23. Finally, over on page 5, beginning on
Iine 15, you state "Simply put, Idaho Power cl-aims that
it has more than L,200 megawatts of contracted and
proposed sol-ar projects j-n this case"; so in your
opinion, L,200 megawatts of proposed and solar
proposed and contracted solar capacity j-s enough to
trigger a reduction in contract length to five years?
Did you conduct an analysis as to where the line should
be drawn as to how much is enough to trigger a contract
length reduction?
A. No.
O. So you don't know if Idaho Power had 600
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CSB REPORTING(208) 890-s198
STERLING (X)
Staff
megawatts of proposed and contracted solar that that
would be sufficient to trigger a contract length
reduction?
A. I haven't specified a certain level- of
megawatts.
O. But is that because you haven't changed your
position from two-and-a-ha1f years ago that the contract
length should be five years and not 20?
A. I wouldn't say i-t's because of that.
O. But nothing has changed in your opinion, has
ir?
A. As f explained previ-ously, we have hundreds or
thousands more megawatts proposed than we had two years
ago. That's what's changed.
O. So your position on contract length hasn't
changed?
A. No, it hasn't.
O. And that position was rejected by this
Commission just two-and-a-hal-f years ago; correct?
A. Yes, it was.
O. And you're highly crj-tical of Dr. Reading in
his presentatj-on of his chart on page 15 of his
testimony, and that's at page 5, l-ine 25 of your
testimony. Irve got to get that reference correct. You
are critical of Dr. Reading's chart on page 15 of his
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testimony; correct?
A. Yes.
O. And one of the primary objections you have is
that Dr. Reading incl-uded peaking resources on his chart
that shows that PURPA projects are cheaper, less
expensive, than some of Idaho Power's own resources;
correct?
A. Yes.
O. So if we concede your point and remove the two
peaking resources from Dr. Reading's chartr we are stil-I
left with the fact that PURPA resources are l-ess
expensive than Idaho Power's most recent state-of-the-art
gas-fired base load unlt Langley Gulch, aren't we?
A. I stil-l- think that's a mj-sunderstanding of the
data that's used to create those charts.
O. But you conceded that Dr. Reading's
calculations are correct, didn't you?
A. f've never spoken to the correctness of his
numbers.
O. I believe you do.
A. I'm not disputing that they're incorrect. I
just never addressed that.
O. So finally, you note on page '7 to 8 of your
rebuttal testj-mony that QFs like Simplot or Clearwater
could sell their output to other utilities in other
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states. Would you agree that that's not always as easy
as it seems?
A. I can't respond to a generalization like
that.
MR. RICHARDSON: Madam Chair
COMMISSIONBR KJELLANDER: Yes, Mr. Mi1ler.
MR. RICHARDSON: Mr. Chaj-r, may I approach the
witness with a document?
COMMISSIONER KJELLANDER: Certainly.
(Mr. Adams distributing documents. )
MR. RICHARDSON: Mr. Chair, I'm handj-ng out
Idaho Power's petition for a declaratory ruling in the
matter of Idaho Power Companyrs petition for a
declaratory ru11ng regarding PURPA jurisdiction and --
MR. HOWELL: Mr. Chairman, could we have a
mi-nute untj-l I've been provl-ded a copy of that?
MR. RICHARDSON: Of course.
COMMISSIONER KJELLANDER: Certainly, and while
we're allowing that to be distributed, Ietrs look
quickly, this would be, to the extent that you want it
marked and identified, 209.
MR. RICHARDSON: f'm not going to mark it as an
exhiblt, Mr. Chairman.
COMMISSIONER KJELLANDER: You're not, okay.
MR. RICHARDSON: Thank you.
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COMMISSIONER KJELLANDER: Mr. Howell, do you
have a copy now?
MR. HOVIELL: I do. Thank you, Mr. Chairman.
COMMISSIONER KJELLANDER: Okay, Mr. Richardson,
if you'd like to proceed.
MR. RICHARDSON: Thank you, Mr. Chairman.
O. BY MR. RICHARDSON: Mr. Sterling, this is a
copy of an Idaho Power petition for a declaratory order
on file in an open docket before this Commission in which
Idaho Power responds to Kootenai E1ectric's attempt to do
exactly as you suggest, whi-ch is to move power to another
state. f 'm wondering if you would please read for the
record the paragraph beginning at the bottom of page 8.
No, not page 8, the paragraph beginning at the bottom of
page 5.
MR. SCHMIDT: Mr. Chairman, my copy just has
every other page; is that
COMMISSIONER RAPER: Odd pages only.
COMMISSIONER KJELLANDER: MT. Schmidt has
identified the fact that we don't have all the pages
here, good catch, and Mr. Richardson, in lieu of running
out and grabbing all the even numbered pages, do you have
any questions associated with the even numbers?
MR. RICHARDSON: I have a complete copy here,
which I can provide to the witness.
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COMMISSIONER KJELLANDER: Why don't we get that
to the witness and see if we can get through this without
having to break to make more copies.
MR. RICHARDSON: Yes, I apologize for that,
Mr. Chairman.
THE WITNESS: Itrs not me. I have page 5.
It's the other parties that are going to need page 5.
COMMISSIONER KJELLANDER: Is he golng to need
page 6?
MR. RICHARDSON: He will need page 6.
COMMISSIONER KJELLANDER: Then he wil-I need a
copy.
MR. HOWELL: Mr. Chairman, I'd l-ike a copy as
weII.
MR. RICHARDSON: So if we could take a break --
COMMISSIONER KJELLANDER: Okay, at this point
where we wil-I be is taklng a ten-minute break and j-n ten
minutes let's all head back here with brand-spanking new
copies that actually have all- the pages, and with that,
then we can go off the record.
(Recess. )
COMMISSIONER KJELLANDER: We will now go back
on the record and, Mr. Richardson, you have since the
break distributed a revised copy with all of the pages,
odd and even, and as I recall-, you were referencing a
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questi-on to Mr. Sterling that was associated, I believe,
with page 5, so f will- l-et you continue, but if you could
start with the question that you had asked Mr. Sterling
to read a paragraph that I believe began on page 5.
MR. RICHARDSON: Thank you, Mr. Chairman.
O. BY MR. RICHARDSON: To reset, restart here, the
question, Mr. Sterling, was finally, you note at page 1
to 8 of your rebuttal testimony that QFs like Simplot or
Clearwater can sel-l their output to other utilities in
other states, and my question was you would agree with
rTr€r would you not, that 1t's not always as easy as it
seems, wouldn't you?
A. And I think I responded that I can't respond to
a generalization like "as easy as it seems." I don't
know what you mean by that.
O. And in response, I handed out Idaho Power
Company's petltion for a declaratory order regarding
PURPA jurisdiction in Case No. IPC-E-1,1,-23, and it's a
petition for a declaratory order, and this asks the
Commission to take judicial notj-ce that this j-s a
petition in an active docket currently before this
Commissj-on, and I was asking you to read the paragraph
that begins on the bottom of page 5, and I'11 just
represent to the Commission that this is a matter where
Kootenai Electric Cooperative was attempti-ng to do just
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what Mr. Sterling was suggesting, whj-ch is sel1 its
electric output, its QF electric output, to a utility in
another state, and woul-d you please read the paragraph
beginning on the bottom of page 5?
MR. HOWELL: Mr. Chairman, I'm going to object
to the line of questloning. I think asking a wj-tness to
read from a document that is not prepared by Staff, but
is a petition prepared by another party in this case
is l-eads to confusi-on about whether the witness would
agree or not agree wlth the statement. As the Commission
is aware r or hopefully aware, that Idaho Power in this
particular case filed a petition not only in Idaho, but
in Oregon and the Commission in this case has done
nothing but issue a notice of petition.
There have been no Staff comments filed in this
case. There have been no further proceedings by the
Commission in this case. This matter has reached
resol-ution as far as I know because it was a matter that
was decided ultimately by FERC regarding Kootenai
Electrj-c's petition against the Oregon Public Util-ities
Commission, so whether this case is open or closed, I
think it's confusing to ask a witness to read a paragraph
from a petition, from a document, that the Staff has
never prepared, that the Staff has never opined on, that
the Commission hasn't had any further proceedings oD, and
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as far as I know, this matter j-s closed.
COMMISSIONER KJELLANDER: Mr. Richardson.
MR. RICHARDSON: Thank you, Mr. Chairman. ft's
interesting that counsel for the Staff would object to
admission of this document to show that it is in fact
difficu1t and challenging to move your power from one
jurisdiction to another. We're not here to I'm not
offering this to prove, one, that Idaho Power was correct
or Idaho Power was wrong, that the docket is open or the
docket is closed. I'm offering this exhibit, this
document, to demonstrate to Mr. Ster1ing the answer to my
question, which is it's not as easy as it seems. When
one entity was attempting to move their power to another
utility 1n a different state, this was the response they
9ot, dealing with multiple years of litigation before
this Commission, the Oregon
COMMISSIONER RAPER: Mr. Richardson, if you
choose to testify in this regard on this document, f
think it's something that you might choose to include in
closing statements, but we have a witness on the stand
that's waiting for questions from you.
MR. RICHARDSON: And he has a question before
him to read the paragraph begi-nning on the bottom of page
5, which I think is a legitimate response to his direct
testimony and that's my response to counsel-.
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COMMISSIONER KJELLANDER: For purposes of just
moving forward, I don't have a significant bit of
consternation with regards to Mr. Sterling reading that
paragraph, recognizing the objection that was brought in
by Mr. Howel-l and also understanding that Mr. Sterling
was not the author of thisr so if it helps us move
forward and we coul-d hear your loveIy voice attached to
those words which are not yours, Iet's go ahead and do it
and 1et's move on.
THE WITNESS: "Kootenai E1ectric's proposed
transaction is a bl-atant manipul-ation of PURPATs rul-es
and regulations by a QF developer in order to financially
profit to the direct and substantial- detriment of Idaho
Power's customers. Kootenai- states 1n its demand letter
to Idaho Power that it has attempted to obtain an Idaho
QF contract with Avista, but has 'reached an impasse
which would require litigation to resolve.' Attachment
1-, page 2. Thus, Kootenai Electric seeks out any
strained argument it can find to try to avoid addressing
the real- problems associated with obtaining a QE contract
1n the jurisdiction where both its project is l-ocated and
where it interconnects to the transmission grid.
Kootenai Electric's proposed transaction stretches the
bounds of legltlmacy, and such manipulatlon has the
possible practical effect of saddling Idaho customers
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with additional costs and higher power rates which exceed
Idaho Power I s avoided costs. "
MR. RICHARDSON : Mr . Chairman, that I s al-l I
have.
COMMISSIONER KJELLANDER: Thank you
Olsen.
