20150715Hearing Transcript Volume III.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
IN THE MATTER OF AVISTA
CORPORATION'S PETITION TO MODIFY
TERMS AND CONDITIONS OF PURPA
PURCHASE AGREEMENTS
IN THE MATTER OF ROCKY MOUNTAIN
POWER COMPANY'S PETITION TO
MODIFY TERMS AND CONDITIONS OF
PURPA PURCHASE AGREEMENTS
BEFORE
CASE NO. IPC-E-15-01
CASE NO. AVU-E-15-01
CASE NO. PAC-E-15-03
COMMISSIONER PAUL KJELLANDER (Presiding)
COMMISSIONER KRISTINE RAPER
c; ....., -1 = C- c.n
-tC c., iii . c:: r- PLACE: Commission Hearing Room en ..,J c» c.n 472 West Washington Street 0
Boise, Idaho :ca ::::
(., a
.(:" DATE: June 29, 2015 N
VOLUME III - Pages 284 - 761
ORIGINAL CSB REPORTING
Certified Shorthand Reporters
Post Office Box 9774
Boise, Idaho 83 707
[e-mail]
Ph: 208-890-5198 Fax: [phone]
Reporter:
Constance Bucy,
CSR
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For the Staff:
A P P E A R A N C E S
Donald Bowell, Esq.
and Daphne Huang, Esq.
Deputy Attorneys General
472 West Washington Street
Boise, Idaho 83720-0074
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For Idaho Power Company: Donovan E. Wal.ker, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
For Rocky Mountain Power: Yvonne R. Bogle, Esq.
9 Rocky Mountain Power
201 S. Main Street, Ste. 2400
10 Salt Lake City, Utah 84111
11 For Avista Corporation: Michael Andrea, Esq.
Avista Corporation
12 Post Office Box 3727
Spokane Washington 99220
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For Clearwater Paper:
For Intermountain Energy
Partners:
For Idaho Irrigation
Pumpers:
CSB REPORTING
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RICHARDSON ADAMS PLLC
by Peter J. Richardson, Esq.
515 North 27th Street
Boise, Idaho 83702
McDEVITT & MILLER
by Dean J. Miller, Esq.
420 West Bannock Street
Boise, Idaho 83702
Boise, Idaho
RACINE OLSON NYE BUDGE
& BAILEY
by Eric L. Olsen, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
APPEARANCES
For J.R. Simplot Company: RICHARDSON ADAMS PLLC
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APPEARANCES (Continued)
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For Idaho Conservation
League & Sierra Club:
For Snake River
Alliance:
For Renewable Energy
Coalition:
(Of Record)
For Snake River
Alliance:
For Micron Corportion:
Northside and Twin Falls
Canal Companies:
For Ecoplexus:
CSB REPORTING
[phone]
Benjamin J. Otto, Esq.
Idaho Conservation League
710 North 6th Street
Boise, Idaho 83702
Kelsey Jae Nunez, Esq.
Snake River Alliance
Post Office Box 1731
Boise, Idaho 83701
Williams Bradbury PC
by Ronald L. Williams, Esq.
1015 West Hays Street
Boise, Idaho 83702
-and­
SANGER LAW PC
by Irion Sanger, Esq.
1117 SW 53rd Avenue
Portland, Oregon 97215
Kelsey Jae Nunez, Esq.
Snake River Alliance
Post Office Box 1731
Boise, Idaho 83701
HOLLAND & HART LLP
by Pamela S. Bowland, Esq.
377 S. Nevada Street
Carson City, Nevada 89703
ARKOOSH LAW OFFICES
by C. Tom Arkoosh, Esq.
Post Office Box 2900
Boise, Idaho 83701
FISHER PUSCH LLP
by John R. Hammond, Jr., Esq.