MR. OLSEN: Yes, I have just a few questions
CROSS-EXAMINATION
BY MS. OLSEN:
0. Mr. Sterling, turning back to page 2 of your
direct testimony, you've already taLked a lot about this
between the prior generic case that you had testifled in
and with Mr. Richardson and everything, given the fact
that you had in the prior generic case suggested a
five-year contract term and are also suggesting, I
believe, if I understand your testj-mony, as one of the
tools or one of the ways the Commission can address this
issue is a shorter contract term as we1l, you also have
talked about a pricj-ng mechanism and I would just like to
try t.o, I guess, put a connecting theme here. Would it
be fair to say that your testimony could be summarized as
follows: Long-term contracts would be acceptable if
avoided cost pricing coul-d be accurate over the long
Mr
956
term; however, the avoided cost pricing is not accurate
over the long run and thus, some shorter mechanism must
be put in place to a1low contract prices to be adjusted;
is that a fair summary of your position?
A. Yes, I think that's a reasonable sunrmary.
O. So just, again, for the record, is it your
posi-tion that the contract term should be limited to fj-ve
years as opposed to the two-year limit suggested by Idaho
Power and the Irrj-gators?
A. Yes.
MS. OLSEN: I have no further quest j-ons.
COMMISSIONER KJELLANDER: Thank you, and Mr.
Adams.
MR. ADAMS: Yes, I have just a few questions
for Mr. Sterling.
COMMISSIONER KJELLANDER: Please proceed.
CROSS-EXAMINATION
BY MR. ADAMS:
O. Good morning, Mr. Sterling.
A. Good mornJ-ng.
O. So were you here yesterday when Mr. Allphin
testified that a QE that signed a two-year contract with
Idaho Power today would not be compensated for
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capacity?
A. Yes, I was here yesterday.
O. Do you agree with that statement?
A. Could you repeat the statement?
O. That a QF that signed an IRP-based methodology
contract to begl-n del-iveries in 2076 would not be
compensated for capacity.
A. That's true if the contract was signed today.
O. And how about a flve-year contract?
A. That would still be true.
O. Okay. Whatrs the date, what's the cutoff date,
where the QF would start getting capacity under Idaho
Powerts current rates?
A. I believe it's 2025.
O. Okay, and what j-s Avista's?
A. Irm not sure.
O. Does 2021 sound about right?
A. Yes.
a. So you testify in your direct testimony on page
11 regarding FERC's rules for contracts, contract length,
and you conclude that there's no specific requirements
under PURPA's regulations regarding contract length;
correct?
A. That's correct.
O. So do you think the Commissi-on coul-d shorten
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the contract length to be as short as the Commission
chose?
A. Yes, I do. In fact, they've done it before.
They've shortened contract length on multiple
occasions.
0. Do you think two years would be okay?
A. My position or my recommendation is that it be
five years.
O. Okay, wel-l, I'm just asking you in the context
of page 77,Iines 11 to 14, where you state that there's
no specific limit to how short it could be. I'm just
wondering if you think that it could be, sdy, one year or
sj-x months or one day.
A. I'm just observing that the EERC rules do not
specify.
O. So there's no l-imit at all in the FERC rul-es?
A. None that I see.
O. Would you agree that at some point we're realIy
just talking about a short-term energy onJ-y rate that the
QF is being paid with these shorter contract terms?
A. It depends on when the contract is signed. It
depends on the duration of the contract, and it depends
upon whether the utility needs capacity during that same
time frame, but if the utility does not need capacity
during the time frame or the term of the contract, then,
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y€s, it wou1d probably be just an energy only contract.
O. Okay, and you did review the FERC regulation;
correct?
A. Yes.
O. Okay, but j-sn't it true that 18 CFR
292.304 (d) (2 ) provides the QF with the option to sell-
energy or capacity over a specified term?
A. That's true.
O. But the QF wouldn't be abl-e to sell capacity
under the shorter term contract lengths under the
cj-rcumstances existing today?
A. What I think the FERC rul-es provide or requlre
is that if capacity is provided and j-t is needed by the
utility, it has some value, then the utility must pay for
ir.
O. Okay, moving on to page 71 of your testimony,
you discuss PURPA rules in other states and you suggest
that the Washington in Washington they only allow
five-year contracts. You also reference 2)-year
contracts in Oregon, Utah, and Wyoming, and 25-year
contracts in Montana; do you remember that?
A. Yes.
O. What did you review with regard to the
five-year contracts in Washington? Did you revj-ew a
tariff or orders?
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A. I don't recall reviewing anything. I think
that was what f was tol-d verba11y.
0. Oh, okay. Did you know that PaciflCorp's
five-year contract term tariff in Washington provldes the
QF compensation for energy and capacity during that
entire term?
A. I'm not aware of thatr rlo.
MR. ADAMS: f'd like to approach the witness
with a document, Mr. Chairman?
COMMISSIONER KTIELLANDER: Do you have both even
and odd pages?
MR. ADAMS: I think I do. I promise we have
both even and odd pages this time.
COMMISSIONER KJELLANDER: Then please proceed.
(Mr. Rj-chardson distributing documents. )
O. BY MR. ADAMS: So Mr. Sterling, is this the
Pacific Power Schedul-e 37 tariff for Washington; is that
what t.his document states?
A. It appears to be, yes.
MR. ADAMS: Okay, I'd move to admit this into
the record as Exhibit 209.
COMMISSIONER KJELLANDER: Without objectj-on, we
will mark and identify this as Exhibit 209.
MR. HOWELL: Mr. Chairman, Irm not sure a
proper foundation has been Iaid for this. This witness
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didn't necessarily agree that this was Schedul-e 37 from a
PacifiCorp from a Washington frm not even sure what
state.
COMMISSIONER KJELLANDER: We have an objection,
so i-n response to that
MR. ADAMS: Wel-l-, ye s, my response is, you
know, the witness did testify as to what the contract
term is in Washington. This is the Washington tariff.
To the extent that Mr. Howel-l- doesn't believe it's an
authentic copy of PacifiCorp's Washington tarj-ff, I think
he I think the witness coul-d stil-l- review this
document and teIl us what it states with regard to
whether QFs are paid for capacity for the entire
five-year term.
MR. HOWELL: Wel-l-, Mr. Chairman, Irm not sure
that these are the entire pages. I don't think a proper
foundation has been l-aid for this document. It's dated
in 20LL. I'm not sure there's been any subsequent
updates from that.
MR. ADAMS: If you'd turn to the second pa9e,
Mr. Howel-l-, it ' s ef f ective Eebruary 2 8 , 2074 .
MR. HOWELL: !{eJ-I, I guess that's my poj-nt,
Mr. Chairman. What purports to be Original Sheet 31.7 is
issued Ln 20L7 and apparently 37 .2 is in 2013 and 'L4.
Again, the witness stated that he was aware only of a
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five-year term, and Irm not sure that the proper
foundation has been laid for the introduction of this
exhibit.
MR. ADAMS: WeII, then in that case, if the
exhibit won't be a11owed, I woul-d move to strj-ke the
l-ines of Mr. Sterling's testimony stating that the
Washington Commission has five-year contract terms for
lack of foundation because the witness stated that he
didn't read any documents. He just heard that from
someone else.
MR. HOWELL: I think earlier in this hearing
Mr. Clements testified on behalf of Rocky Mountain Power
that Washington does indeed have a five-year PURPA
contractr so there is testimony in the record by another
witness that Washington has a five-year contract.
COMMISSIONER KJELLANDER: Let me jump in
quickly here and I appreciate the robust nature of the
debate thatrs been made amongst the two of you and al-so
the civilj-ty associated with it. Let me just ask this
question of you, Mr. Adams: Is there a way without
putting this in play to go ahead and ask the specific
questi-on you want to get to to get to the end game?
MR. ADAMS: Yes, that would be fine.
COMMISSIONER KJELLANDER: Then let's do that,
okay?
963
a. BY MR. ADAMS: Mr. Sterling, could you turn to
the second page of the document?
A. I 'm there.
O. What does it state after the number 7 there,
the avoided cost rates?
A. After avoided cost rates there's a table with
three columns. Two of the columns say capacity payments
by year; the third co1umn is energy payments by year.
O. And each year has a capaclty payment beginning
2014; is that correct?
A. That's correct.
MR. ADAMS: Okay, no further questions.
COMMISSIONER KJELLANDER: Thank you.
Mr. Miller.
MR. MILLER: Mr. Chaj-rman, I'm confident that
my intervenor colleagues are going to possibly plow as
much ground as can be plowed with this witnessr so I
don't have any questions.
COMMISSIONER KJELLANDER: Thank you. Mr.
Otto.
MR. OTTO: Thank you, Mr. Chaj-rman. I do have
just a few questions.
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CROSS-EXAM]NATION
BY MR. OTTO:
A. So Mr. Sterling, you testified in your writj-ngs
and here today that you're the lead Staff person on PURPA
issues and the avoided cost model as part of that; is
that correct?
A. Yes, it is.
a. And 1s it your understanding that under this
model, the capacity payments begin when the utilities
identify a resource deficiency date?
A. That's correct.
O. Is it your understanding that the energy
component 1s based on the utility's incremental avoided
cost in each hour?
A. Yes.
a. Thank you. You also testified in writing and
here today that the real- risk is about thousands of
megawatts of proposed QEs; is that correct?
A. Yes.
0. Did you observe the Idaho Power IRP
development?
A. The 2015?
O. The 20L5 development. This may help.
Specifically the day where Mr. Allphin explained PURPA to
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the IRP advisory committee, were you there that day?
A. I don't recall specifically, but I think I only
missed one meeting and I don't bel-j-eve that was the
meeting you're talking aboutr so I think I was there,
yes.
O. Okay, and how does the does the IRP, Idaho
Power's IRP, does it forecast future PURPA development?
A.
o.
No.
And why not?
not?
A. Because the IRP process is a planning process
for the utility to determine how its how the best way
to meet anticipated load is, and it i-n planning has to
rely on what it knows it can count oDr and when it comes
to PURPA projects, they take what comes, whether it comes
or whether it doesn't come, when it comes, however much
comes. It' s not within the control- of the utiJ-ity and so
the utility doesn't plan for it.
O. So what I heard you say is that in the fRP,
is that whatthey can't count on any future development;
you just said?
What's your understanding of why
itrs almost
will- come
A. Generally, yes.
O. But in this case your position is
certainty that these thousands of megawatts
onl-ine?
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A. I havenrt stated that.
a. It's the risk that that will happen?
A. That's true, y€s.
O. Now, turning to your direct testimony on page
2, lines 18 through 24, you say that it's -- wel-I, let's
make sure we get this right. Oh, I have it right here.
You say you don't believe that any avoided cost
cal-culation can prove to remain accurate over a 20-year
period. Do you see that?
A. Yes, I do.
O. And you stand by that?
A. Yes, I do.
0. On page 9 in l-ines 72 through 16, actually all
the way through !9, you cite to several power purchase
agreements. Do you see that?
A. Yes.
O. Do you know the term of those power purchase
agreements?
A. I donrt recall wlth each specific project
mentioned, but i-t's either 20 or 25 years.
O. Are those fixed price contracts?
A. Yes, I believe they are.
O. And do you believe those benefit ratepayers?
A. Yes, I do.
MR. OTTO: Thank you. That's all.
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COMMISSIONER KJELLANDER: Okay, I guess I'm
just not used to hearing the word thank you, I appreciate
that. Mr. Sanger.
MR. SANGER: No questions, Chairman.
COMMISSIONER KJELLANDER: Thank you.
MR. SANGER: You' re wel-come .
COMMISSIONER KJELLANDER: MT. Hammond.
MR. HAMMOND: Just a couple, Mr. Chairman.
CROSS-EXAMINATION
BY MR. HAMMOND:
O. You testified to the thousands of potential
megawatts that have been or projects that are seeking to
come online. How many of those projects at this point
have come online?
A. Thi-rteen, I believe.
O. Thj-rteen? And how much do they represent? How
many megawatts do they represent?
A. WeIl, the 13 projects collectively represented,
I believe, 461 megawatts, and four of those 13 have since
been terminated and those four, I believe, are 160
megawatts collectively.
O. And maybe I shou1d clarify, maybe Irm not
understanding. I guess when I'm saying online, they're
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delivering power to the utilities.
A. Irm sorry, I misunderstood.
O. I'm sorry.
A. None of them are yet online.
O. So at this point therers no megawatts being
delivered on these thousands of proposed projects; is
that correct?
A. That's correct.
O. Okay. We've heard a lot of testimony and
positions made in this case about sort of what is
bel-ieved to be a bal-ancing of PURPA, that PURPA is the
Commission is supposed to encourage the development of
these projects through PURPA, but, on the other hand, the
utilities have expressed the principle, and maybe I'm
saying things inaccurately, but ratepayers should be
indifferent to PURPA power coming onl-ine, they shouJ-dn't
be paying too much; is that a fair assessment of the
test j-mony you've heard?
A. Yes.
O. On page 2, you've made the point, page 2 of
your direct testimony on line 14, startj-ng at line 74
through line t7, you make the point that long-term
contracts, by themsel-ves, would not necessarily be
problematic; is that correct?
A. Thatrs correct.
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O. Wou1d a fair and balanced way to deal with
PURPA to address the Commission's duty or obligation to
encourage PURPA development, while at the same time
providing a mechanism by which ratepayers wil-I be held
indifferent, if prices -- if you updated avoided cost
prices on a more frequent basis, could that address that
concern and provide that bal-ancing by itself of those two
goal s ?
A.
o.
A.
Let me clarify your question a bit.
Sure. Thank you, Irm sorry.
When you say update the avoided cost prices,
are you talking about updating prices periodically in an
existj-ng contract or for new contracts going forward?
O. Either one, either scenario.
A. Wel-l-, we do already and have for many years
updated avoided cost rates going forward as they would
apply to new contracts, but once a contract has been
signed, those contracts do not get changed, at least
modern contracts do not get changed, for the term of the
contract. If we had a mechanism in an existing contract
to periodically update those rates, that could perhaps
resolve some of the problems that we have now.
MR. HAMMOND: Thank you very much. I have no
further questions.
COMMfSSIONER KJELLANDER: Thank you, Mr
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STERLING (X)
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Hammond. Ms. Nunez.
MS. NUNEZ: Thank you, Mr. Chair, I do have a
few questions.
CROSS-EXAMINATION
BY MS. NUNEZ:
O. Good morning, Mr. Sterling.
A. Good morning.
O. Based on your 20 plus years of experience
working in PURPA pricing and risk assessment, can you
please comment on how the Commission and the utility
companies have analyzed the environmental- harms of energy
production, such as air and water pollution, habltat
degradation, and climate change in the context of risk
assessment and pricing analysis?
A. Wel-l-, we don't do any risk analysj-s as part of
PURPA pricing and we do not al-so incl-ude any of the other
things that you mentj-oned in consideration of PURPA
prices.
a. Do you believe that the Commission has
authority to consider the risks and costs associated with
such environmental consequences when they're acting in
the public interest?
MR. HOWELL: Mr. Chairman, I'm going to object
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to the question as being beyond the scope of this
wj-tness' direct and rebuttal testimony. He's already
testified there's no testimony in his prefiled rebuttal
or direct that discusses environmental issues with the
pricing of avoided costs.
COMMISSIONER KJELLANDER: Thank you,
Mr. Howell. Ms. Nunez, can you direct the witness to a
page or a l-ine number?
MS. NUNEZ: The scope of my quest j-oning is
about the ful1 gamut of the risks to Idaho ratepayers
when making decisions about the type of energy generation
that utility companies will be doing in the future, so it
is linked to his testimony in the sense that he has
experience working with the Commission and the utillty
companies on risk assessment and PURPA decisions, so
that's the link. I'm not alleging that therers anything
about environmental issues in his testimony.
MR. HOWELL: And I woul-d renew my objection.
This witness has already testified that avoided cost
rates do not incl-ude any cost-benefit analysis or the
balancing of environmental issues in the calculation of
avoided cost rates.
COMMISSIONER KJELLANDER: And Irm incl-ined to
agree wj-th Mr. Howell- in this one. Ms. Nunez, if there's
a way to get at the questioning that you want if you
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coul-d direct the witness to a page number and lines
within his testimony, that would be greatly
appreciated.
MS. NUNEZ: I actually did get the answer to my
question, which is that these environmental harms aren't
included in the conversation.
COMMISSIONER KJELLANDER: Well-, fair enough.
Letrs move oo, then. Is that it?
MS. NUNEZ: That's it.
COMMISSIONER KJELLANDER: Thank you.
Mr. Arkoosh.
MR. ARKOOSH: No, thank you, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Schmidt.
MR. SCHMIDT: No, thank you.
COMMISSIONER KJELLANDER: Are you regretting
that you showed up here?
MR. SCHMIDT: No, I'm enjoying it. I wish I
would have been here yesterday. This is a very nice
atmosphere and I enjoy being here.
COMMISSIONER KJELLANDER: Wel-l-, we hope you can
find your way back.
MR. SCHMIDT: That remains to be seen.
COMMISSIONER KJELLANDER: Idaho Power.
MR. WALKER: Thank you, Mr. Chairman.
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CROSS-EXAMINATION
BY MR. WALKER:
O. Mr. Sterling, I'd just l-ike to follow up on the
Washington tariff sheet that was presented to you. Do
you still have that with you?
A. Yes, I do.
O. And on page 2 -- well, first of a1I, on the
front page nor strike that. On page 2, Mr. Sterling,
do you see this is where counsel previously had you read
the avoided cost rates? Do you recal-l- that?
A. Yes, I do.
O. Do you see No. 7 under the terms and conditions
above that?
MR. ADAMS: Mr. Chairman, I'm going to object
to this. This is not cross-examinati-on. This is more in
the form of redirect examination. Itrs more along the
lines of friendly cross, I think. I was pretty 1imited
in what I was allowed to ask, so I don't think itfs fair
for Mr. Walker to fol-l-ow up with questions himself . Mr.
HoweIl cou1d, I suppose.
COMMISSIONER KJELLANDER: Mr. Wal-ker, having
not heard your question, it's difficul-t for me to assess
whether it's friendly cross, but as I recall, it was a
very l-imited response that Mr. Sterling had to a question
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in which he read a specific line. Can you attach it to
that specific response?
MR. WALKER: Yes I was simply going to ask him,
Mr. Chairman, to read the numbered item 7 on that same
page that counsel had him read from in response to his
question.
COMMISSIONER KJELLANDER: I'11 al1ow that.
THE WITNESS: "The avoided cost rates are fixed
for five years. However, these rates are recalculated
every year and applicable to any seller that enters into
a power purchase agreement with PacifiCorp in that year."
COMMISSIONER KJELLANDER: Does that conclude
your questioning?
MR. WALKER: I have one foIIow-up question.
O. BY MR. WALKER: Mr. Sterling, is there you
read the capacity and energy payments, is there any
indication here of what the utj-lity's capacity
sufficiency or deficiency position was to establish these
rates ?
A. Not that I can see, but, you know, this j-s a
Washington tariff that has no standing in Idaho.
MR. WALKER: I have no other questions.
COMMISSIONER KJELLANDER: Thank you. Avista.
MR. ANDREA: One question, Mr. Chairman.
COMMISSIONER KJELLANDER: If you coul-d move a
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STERLING (X)
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microphone cl-oser to you. Thank you.
CROSS-EXAMINATION
BY MR. ANDREA:
O. Good mornlng, Mr. Sterling.
A. Good morni-ng.
O. I just want to follow up, a1so, on the
questioning on the Washington PURPA rates. It was
suggested that, and I don't reaIly know because I don't
have the tariff sheet, PacifiCorp does include capacity
payments in its Washington five-year contracts. Are you
aware that Avista does not include a capacity payment in
its five-year Washington PURPA contracts?
MR. ADAMS: f'm going to object itrs beyond the
scope and potentially friendly cross. f don't know what
Mr. Andrea j-s trying to
COMMISSIONER KJELLANDER: I'm very much
inclined to agree. I appreciate the questj-oning, but it
certainly does sound like something that would be better
addressed in redirect.
MR. ANDREA: That's fine, Mr. Chairman. I was
just trying to have a complete record as to the
Washington rate, but I withdraw the question. Thank
you.
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Staff
COMMISSIONER KJELLANDER: I appreciate that and
thank you.
MR. ANDREA: No further questions.
COMMISSIONER KJELLANDER: Thank you. Letrs
move to Rocky Mountain Power.
MS. HOGLE: Rocky Mountain Power has no
questi-ons. Thank you.
COMMISSIONER KJELLANDER: Are there questions
from the Commission?
COMMISSIONER RAPER: I have just one.
EXAMINATION
BY COMMISSIONER RAPER:
O. I'm going to ask Mr. Sterllng to speculate and
see if my former boss Mr. Howell wants to object to my
question to the witness. Mr. Sterlingr orr page 11 of
your direct, line 7, therers a sentence that begins,
"Long-term contracts based on forecasted rates create
greater risks for customers because the rates in the
l-ater years are not reflective of avoided costs"; so my
question to you based on that statement is, don't you
believe that FERC took into account those considerati-ons
of long-term contracts when it talks about
underestimations and overestimations eventually balancing
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out?
A. I believe that it did, although I still would
submit that neither PURPA nor FERCTs rul-es implementing
PURPA specify contract length, so while FERC may have
contemplated overestimations and underestimatj-ons of
avoided cost ratesr w€ don't know whether those
overestimations or underestimations would be for a period
of one year, two years, fj-ve years, 20 years, 30 years,
but y€s, I do think they thought about overestj-mations
and underestimations and whether in fact they would
balance out or not.