Post Office Box 1308
Boise, Idaho 83701
APPEARANCES
1 I N D E X
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3 WITNESS EXAMINATION BY PAGE
4 Randy Allphin Mr. Hammond (Cross) 284
(Idaho Power) Mr Howell (Cross) 294
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Anthony J. Yankel Mr. Olsen (Direct) 297
6 (Irrigators) Prefiled Direct Testimony 299
Mr. Miller (Cross) 341
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John R. Lowe Mr. Sanger (Direct) 343
8 (REC) Prefiled Direct Testimony 345
Mr. Walker (Cross) 362
9 Commissioner Raper 365
10 Mark Van Gulik Mr. Miller (Direct) 368
( IEP) Prefiled Direct Testimony 370
11 Mr. Walker (Cross) 389
Mr. Olsen (Cross) 391
12 Mr. Miller (Redirect) 397
13 Clint Kalich Mr. Andrea (Direct) 400
(Avista) Prefiled Direct Testimony 402
14 Prefiled Rebuttal Testimony 408
Mr. Richardson (Cross) 414
15 Mr. Otto (Cross) 417
Mr. Sanger (Cross) 418
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Paul H. Clements Ms. Hogle (Direct) 420
17 (Rocky Mountain) Prefiled Direct Testimony 423
Prefiled Rebuttal Testimony 4 97
18 Mr. Richardson (Cross) 522
Mr. Otto (Cross) 527
19 Mr. Sanger (Cross) 531
Mr. Hammond (Cross) 534
20 Mr. Arkoosh (Cross) 543
Ms. Hogle (Redirect) 550
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Brian Dickman Ms. Hogle (Direct) 552
22 (Rocky Mountain) Prefiled Direct Testimony 554
Mr. Otto (Cross) 576
23 Mr. Hammond (Cross) 577
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INDEX
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INDEX (Continued)
WITNESS EXAMINATION BY PAGE
Adam Wenner Mr. Otto (Direct) 579
(!CL/SC) Pre filed Direct Testimony 581
Prefiled Rebuttal Testimony 602
Mr. Andres (Cross) 607
Ms. Huang (Cross) 610
Mr. Otto (Redirect) 612
R. Thomas Beach Mr. Otto (Direct) 613
( !CL/SC) Prefiled Direct Testimony 616
Pre filed Rebuttal Testimony 689
Mr. Walker (Cross) 704
Mr. Howell (Cross) 711
Mr. Andrea (Cross) 713
Mr. Otto (Redirect) 723
Ken Miller Ms. Nunez (Direct) 725
(Snake River) Prefiled Direct Testimony 727
Mr. Howell (Cross) 745
Mr. Walker (Cross) 748
Mr. Olsen (Cross) 754
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INDEX
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3 NUMBER
E X H I B I T S
DESCRIPTION PAGE
4 FOR ICL/SIERRA CLUB:
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301. CV for R. Thomas Beach
302. IPCo Responses to Request Nos. 2,
5, 16 & 18
Premarked
Premarked
303. California ISO/NV Energy Energy Premarked
8 Imbalance Market Fact Sheet
9 304. Rocky Mountain Institute, Utility- Premarked
Scale Wind and Natural Gas
10 Volatility
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12 FOR INTERMOUNTAIN ENERGY PARTNERS:
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401. IPCo Schedule 73
402. Energy Sales Agreement Between
IPCo & Clark Solar 1, LLC
FOR ROCKY MOUNTAIN POWER:
601. Pricing queue for PacifiCorp's
system as a whole for PURPA
projects
FOR AVISTA CORPORATION:
1101. Notice of Intent Not to Act and
Declaratory Order
1102. Order Denying "Requests for
Rehearing, Reconsideration or
Clarification"
1103. Exelon Wind 1, LLC v. Nelson
Identified 399
Identified 399
Premarked
Identified 721
Identified 721
Identified 721
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Wilder, Idaho 83676
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BOISE, IDAHO, MONDAY, JUNE 29, 2015, 1:45 P. M.
COMMISSIONER KJELLANDER: With that, then,
we'll go back on the record, and before we broke for
lunch, Mr. Allphin, you were under oath, so you still are
and we were in the process, I believe, of moving on to
Ecoplexus who had indicated they may have some cross.
MR. HAMMOND: Thank you, Chairman Kjellander.