COMMISSIONER RAPER: Thank you. That's all.
COMMISSIONER KJELLANDER: Thank you. There
being no further questj-ons from the Commissj-oners, we
move now to redirect. Mr. Howe11.
MR. HOWELL: Thank you, Mr. Chairman.
REDIRECT EXAMINATION
BY MR.
o.
Exhibit
A.
o.
A.
HOVIIELL:
Mr. Sterling, do you have what's been marked as
209 in front of you?
Isita
The Washington tariff Schedule 37.
Yes, I do have that.
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O. All right, and could you look at the first page
of that under the paragraph l-abeled "Avail-ability"?
MR. ADAMS: Mr. Chairman, I'm going to object
again. I think this is beyond the scope of what I was
all-owed to ask and it was not admi-tted as an exhibit
either over Mr. Howel-l-'s objection, so to go beyond the
scope of the questions I asked, I think, wou1d be unfair.
MR. HOWELL: Mr. Chairman, I don't think it's
beyond the scope. Whether it's admitted or not, there
was cross-examination on this specific exhibit that is
purportedly a Pacific Power tariff schedul-e and so I
think I'm within my rights to ask upon redirect about
this specific tariff.
COMMISSIONER KJELLANDER: I appreciate that and
I guess thatrs the risk you run of bringing a document in
on the l-ast dry, so f 'm going to a1low the question.
MR. HOWELL: Thank you, Mr. Chairman.
O. BY MR. HOWELL: So Mr. Sterling, turnJ-ng your
attention to what, I guess, purports to be the front page
under the heading "Availability"
A.
o.
tariff apply
Iess than two
A. It
I see that, yes.
if you were to read that, doesn't this
to cogeneration/smaII power production of
megawatts or two megawatts or less?
appears that wdy, yes.
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STERLTNG (Di)
Staff
o.
tariff
A.
o.
rates,
Pacific
there?
So for purposes of IRP in ldaho, would this
be applicable to IRP methodology calcul-ations?
It coul-d appfy to a sma1l number of projects.
And turning over the page on the avoided cost
there's no indication, is there, about whether
Power was in j.n a surplus capacity situation, is
A. There's no indication on the tarj-ff, no.
O. Fina11y, Mr. Richardson asked you about your
criti-cism of Dr. Reading's Chart No. 1 and the
calculations by includlng Idaho Power's peaker plants in
the power costs. Do you recollect that testimony?
A. Yes, I do.
O. Isnrt it true that that was not your only
critlcism of Dr. Readingrs Chart No. l?
A. Yes.
O. And what was your other criticism?
A. WeII, I think my other criticism related to the
fact that you can't just compare costs between resources
that way. Under the IRP methodology, the modeling looks
at an hourly dispatch of all the resources in the
utillty's fIeet. In some hours, a QF may be displacing a
coal pIant. In other hours, it may be a different coal-
pIant. In other hours, it may be a gas plant. In other
hours, it may be a peaking gas p1ant. In other hours, it
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STERLTNG (Di)
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may be market purchases, so it's a whole collection of
resources that go into the determination of avoided cost
rates under the IRP methodology, and to compare very
different resources with very different capacity factors,
very different operating circumstances is just not a
valid comparison.
O. And to drill down on your answer, wasn't one of
your criticlsms that this chart omitted any costs from
the Company's hydro generation?
A. Yes.
MR. HOWELL: Thank you, Mr. Chairman. I have
no further questions.
COMMISSIONER KJELLANDER: Thank you,
Mr. Howel-I, and that completes our witness list for this
case.
(The witness left the stand. )
COMMISSIONER KJELLANDER: As I mentioned
yesterday, it would be my hope that there would not be a
request for briefs on this case,' lnstead, we would have
some closing statements. Does anyone have another
approach that they would l-ike to take? Is anyone bent
directly on the path of wanting to file briefs and feel-
comfortable that we coul-d do it through the approach of
closing statements? Good. With that in mind, would it
be appropriate to perhaps take a ten-minute recess to
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allow people to gather their thoughts, and just before we
break, if I coul-d briefly just get a quick show of hands
from those who want to be incl-uded in that process so I
can kind of guesstlmate when to te11 my friends that I ' d
Iike to have l-unch. I'l-l- tell them tomorrow. Eair
enough, we wiII go off the record and return in ten
minutes.
(Recess. )
COMMISSIONER KJELLANDER: WelI, welcome back.
We'Il- go back on the record. Even if you didn't raise
your hand that you want to make a closing statement,
we're going to go through and allow everybody an
opportunity to get there. The only privilege of being a
former Commissj-oner and now being 1egaI counsel-
representing clients before us is that we either rea11y
like you or just want to get you out of here, so l-et's
start with Mr. Miller.
MR. MILLER: Thank you, Mr. Chairman. f guess
I would note that I noticed this morning that the
Commission's policy on payment for coffee doesn't seem to
exclude former Commissi-oners.
COMMISSIONER KJELLANDER: But it's a fu1Iy
embedded service.
MR. MILLER: Thank you very much for the
accommodation. By way of j-ntroduction, 1et me point the
982 COLLOQUY
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Commission to the fact that we have filed the testimony
of Mr. Van Gulik in this case who provides a
feet-on-the-ground perspective regarding the difficul-ties
of developing PURPA solar projects and the current status
of the viability of that market at current prices.
No party fil-ed any testimony rebutting Mr. Van
GuIik's testimony and no party cross-exami-ned Mr. Van
Gulik in any serious way yesterday, so rather than review
that testimony with you here, I would just ask that
during the course of your deliberations you again review
Mr. Van Gulik's unrebutted testimony.
Second, I appreciated the Chairman's
explanation to the public the other night at the public
hearing where the Chairman explained that the Commission
approaches cases such as this in a judicial way; that is,
that its decision must be based on evidentiary facts in
the record such that any decision would be sustainable as
based on substantial- and competent evidence, so
approaching that case approaching that case in this
wdy, the first question obviously is who has the burden
of proof, and the answer to that is obvious; that is, it
is the utility companies' burden to introduce into the
record sufficient facts to justify a departure from a
long-standing policy of the use of deployment of 20-year
contracts.
CSB REPORTING
(208 ) 890-5198
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The policy was upheld just two years ago
despite requests to change it then. Of course, the
Commission is not bound strictly by stare decj-sis, but at
the same token, any change from existing policy has to be
based on facts that are in the record before the
Commission, so what are the relevant facts that are
before you as the result of this hearing?
The first re]evant fact is that a two- to
five-year contract would bring renewabl-e development
under PURPA to a halt. ,M.. Van Gulik's testimony on this
point is unrebutted. Several other witnesses made the
same polnt. The utility companies and the Staff don't
contest this fact, because that is their intended result.
Although there was some testimony that some QF projects
such as existing industrial gas plants might be able
to -- might prefer shorter contracts, there is absolutely
no evidence in the record to rebut the point that
two-year, two- or five-year, contracts wou1d bring new
renewable development under PURPA to an end, so what are
the other facts that are in the record that bear on this
issue?
The first fact is that currently there are zero
megawatts of renewable sol-ar PURPA onl-ine and producing
power to fdaho Power Company. Ms. Grow confirmed that on
cross-examinati-on. What are the other rel-evant facts?
984 COLLOQUY
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They can be derived from Exhibit 11. Page 2 of Exhibit
!1, if you have it with you, shows that from January
through April of 2015, the number of renewabl-e megawatts
under contract has declined rather than increased. The
number of renewable megawatts under contract went from
401 to 260.
The other relevant facts disclosed by Exhibit
11 are on page 3, and this is reaIly the heart of the
utility companies' case and exhibit -- page 3 is a l-ist
of PURPA projects that the Company has labeled as
proposed solar, but if you go beneath the surface of this
exhlbit, certain other facts emerge as discl-osed by Mr.
Adams' very professional cross-examination yesterday and
my meager efforts at cross-examination, but the facts
that emerge when you go beneath the surface are that of
the 41 projects l-isted here, only 74 provide enough
information to even reach stage one of the Idaho Power
contracting process. Of those, only two received
indlcative pricing for 20-year contracts.
Mr. Allphin indicated in his testimony that
perhaps one had gone to the stage of actually requesting
a contract, but zero of these projects entered into
serious negotiations and ever executed a final and
binding contract. Mr. Allphin resisted my efforts or
suggestion that perhaps this exhibit should be, which is
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CSB REPORTING(208) 890-s198
labeled proposed PURPA should be, somehow relabe1ed to be
an more accurate reflection. I would suggest the best
better l-abel for this exhibit woul-d be a list of tire
kickers. That's a 1ega1 term.
The next fact that is, I think, undisputable is
that the IRP method as it currentl-y works is
sel-f-correcting; that is, it is producing prices such
that the demand for sofar PURPA projects is decreasing as
previous projects come on1ine. Mr. Chairman and Members
of the Commission, Senator Patrick Moynihan was famously
quoted to saying, "You're entitled to your own opinion,
but you're not entitled to your own facts," and if you
want to put a bipartisan tone on it, President Reagan was
famously quoted as saying, "Facts are stubborn thingsr "
and the facts as they exist in this record are
insufficient to support a change in policy that has been
in place for many years.
The util-ities have the burden of proof and they
have failed to carry their burden of proof. Those are my
meager thoughts.
COMMISSIONER KJELLANDER: Thank you,
Mr. Mi-l-l-er. Mr. Ol-sen.
MR. OLSEN: We have a few comments. As the
Irrigators, we're obviousl-y a big consumer of this
electricity. We're not producers of the PURPA projects,
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and one thing that's troubling
out in Mr. Yankel's testimony
to us and what was pointed
that it doesnrt appear
that certain resources would be necessary at this point
in time and the Company would be forced to buy the output
of these projects, notwithstanding the fact that theyrre
not needed, and herein lies the crux, I think, of the
issues is this policy issue needs to be addressed by the
Commission, because to require the forced purchase of
this, notwithstanding j-t's not needed in their resource
stack, I think is not logical or fair, just, and
reasonabfe to the Idaho ratepayers, and so we woul-d
encourage the Commission to look at all the factors that
have come out in these proceedings and rule what you
think would be fair, just, and reasonabl-e. Thank you.
COMMISSIONER KJELLANDER: Thank you. Mr.
Schmidt.
MR. SCHMIDT: Thank you. There is a reason I
came. I did want to get on the record why Micron is
participating, but l-et me first say what we're not doing.
We're not here to oppose or support any particul-ar
project, whether it be a cogeneration project or a solar
project, but we are here merely as a customer. We're the
largest customer on Idaho Power's system and the cost of
buying power from Idaho Power is a slgnificant operating
cost to us. We don't typically participate in these
t-
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cases unless we percej-ve or see that that cost may be
affected and we're askj-ng that you at least take into
consideration the impact that your a..i"io., in this
docket may have on t.hat cost.
Now, as I have reviewed the record and,
fortunately, my partner who was here yesterday, sent me
about 35 pages of notesr so I think I followed most of
the cross-examination 1n intimate detail, maybe more than
f wanted to at 11:00 o'clock last night, but as I look at
the record in this case, it seems to me that you have a
couple of important decisions to make. One is the
main one is the length of the contract term.
I had initially intervened in this case
thinking there may be a 1ot more attention or j-nterest in
the calculatj-on of the rate and how avoided cost is done,
because I'm not here to teII you that your method is
wrong or inaccurate, but my experience shows that there's
a l-ot of other ways that it can be done and they're al-l
perceived as fair, so there. is a 1ot of dj-scretion that
this Commission has under PURPA, even though PURPA is a
federal mandate.
I've been working on
three decades, but PURPA does
contract term that you need to
your discretion. Idhether you
PURPA-type cases for over
not mandate the actual
i-mplement. That i-s within
choose 20 or whether you
988 COLLOOUY
choose five or even as l-ow as one, I think in this record
maybe you can only go as l-ow as two, but I think that's
up to you, and it should be based upon what you believe
is j-n the best interests of not just the utilities and
the developers who are all here who want to build more
projects, but also the customers that you have to look
out for as well, and Trm pleased to hear there is another
customer represented in the room.
f thought we were one of the only ones and
that's why Micron wanted to participate is we wanted to
make sure that you don't l-ose sight of customer effect in
your decisions here, because PURPA does have effects.
It's intended, and f think the last witness who testified
made this cl-ear even throuqh the cross-examination, the
customers are supposed to be indifferent and indifferent
means PURPA should not hopefully in the short term and
certainly not 1n the long term cause us to pay higher
costs. ft's intended to avoid costs that we otherwise
would have to pay that the utility incurs. That's the
concept of avoided costs. It's a very simple concept.
It's a very logical concept, but it gets messy in the way
in which you implement the specifics of it.
Now, the facts are we have an excess capacity
situation. When there is excess capacity, you would not
let Idaho Power buil-d another power pIant, you should
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not, because capacity is not needed. In those
circumstances, hopefully, you didn't get too far
overcapacity, but as we know, capacity is lumpy
sometimes, so we just added into the system Langley Gul-ch
just a few years ago and Langley Gulch has put us in a
very nice situation. The circumstances in the region
al-so have us in a very nice circumstance. Customers
should benefit from that. Why? Because they paid for
Langley Gul-ch to go into their rates and it impacts our
rates.
Secondly, w€ know that the rates that are
recovered by PURPA projects are passed through dollar for
dollar, so the utility doesn't profit on that, which I
think is appropriate policy and it's consistent with most
of the states in the country j-n the way they handle these
type of contracts, but to pass through therefore, 1t
passes through not just energy, but energy and capacity,
costs through your annual- adjustment mechanj-sm.
Customers l-ike Micron are high load factor customers, so
they pay one could argue a disproportionate share of
that, but they pay more j-n their rates because they are
high l-oad factor customer for that portion of the rates
than they do as other portions of the rates change over
time and less frequently, so we're not saying that we
think there's an obvious decision here that you should
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make that dictates one result or another.
We think it's solely within your dj-scretion and
we would only ask that you make sure you consider what
the impact can be on customers, particularly in the near
term, because every time you change a rate that impacts a
customer Iike Micron maybe five percent, that's goj-ng to
impact over mi1lions of dollars of our operating costs.
That will affect Idahors economy. That will affect our
ability to hire more employees or contj-nue with the labor
force we have. A lot of other factors come into that,
but energy is a big one and that's why we're here.
We care about whether our costs are going to
stay stable, so I don't know if the record in this case
makes cl-ear enough what the impact on our rates will be,
but I do know from experi-ence that if you add capacity
into rates when capacity is not needed, at l-east in the
near term, you end up paying higher costs.
If you generate power when other power has to
be avoided or not used because it can't be dispatched,
you impact costs, so if those costs
impacted severelyr we ask that you
consideration in making a decision
with your policy of whether this is
with a 2O-year contract term or not
COMMISS]ONER KJELLANDER :
are going to be
take that into
whether you continue
the time to continue
. Thank you.
Thank you.
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Ms. Nunez.
MS. NUNEZ: Thank you. The Snake River
Al-Ij-ance believes that a decision by the Commission to
halt the development of renewable energy exposes fdaho
ratepayers to economic risks that have not been
adequately analyzed. The testimony of Ken Mil-l-er
elaborates on the discussion that we think needs to
happen, especially when defining what Idaho needs.
V'le believe that the technlcal and political
j-ssues associated with integrating large amounts of
renewabl-e energy are resolvable by the many brill-iant
minds we have in this state. We encourage ambition and
optimism and an accelerated commitment to a cl-ean energy
future for Idaho. We thank everyone for holding the
space and offer our support in this i-mportant process.
Thank you.
COMMISSIONER KJELLANDER: Thank you. Mr.
Sanger.
MR. SANGER: Thank you, Commissioners. For the
record, my name is Irion Sanger. I'm the attorney for
Renewable Energy Coal-ition and Renewable Energy Coalition
recommends that any relief you adopt in this proceeding
not appfy to QFs under the rate eligibility cap; in other
words, contract terms shoul-d not be reduced for QFs,
sol-ar and wind QEs, 100 ki-lowatts and be1ow and any other
992 COLLOQUY
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CSB REPORTING
(208 ) 890-s198
QF 10 megawatts and below
While REC has concerns about the allegations
raised by the util-lties in their filings, we do commend
Idaho Power for not recommending that contract terms be
reduced for small QFs. Avista also is not facing a large
amount of PURPA development and we understand that thelr
position is primarily that they want whatever rel-ief is
provided to ldaho Power Company and Rocky Mountain Power.
Therefore, you have both Avista and fdaho Power which are
either supporting our view that you don't extend any
rel-ief to smal-l- QFs or not opposing that. Al-so, Staff
has recoflrmended that smal-1 projects not have their
contract terms reduced.
The only party in this proceeding that has a
different view is Rocky Mountain Power. Now, we
recoflrmend that Rocky Mounta j-n Power' s proposal be
rejected because they have not provided any evidence to
meet their burden of proof that any of their problems are
being caused by small projects, nor have they provided
any evidence that ratepayers wil-l be better off i-f you
reduce the contract terms f or smal-l QEs.
Now, as explained in the testimony of the
Coalition's witness John Lowe, most existing projects on
the system right now are smal-l- hydroelectric projects
wel-l under the size threshold for pubJ-ished rates. Now,
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CSB REPORTTNG
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the util-ities rely upon these projects to provide needed
energy and capacity. They include them in their
lntegrated resource plan and they provide significant
seasonal benefits to the utilities as wefl as being major
parts of the Idaho agricultural economy and the local
communities in which they operate in.
Now, I think the record is pretty cl-ear that
these small QFs under the rate eligibj-lity cap are not
causing any of the prob1ems that have been alleged 1n
this proceeding. Essential-ly, we would not be here if
there was not a large amount of proposed sofar
development. This proceedlng would not exist.
Now, Paul- Cl-ements, Rocky Mountain Power's
witness, sLated in his rebuttal- testimony that the
primary concern of Rocky Mountain Power that led to its
position 1s that currently it has tons of proposal-s for
new QF projects to provide power that is not needed to
meet the customers needs. Mr. Clements also has his
Exhibit 601 which identified B9 new proposed projects.
As he explained yesterday, there's only one of those
projects in Idaho, which is not a wind or solar project,
and there's only two projects which are not wind and
solar proposed projects in the entire six-state service
territory; therefore, therers no allegations t.hat
non-wind and solar or small projects are causing any
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CSB REPORTTNG(208) 890-s198
harm.
Mr. Clementsr rebuttal testimony also did not
respond to Renewabl-e Energy Coalition witness testimony,
did not respond to John Lowe's allegatJ-ons and
discussions of the harms that woul-d be caused by
shortening the contract term for small projects or why
smal-l projects are not causing any of these difficul-ties;
therefore, we simply don't believe that Rocky Mountain
Power has submitt.ed evidence to support the breadth of
its recommendation in this proceedj-ng, and we don't at
Ieast as it applies to Rocky Mountain Power, we don't see
their petition as a thoughtfully thought-out proposal to
protect its ratepayers. Instead, it seems to be part of
an overall strategy to reduce its PURPA obligations.
The parent company, Berkshire Hathaway, is
trying to repeal PURPA at the f ederal- l-evel. Pacif iCorp
has proceedings in nearly all of its states that are
either initiated or completed trying to reduce its PURPA
obligations, so we thj-nk the Commi-ssion should consider
this overall strategy of PacifiCorp and Rocky Mountain
Power when looking at the breadth of their proposal.
Now, the Coalition recognizes that there's an
unprecedented and unique circumstance here with all of
the new sol-ar development proposals and we recognize the
Commission may want to take some sort of action in this
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CSB REPORT]NG
(208 ) 890-5198
proceeding. We don't necessarily agree with all of the
recommendations made by the utilities, but we do believe
there is a legitimate issue here.
Our recommendation woul-d be that the Commission
open a generic proceeding to investigate these issues.
The utilities have framed this as proposing only one
potentj-aI solution and there could be other potential
sol-utions that would address things better. One of the
main issues that people have discussed is the question of
need. What do you do when a util-ity doesn't need new
projects? WeI1, shortening the contract term can reduce
the number of projects, but it doesn't reaIIy get at the
heart of the key issue that the utilities keep bringing
up, so we woul-d reconimend that you open a proceeding up
and l-ook at these issues more broadly and try to think of
different sorts of solutions, weigh them, and then decide
which soluti-on best meets the probl-ems that the utilities
are facing.
If the Commission is golng to take action based
on the record here, however, we do recommend that any
relief that you guys decide to adopt not apply to small
projects under the rate eligibility cap. Thank you very
much.
COMMISSIONER KJELLANDER: Thank you. Mr.
Richardson.
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MR. RICHARDSON: Mr. Chairman, thank you.
Commissioner Kjellander, Commissioner Raper, appreciate
your patience and indulgence in hearing us out today and
yesterday. I'm handing out a page from Rocky Mountain's
petltion in this matter, page 20, just for ease of
reference so you don't have to dig it out, and as they
Sdy, a picture is worth a thousand words, and I think
this graph on Rocky Mountain's page 20 of its petition
speaks very loudly. It shows all the potential- projects
that Rocky Mountain is facing in its different
j urisdictions .
Of course, Callfornj-a is bl-ank because it's
under an RTO and the must-buy provisions of PURPA do not
apply in Cal-ifornia. A11 the other jurisdictions that
Rocky Mountaj-n operates in have potential projects,
except for notably one and that's the State of
Washington, zero wind, zero solar, zero other, zero
total-, and we know Rocky Mountain operates in Washington
State and Washington State has a tariff, Exhibit 209. It
shows that QFs get paid capacity and energy, but no QF
has been successful in Washington State, and whatrs the
controlling factor there is they have a fi-ve-year
contract, So I think the evidence is pretty cfear that if
you go to a five-year contract, you are going to kiII the
QF industry in the State of ldaho, and you need l-ook no
CSB REPORT]NG(208) 890-s198
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CSB REPORTING
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further than the State of Washington and thej-r
implementation of PURPA.
Clearwater Paper Corporation is Avista's
Iargest customer and we appreciate our rel-atj-onship with
Avlsta and value it very highly, but we're also kind of
l-ike the largest credj-tor or bank. We need the bank to
be healthy and we need the creditor to be healthy. It's
a symbiotic relationship. We are dealing after all with
state sanctioned monopolies. Itrs i11ega1 for Clearwater
Paper to try to buy power f rom someone el-se. Werre abl-e
to cogenerate and sel-l- our power to Avista under PURPA
and we're al-so currently selling our power to Avista
under a non-PURPA agreement, but Clearwater Paper wants
to preserve its options to be able to sel-l under PURPA to
Avista, to Idaho Power, to PacifiCorp.
Cl-earwater Paper Corporation operates in a
competitive market for al-l- of its products that it buys
and that it sel-Is, except for electricity, and we think
it's clear now that the dust has settled that there is no
imminent or even distant threat to Idaho Power or Rocky
Mountain Power or to Avista of being overrun with
unchecked solar or wind projects.
The IRP methodology for setting avoided cost
rates has actually proven to be resilient and sends
appropriate price signals. As Staff witness Sterling
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noted on the stand today, this morning, the price is the
k"y, not the contract length, and the IRP can even be
made more resil-ient by updating it for to account for
all- QFs in the queue, and this woul-d more appropriately
send the correct prlce signals during large j-nfluxes of
new QFs.
I also think the compromi-ses offered by
Dr. Reading on behal-f of J.R. Simplot Company and the
Clearwater Paper Corporation were very reasonable and I
would ask the Commissioners to seriously consider
adoptlng them instead of dropping the contract term.
Dr. Reading proposed a fixed 20-year capacity term with
an update to the energy component after 10 years. This
aIl-ows the QF to be compensated for avoided capacity,
while at the same tlme it addresses some of the concerns
raised by the util-ities on the probl-em that brought us
here.
If you are convinced that you need to take
action, you should focus only on the alleged culprit,
which is the variabfe and intermittent sofar and wind
projects, So reduce their contract term if you must, but
please take cogeneration out of the crossfire between the
utilities and the sofar project developers, and I don't
really need to point it out, but cogeneration, in
addition to being a hiqhly efflcient way of producing
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electricity, actually makes Clearwater Paper
Corporation's products it makes more valuable and more
profitable and, hence, makes it a more stable and
economic, efficient driver in north Idaho's economy, so
thank you for your consideratlon and I'd be happy to
respond to any questions you may have.
COMMISSIONER KJELLANDER: Thank you. I don't
think we are going to wander into questioning, but we do
sure appreclate that. While we've got the microphone
next to Mr. Adams, why don't we 1et Mr. Adams provide us
comments.
MR. ADAMS: Thank you, Chairman Kjellander.
The J.R. Simplot Company, of course, agrees with Mr.
Richardson's comments and I won't go j-nto great detail
repeating that. I just want to hlghlight some additional
points that we are concerned that based on the evj-dence
that has been presented in the case was either initially
overstated or has proven to become overstated with regard
to the solar contract requests, and then second, I was
going to briefly discuss our position that the util-ities'
proposals and the Staff's proposal, aIso, for two-,
three-, and five-year contract lengths would be
inconsistent with FERC's PURPA regulations.
First, ds to the statement in the case, Idaho
Power filed this case because it had 461 megawatts of
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CSB REPORTING(208) 890-s198
PURPA contracts, sol-ar contracts, executed and approved
to be online in 2076 and an additional 885 megawatts of
PURPA sol-ar capacity in the queue that they stated were
actively seeki-ng PURPA energy sal-es agreements. Yet,
it's undisputed there's no solar QFs online right now,
and since that time the C1ark Sol-ar 1 through 4 contracts
have been terminated, and Idaho Power's overal-l solar
contract total- is down to 320 megawatts between Idaho and
Oregon currently.
Additiona1ly, as Mr. Richardson mentioned, the
IRP methodology is sending significantly lower prices to
new projects that come along in the queue, and the reason
for that is that the point at which the QFs are getting
compensated for capacity has been pushed out in the
calcul-atj-on because of the higher-queued QEs, which we
belleve the design of that was to address the issue of
building capacity on the system when it's not needed, and
the QFs are simply not going to be compensated for
capacity until it's projected that the utility will need
additional capacity.
Another fact for the Commission's consideration
is that the federal tax credits for sol-ar power are going
to be reduced significantly in 2016, further reducing the
ability of these prospective solar contracts to be
developed. We're concerned that ldaho Power's request
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for relief woul-d affect al-l resource types and undermine
longstanding Commissj-on policy providing the opportunity
for QFs that are economically viable and can seII
electricity at the avoided costs, so we ask that the
Commission take a step back and conslder those facts in
the record at this point before addressing the question
of whether the contract term should be shortened to two,
three r ox five years.
And moving on to the second pointr we do
believe that doi-ng that woul-d be inconsistent with FERC' s
regulations under the facts of this case. The utilities
and the St.aff have suggested that there is no 1imit,
there's no lower limit to the length of a fixed rate
contract under FERCTs regulations. We do disagree with
that. The critical- regulation here is 18 CFR
292.304 (d) (2 ) subpart 2. That's the legally enforceabl-e
obligation rule and f'm not going to read it into the
record, but if you read that regulation on its face, it
establ-ishes a few important points.
One is that the QF has the option to sell
energy. The QF also has the option to choose to sel1
excuse me, the QF has the option to sell- energy or
capacity and that the option to sel-l- the capacity is
critical- in this case. The QF also has the option to
choose to sell that capacity over a specified term, and
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CSB REPORTING
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the QF also has the option to have the rates calculated
prior to delivery at the time of creatj-on of that legally
enforceabl-e obligation.
Order No. 69 which implemented this regulation
explai-ns "Use of the term 1ega11y enforceable obligation
is intended to prevent a utility from circumventing the
requirement that provides capacity credit to the QF, " and
we believe that the fundamental flaw of the proposals for
two-, three-, and five-year maximum contract terms is
that the QE would not be able to enter into an
arrangement where it would be compensated for capacity
and be able to displace capacity on the utility's system.
J.R. Simplot Company and Clearwater Paper have
provided several alternative proposafs if the Commission
is concerned that Mr. Richardson discussed, but we don't
believe it would be appropriate or legal to simply
shorten the contract term to a length that appears to be
desi-gned to frustrate development of QFs, particularly
cogeneration projects. Thank you.
COMMISSIONER KJELLANDER: Thank you.
Mr. Arkoosh.
MR. ARKOOSH: Thank you, Mr. Chairman, Madam
Commissioner. I represent the canal companies and our
interest is in not shortening the contracts for published
rates, and two of the util-ities here, Idaho Power and
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CSB REPORT]NG(208) 890-s198
Avista, and the Staff all- agree thatrs not appropriate at
this time. Rocky Mountain, on the other hand, has
maintained their position that those contracts should be
shortened and that's against the background of PURPA as
set forth in the Mississippi case in the Supreme Court.
It has two significant purposes. One is to incentivize
the use of renewable resources and the other is to
overcome traditional- utility reluctance to purchase
privately-produced power.
The question of whether or not it incentivj-zes
use really does address the contract term, because I
think your record is fairly clear that two-, three-, and
five-year contracts wonrt be successful-. As counsel has
just pointed out, the way j-t's currently structured, it
would prevent the selling of capacity, but the customers'
concerns here, that is, whether the util-ities must buy
more power than they need on a must-buy federal program
or whether they maintain consumer indifference in the
avoided cost is realIy not addressed by this proceeding.
I think that those are concerns that have to be
addressed through the setting of avoided costs and what
power is displaced if you have a must-buy federal program
and ultimately might have too much power, so it just
Ieaves us with the question of incentive, and that's
what's being affected by this shortened proposal, this
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shortened contract proposal.
Rocky Mountain Power at page 10 of Mr.
Clements' rebuttal testimony set out their reasons for
shortening the contract term to l-ess than 20 years, and
as I discussed with him on cross-examination, itrs
because in hls opinion it wou1d expose customers to an
unreasonable price risk, and as I've indicated, this is
not a pricing this is not an avoided cost setting
hearing. This is a contract hearlng which doesn't really
go to customer indifference. It goes to the
incentivization of the development of the industry.
The three reasons given at page 10 why he
believed that 1t was an unnecessary long-term, fixed
price risk were first, it exceeds the Company's current
hedging policies and practices, and I woul-d point out
that the Company's hedging policies and practices where
it hedges its energy on the market is not part of the
federal mandate. It's not part of the program. It's not
even a part of the development of the avoided cost or not
a very significant part.
The second reason is that Rocky Mountain Power
feel-s that 20-year contracts are not consistent with the
Company's long-term planning approach, and that goes both
to incentj-ve and traditional utility reluctance not to
purchase, but, again, it is not part of the federal
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mandate. It's not a federal reason. It's not a part of
PURPA, and the final- reason is that the long-term
contracts are not consistent with the Company's REP-based
approach to obtaining long-term power, and, again, that
goes directly to traditional utility reluctance.
That is one of the reasons PURPA was passed.
If util-ities choose to develop capaclty using other than
these renewable resources, then the Commission is
directed to be sure that there is an incentive not to
fuIfill their needs that wdy, but llterall-y to give a
preference to PURPA projects, so all three of the reasons
are not part of the federal mandate, and I would suggest
that al-l- three of the only reasons given on this record
for expanding published as opposed to IRP avoided cost
rates are not reasons that are consistent with PURPA.
Thank you very much.
COMMISSIONER KJELLANDER: Thank you. Mr.
Otto.
MR. OTTO: The Conservation League and the
Sierra Cl-ub believe the Commission shoul-d maintain the
2O-year contract. At the same time, you should adopt our
proposal on pages 7 and 8 of Mr. Beach's rebuttal
testimony to include an adjustment to the energy
component at the midpoint of the contract. This is quite
slmil-ar to the proposal- of Mr. Reading representing
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Simplot and Clearwater.
There have been many references to other paths,
paths other than PURPA, that could lead to development of
renewables, and while that may be true, PURPA remains the
law of the land, and the Commission has an obligation to
implement PURPA 1n a way that complies with that federa1
law.
A structure of a long-term contract that
enables a QF to have a reasonable chance at fj-nancing,
allows the QF to operate long enough to avoid the need
for utility-buiIt capacity, and all-ows a true-up of the
energy component to protect ratepayers is the proper
bal-ance required by PURPA. That bal-ance is to encourage
QE development while ensuring ratepayers are indifferent
to price.
As the Commission decided in Order 32697 and
confirmed recently in 33159 and Mr. Kalich testified to,
the IRP method is well, he said it's working. The
Order said the methodology compares the generation
profile of a QF to the utility's need for resources. The
Commission should take some pride that they've developed
a robust avoided cost methodology that 1s sensitive to
need and does reflect the utility's avoided hourly costs.
The core of this case, the utilities' position
in this case and backed by Staff is a claim that they're
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being f1ooded with QF contracts and have no need for
additional power. I encourage the Commission to look at
these facts before accepti-ng this assertion. The fact is
the utilities are faced with a lot of inquiries, but
a]most no actual contracts at this time.
The claim utillties donrt need additional-
resources is not as simple as they'd have you believe.
Idahoans need capacity when utilities are capacity
deficient, and under the current model, QFs are only paid
at that date. That date comes from the IRP process with
public participation and the Commission has the final,
say.
Ms. Grow confirmed with me that Idahoans need
energy every minute of every day, and the Commission has
found that the energy component of the avoi-ded cost
focuses on that highest displaceable j-ncremental avoided
cost being incurred in each hour, and as Mr. Dickman
testifies on page 2 of his testimony, his direct, this
means the generation from Company-owned resources or
displaceabl-e power purchases. In sum, ratepayers win
when the resources deliver the l-east expensive power in
each hour and that's exactly what the avoided cost model
is doing.
Mr. Sterling and some of the util-ities claim
it's not posslbl-e to accurately predict avoided costs
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over 20 years, but that's exactly what happens when you
approve long-term power purchase agreements with fixed
contracts, something that was confirmed to benefit
ratepayers. Long-term predictions are al-so what supports
putting a utility-buiIt resource into rate base. WhiIe
the fuel costs may be updated in the power cost
adjustment, the capital costs and the fixed O&M costs are
not. They're in it for the l-ife of the project never to
be trued up again if that resource decision looking
backwards maybe wasn't the right one.
Mr. Beach's testimony also contains two more
benefits that come from these long-term, fixed prj-ce
contracts. They can be a hedge against volatility and
they can reduce market prices. This hedge is an al-l--in
price. A QF contracL, that's the total- price that
customers are going to have to pay for that power. It
cannot be fairly compared to just the fuel- price that is
the current hedging practice, and as far as market price
suppression, we see the util-ities and their IRPs moving
more towards market purchases and as we do so, the
Commission should take efforts to keep market prices 1ow,
not keep market prices high to support off-system sa1es.
So as I mentioned, the avoided cost and the IRP
methodology and the QF contracts, there is a rigorous
public process to all of these efforts. The methodology
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came from a fu1ly contested case that we al-l remember
well. The capacity date comes from the IRP, again, a
public process with Commissj-on approval. That same
process produces the basic inputs to the energy costs.
Both the energy and the capacity lnputs are updated
annually. A11 of these are public processes with the
Commission approval. This j-s robust. While it may be
different than a util-ity-built resource, it still has a
1ayer, many layers, of public participation, review, and
annual- assurances that these are accurate.
As Mr. Clements testifies, the Commission does
have a 1ot of discretion to implement any contract
length. Importantly, that discretion or those actions
have to be consistent with the EERC regulations, and the
key as Mr. Wenner explained, you have to look at the
regulations in the context of the statute as a whol-e, and
that was his recommendation and I think that's my
recommendation, too, as an Idaho attorney, I'Il- say that.
You shou1d interpret a statute in the context of its
entire purpose and need and structure as recently
confirmed by the Supreme Court.
A contract length and structure that enables a
QF a reasonabfe access to financing while paying only the
utility's actual avoided cost for energy and paying for
capacity only when a utility identifies need, that's
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consistent with FERC regulations, so if the Commission
wishes to provide the utilities the opportunity to
true-up those energy costs over a long-term contract,
again, I urge you to support our proposal as laid out in
Mr. Beach's rebutta1 testimony. That's the correct
balance the Commission should reach. You're encouraging
QF development whil-e protecting ratepayers over the long
term. Thank you.
COMMISSIONER KJELLANDER: Thank you. Mr.
Hammond.
MR. HAMMOND: I just have a few comments. I've
heard a lot of points made that I would agree with. In
terms of our client Ecoplexus, the concern obviously is
having the Commission develop a program out of this
docket that meets or helps comply with federal law. Now,
maybe in Idaho we hate the federal- government telling us
what to do. There always seem to be that undercurrent in
much of our relationships sometj-mes with the federal-
government; however, PURPA is the law and the Commissj-on
has some important decisions to make regarding how to
comply with those obligations, and I believe the
testimony in this record has demonstrated or provided the
ability for this Commission to use its discretion to use
something other than simply shortening the length of
contract.
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I think shortening the length of contract in
the manner in which the utilities have proposed is a
hammer meant to kill PURPA development altogether. I
think the record or the history of PURPA development in
this state demonstrates at l-east to some extent
shortening that contract term will al-] but eliminate, or
almost el-imj-nate, any PURPA development. I don't think
the Commission wants to eliminate PURPA development. I
think the Commission wants to find that pathway to find
reasonabl-e good development that makes sense for the
State of ]daho.
f bel-ieve based on the record there are means
by which we can do that, either through the current
methodol-ogy or adopting modifications to it to adjust
pricer ds has been addressed by several- of the closing
arguments, to adjust price over the term of the contract
if there is a need to have it more closely match what is
going on. That in and of itself or those changes could
help to regulate the amount of power that comes online
that would address some of the concerns the util-ities
have, while at the same time helping the Commisslon
support or meet its obligations, potential obligations,
to encourage the development of PURPA power in the State
of fdaho.
With that I'd leave it to your discretion.
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Thank you very much for the opportunity werve had to
address these issues before you.
COMMISSIONER KJELLANDER: Thank you, Mr.
Hammond. How about Staff for the Public Util-ities
Commission?
MS. HUANG: Thank you, Mr. Chairman. On behalf
of Commission Staff, my closing wil-l- address the l-imited
issue of the Commission's authority to address the length
of PURPA contracts in response to the legal analysis in
Mr. Wenner's testimony and also arguments made today by
Mr. Adams and Mr. Otto and others.
I woul-d agree with Mr. Schmidt's closing
statements on this issue. Nothing in PURPA Section 210
or in FERC's PURPA regulations refer to, l-et alone Iimit,
the ability of this Commission to establ-ish a standard QE
contract duration that it deems appropriate.
In FERC's policy statement regarding its
enforcement role under Section 210 of PURPA at 23 FERC
6L,304, FERC provided that its regulations all-ow the
states "a wide degree of l-atitude in establi-shing an
implementation p1an. Such l-atitude is necessary in order
for implementation to accommodate local- conditions and
concerns so long as the final plan is consistent with
statutory requirements, " and indeed as noted by more than
one expert in these proceedings, as wel-l- as counsel for
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various parties present today, other state commissions
throughout the West, including Washj-ngton and this
Commission here in ldaho, have set different contract
lengths to accommodate the l-ocal conditions and concerns.
In fact, Mr. Wenner did concede in his direct
testi-mony at page 5, l1ne J , that nothing in the EERC
rules specifies a specific number of years for contract
terms. Contrary to Mr. Wenner's claim, FERC has not
characterized QEs as having the right to a long-term
contract. The language that Mr. Wenner quotes at page 5,
Iine 22, to page 6,line 13, in his direct testimony,
he' s quot j-ng f rom FERC' s Order 59 , which was also
referenced by Mr. Adams, I bel-ieve, that quote on j-ts
face fail-s to support the supposition that there is a
right to a long-term contract.
In fact, on the fol-l-owing page in FERCTs Order
69, FERC states that it shoul-d l-eave to the states
flexibility for experimentation and accommodation of
special circumstances with regard to implementation of
rates for purchases. This, again, highlights that the
states be given wide latitude on these matters.
Further, Mr. Wenner's assertion that the Idaho
Supreme Court has also found a right to long-term
contracts in the CERs is equally far-fetched. Neither
the quoted language that Mr. Wenner provides nor any
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CSB REPORTING(208) 890-s198
other language in that Afton Idaho Supreme Court decisj-on
supports his argument, and he has hi-s quote in his direct
testimony at page 6, l-ines 5 through 13.
The quote that he cites from the Afton decision
is actually on page 785 rather than 186 as he cites. ft
is found in Footnote 1 of that decision. The Afton
decision at Footnote B also includes the Court's comments
that the level of QF payments varies depending on the
length of the contract, and also the Commission's
ratemaking authority is intricately rel-ated to its
ability to define the term of the obligation, so in sum,
there is no 1ega1 authority that legitimately supports
the argument made by Mr. Wenner that this Commission
l-acks the ability to establish the length of PURPA
contracts in Idaho in keeping with its duty to ensure
rel-iable service and just and reasonable rates in the
public interest.
As supported by Mr. Sterling's testimony today
regardi-ng the capacity arguments that have been made, Lf
a QF provides capacity, then a utility must pay for it,
but there is no requirement that a QF be entitled to
provide capacity and be paid for it.
The Commission's authority to establish
contract Iength 1s consistent with FERC Order 69 and
Idaho Supreme Court decisions, and for those reasons, the
1015 coLLoQUY
Commissj-on Staff respectfully requests that you find that
you do have jurisdiction and authority to set the
contract length in these proceedings.
COMMISSIONER KJELLANDER: Thank you. Letrs
move to Avlsta.
MR. ANDREA: Thank you, Mr. Chairman. At the
outset, I do want to thank the Commission for its time
and consideration in this proceeding, recognj-zing that
the testimony has been long and it's sometimes not as
exciting as other things we may be doing, so appreciate
your attention and consideration.
Certain intervenors have attempted to read a
long-term contract requirement into FERC's PURPA
requirements and regulations. As Staff has just
presented and Avista agrees, there is no such requirement
and the attempt to read that in is misl-eading. The truth
of the matter is that FERC has left it to the states to
implement PURPA and has provided the states broad
discretion in the way that they do that, and that
discretion lncl-udes setting of the contract term.
The Fifth Circuit in fact has recently
recognized in the Exelon Wind 1 decision that the state
PUC, 1n that case the Texas PUC, had the broad discretion
to set the contract term to no long-term contract for
resources that cou1d not provide the reliable,
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CSB REPORTING
(208 ) 890-5198
predictable power. That demonstrates that at least one
federal court of appeals has recognized the states broad
discretion to set the term.
Final1y, I note that some have attempted to
point out that Avista does not have the vol-ume of PURPA
contracts that are currentfy being experienced by Idaho
Power and PacifiCorp. That really is irrelevant here.
Irrespective of how many megawatts of solar are or will
be on1ine at any of the utilities, this case has
demonstrated that no QF projects should be eligible for
long-term contracts due to price risks that are borne by
customers. Just because there's no flood does not mean
it is okay to pay too much even for a few contracts.
The arguments that have been presented in thls
regard are asking the Commission to walt until- the horse
has left the barn before shuttlng the door. The
utilities' customers will- be harmed by such an approach.
Avista clearly has an interest i-n ensuring that any rufes
j-mplementing PURPA adopted by this Commission are equally
applied to Avista to ensure that it does not become a
magnet for PURPA projects that would otherwise selI to
another utility.
Avista's interest in this proceeding continues
to be to ensure there's a level playing field between al-I
of the utilitj-es and that the terms that are required for
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CSB REPORTING(208) 890-s198
any one utility are applied equally to all of the
util-ities regulated by this Commission. Again, I thank
you for your tlme and consideration, and that concl-udes
my remarks.
COMMISSIONER KJELLANDER: Thank you. Let's
move to Rocky Mountain Power/PacifiCorp.
MS. HOGLE: On behal-f of Rocky Mountain Power
and its customers, we appreciated the opportunity to
present our case here to you today. I mentioned our
customers because the utility will not benefit nor it
will be harmed from the decision that you make in this
case. As Mr. Schmidt stated in his closing statement, we
pass through 100 percent of the costs to QFs, of the
Company costs from the payments that we make to QFs for
their power.
We bel-ieve that through our application, direct
and rebuttal testimony, and live testimony presented
through the course of two days we have met our burden.
Mr. Clements testified that leaving the PURPA contract
term at 20 years would viol-ate the ratepayer indifference
standard under Section 2L0 of PURPA, and that cutting it
to two, three, or five years viol-ates no provision under
PURPA.
Contrary to what Mr. Adams stated in his
closing, two-, three-, or five-year PURPA contracts can
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include capaclty payments. To the extent that a QF helps
the Company or the utility reduce firm power purchases
from another utility, then the rate for such a purchase
wiII be based on the avoided capacity and energy costs,
and thatrs from FERC Order 69 which has been quoted
extensively here today and yesterday, 45 Fed. Reg. L22L4
and page 122L6, February 25th, 1980. That's the specific
quote.
Rocky Mountain Power submlts that the
incentives to encourage the development of alternative
resources are buil-t into PURPA and inc]ude the
must-purchase obligation under Section 210 and in FERC
Regs part E, which is the exemption of QEs from the
Eederal Power Act and many state laws and regul-ations to
which util-ities are subject. The price and the term of
the contract are neutral and not 1n and of themselves
incentives.
Based on the foregoing, Rocky Mountain Power
respectfully requests that you grant our petition for a
permanent reductj-on of maximum contract terms of PURPA
contracts to three years and modification to the
Company's avoided cost methodol-ogy as set forth in our
appJ-ication and our testimony. Thank you very much.
COMMISSIONER KJELLANDER: Thank you. Let's
move to Idaho Power.
CSB REPORTING
(208 ) 890-s198
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MR. WALKER: Thank you, Mr. Chairman and
Commissioner Raper, and I too wish to thank you for the
opportunity here to make a closing and during this
hearing and for bringing this matter to a fairly rapid
hearing and concl-usion and ultimately your decision, and
f'd l-ike to say up front that these are contentious
matters among the parties and certainly, I'm passionate
about representing the Company and its customers.
Hopefully, none of the contentiousness certainly was
meant with no disrespect to this Commission, flo
disrespect to Dr. Reading, Mr. Mill-er or Mr. Richardson
or any of the other parties here, but these are serious
matters and understand that we're passionate about our
positions.
Now, a good place to start, I think, is always
why are we here, why are we doing this and, you know,
this case is this case is not about fossil fuels or
the retirement of coal plants or CO2 emissions or other
external-ities of environmentalism. What this case is
about is the mandatory purchase requirement and
obligation of PURPA and the just and reasonabl-e terms and
conditions of that mandatory purchase for the State of
Idaho established by this Commission under its proper and
lawful authority.
Now, PURPA requires the util-1ties to purchase
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CSB REPORT]NG(208) 890-s198
It does not require the utility and its customers to
provide risk-free financing to QFs. It requires the
customers be held neutral and be held harmless in such
transactions. None of the parties opposlng the requested
reduction in maxj-mum contract term here have rea1ly
addressed the larger issues related to need for
additional- generation resources and the disproportionate
amount of risk that long-term, fixed rate, unchangeable
QF contracts place upon Idaho Power's customers without
the beneflt of this Commission's or the public's scrutiny
of their acquisition of which the Company's own the
Company-owned resources must endure.
Now, the State of Idaho, in the State of ldaho,
we have a chosen authorized and constitutional- system of
regulati-on that's designed to protect the interests of
the citizens of the State of Idaho and to allow for
companies like Idaho Power to reliably provide a vital
service to the public. This is a system that has
us aII very wel-I since the time of Idaho Power &
versus Blomquist in 7974. This is a system that'
enab1ed us to today to continue to enjoy some of
l-owest electricity prices, retail prices, in the
Now, the continued creation of 2)-year
contracts places an undue risk on customers at a
when Idaho Power has sufficient resources to meet
served
Light
S
the
nation.
term
time
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CSB REPORTING
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customer needs. The Company's required lntegrated
resource planning process is filed and updated every two
years. Non-PURPA purchase and sales transactions are
limited to l-ess than two years pursuant to the Company's
approved risk management hedging po11cy, and avoided cost
rates themsel-ves are updated at l-east every year, and
consequently, Idaho Power requests that the required term
for any prospective PURPA energy sal-es agreements above
the published rate eligibility cap also coincide with
that two-year time period.
Now, to also take some notice of very recent
U.S. Supreme Court decisions, the parties here would have
us ignore the substantial risks associated with 21-year,
fixed rate contracts without ful1 evaluation of the cost
impact to society and to Idaho Power's customers.
of tal-k about what's in the record, we1l, here's
A lot
something that's in the record, $2.7 bil-lion, that's the
estimated obligation for over 1,300 megawatts of proposed
QF sol-ar projects
$1.2 bil
320 megawatts that
construction in 20
the obligation of
on Idaho Power's system.
lion, that's the estimated cost of the
are currently under contract for
16; and finally, $2.6 billion, that is
the existing 781- megawatts that are
currently constructed and operating on fdaho Power's
system. That's and yes, that'a total- possibl-e
7022 COLLOQUY
impact to customers of over $6 bi]Iion, and is that real-?
You bet it' s real-.
I believe this Commission is very familiar with
concepts of 1ega11y enforceable obligations and many of
the projects on that very list currentl-y seek legally
enforceable obligations and yet come in here and say
well, never mind, we're really not going to develop, that
doesn't have a chance, but oh, by the w&y, we al-l want
legaIly enforceable obligations for rates in place at the
time we're making these requests. You can't have it both
ways.
What efse do we know about that list? Well-, w€
know that nobody has dropped off of that list of proposed
projects from the time we filed until- today, and in fact,
that l-ist hqs grown even during the pendency of this
case. It was BB5 megawatts in January, today it's over
1,300.
There's also been discussion of Section
292.304, Order No. 69, and selected portions of FERC
direction with regard to an LEO and let's l-ook at that
section briefly. What does it require? Well it gives us
guidance on what pricing is available to a QE. lt can be
priced for a term or it can be pri-ced at the time of
delivery. Order No. 69 in its discussion about an LEO, I
think it's very cl-ear that FERC's direction there with
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CSB REPORTING
(208 ) B 90-s198
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CSB REPORTING(208) 890-s198
regard to an LEO was meant to address situations when a
utility is refusing to contract with a QF. It was not
meant as a guarantee to get capacity payments no matter
what and certainly not when the utility is in a capacity
suf f icient pos j-tion.
Now, and f rm almost done, f promise, so we
really don't need a l-ot of fancy calculations or complex
analysis here to figure out that anything paid for
something that is not needed is too much and it's
potentially harmful to customers. The required term of a
mandatory QF purchase is within the authority and
dj-scretion of this Commission to determine and set, and
in fact, the Commission has modified the required
contract term for PURPA purchases as discussed several
times in the past, including previous terms limited to
five years.
Idaho Power currently undisputably has no
identifiabl-e need to acquj-re any additional generation
resources potentially for the next 10 years, and
additionally, the planned Boardman to Hemingway
transmission line would serve additional- growth beyond
that without adding any new power plants. The
acquisition of Company-owned resources, generation
resources, as well as the Company's purchase and sale of
non-PURPA generation is either limited to terms less than
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(208 ) 890-s198
two years or it's subject to very j-ntensive Commission
and public participation, scrutiny process, and
proceedings to all determine that the Company is acting
prudently, in the public interest, fulfilling a need in
the l-east cost and most reliable manner possible.
Now, all of these requirements, particularly
that of establishing need for the resource, are absent in
the mandatory PURPA QF purchase, and the further
constraint imposed by PURPA that eliminates contract
reopeners or any ability to modify or change those prices
that are locked into the contracts regardless, in FERC's
own words regardl-ess, of whether aI1 costs were included
at the time or regardless of whether those costs varied
from the actual costs and conditions as they may have
changed or varied over the duration of that contract.
That makes long-term contracts, you know, dt
best a risky proposition and here damaging and harmful- to
customers, and further, with all the uncertainties, I
think everybody in the case talked about many of the
uncertainties into the future that all can impact the
costs to customers, can affect the rate. With that
uncertainty, it really is unreasonable to contj-nue to
requlre our customers to shoul-der all- of that risk, and
Idaho Power asks that the Commission reduce the maximum
term as we've requested.
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COMMISSIONER KJELLANDER: Thank you. I bel-ieve
we got aII the parties. Did I miss anyone? Okay, a
couple of procedural items. AlI the exhibits that have
been marked and identified to these proceedings wilI now
be admitted.
(A11 exhibits previously marked for
identification were admitted into the record. )
COMMISSIONER KJELLANDER: I believe that I
mentioned earl-ier 1n the proceedings that itrs our lntent
to have the requests for intervenor funding in very near
term and so I'm going to plck a 10-day window, which
woul-d be Eriday, July 1Oth, so hopefully, that's an easy
date to remember, and we'd l-ike to see those requests for
intervenor funding in as soon as we can so that we can
proceed quickly towards our del-iberative process.
As a reminder, this evening we have a
telephonic hearing that begins at 7:00, and so while
you're out enjoying the wonderful, Iovely weather in
Boise, we'II be in here wishing that we were here because
it's not as bad as outside. That said, is there anything
else that needs to come before the Commission? If not,
this component of our proceedings is complete. We
appreciate your willingness and desj-re to help us develop
the record and, again, we l-ook forward to getting out a
timely Order once we have al-l of the matters in front of
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us for appropriate deliberations and with that, thank you
and we'11 see you a1I soon, hopefully, in another case.
(The hearing recessed at 72230 p.m. )
CSB REPORTING(208) 890-5198
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