RANDY ALLPHIN,
produced as a witness at the instance of Idaho Power
Company, having been previously duly sworn to tell the
truth, the whole truth, and nothing but the truth, was
examined and testified as follows:
CROSS-EXAMINATION
BY MR. HAMMOND:
Q. Good afternoon, my name is John Hammond. I
work for Fisher Pusch and we represent Ecoplexus.
Although I know you have to be here, thank you for being
here and taking the time to make yourself available.
Were you in the room when Mrs. Grow or Ms.
Grow, excuse me, testified earlier their morning?
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284 ALLPHIN (X)
Idaho Power Company
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A. Yes, I was.
Q. Did you happen to hear her testimony concerning
the Company's review of lll(d) scenarios, possible lll(d)
scenarios?
A. Yes.
Q. And in those scenarios, are you aware what the
Company used as its base case for pounds C02 per
megawatt-hour?
A. No, I'm not involved with that analysis or in
anyway with the interpretation of lll(d).
Q. Do you have any knowledge of whether a PURPA
project, let's say a solar PURPA project, would help or
assist the Company in meeting possible lll(d) standards
that come down?
A. Again, I don't participate or have knowledge of
actually how the lll(d) regulations are transpiring.
Q. The Exhibit 1501, do you have that or is that
up on the stand? I'd like you to turn, if possible --
well, could you identify this document for me just for
the record?
A. It looks like this is a few pages of the draft
2015 integrated resource plan.
Q. Could you turn to -- it's marked page 95 at the
bottom. It's a graph, Figure 7.5.
A. Yes, I've got it.
CSB REPORTING
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285 ALLPHIN (X)
Idaho Power Company
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Q. Did you participate at all in the creation of
this graph?
A. No.
Q. Do you have any knowledge about this graph and
what it entails?
A. My knowledge is what I see here in front of
me.
Q. Could you tell me what that is?
A. It appears to just show various resources and
as the legend says, "30-year levelized capacity (fixed)
costs."
Q. Do you know earlier in the testimony Ms. Grow
testified or acknowledged that there were some issues
concerning the Boardman to Hemingway transmission line,
transmission pathway, there were some uncertainties in
permitting and other issues; are you aware of that?
A. I was here during her testimony.
Q. Do you think those issues or would you have any
knowledge of whether those issues could affect the fixed
cost for Boardman to Hemingway?
A. I would have no knowledge to know whether it
does or not.
Q. So today the Company's position is to move to a
two-year contract; is that correct?
A. Yes, a two-year contract term.
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286 ALLPHIN (X)
Idaho Power Company
Q. But the Commission hasn't found that the risk
a two-year contract term on PURPA contracts.
selected versus five years or ten years?
A. I have -- again, I'm not privileged to the
ALLPHIN (X)
Idaho Power Company
287
Q. Why was -- was there a reason why two years was
A. Again, as stated in our testimony and rebuttal,
the Idaho Power Company IRP process is gone through on a
Q. What do you expect the impact -- if the term is
A. No, that's what we're here today asking for is
forth are updated on an every two-year cycle. The
frequently than a two-year cycle. Idaho Power Company's
published avoided cost and the inputs in the incremental
two-year cycle. All of the inputs, the forecasts, and so
cost model are updated on an annual cycle, even more
so basically the Commission and the Company have found
years, then, is required to receive Commission approval,
transactions no more than a two-year time frame and two
risk management policy allows us to enter into market
point?
that the risk that they wish Idaho Power customers to be
exposed to is two years.
lowered from 20 to two years, what do you expect the
should be two years for PURPA contracts, correct, at this
impact would be on PURPA projects, if you have an
opinion?
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financing or the business models that PURPA projects
used, so I don't know specifically what impact it will
have.
Q. Isn't the term reduction from 20 to two years
in part to eliminate several of -- the ability of PURPA
projects to come online?
A. Absolutely not. The purpose for asking to
change to two years is to eliminate a portion of this
risk that currently under a 20-year contract Idaho Power
Company customers are being asked to bear.
Q. Correct me if I'm wrong if I misstate the date,
but I believe in 1996, 1997, the Commission reduced the
length of contracts, PURPA contracts, from 20 to five
years; is that testimony you heard earlier?
A. Yes.
Q. And did you hear earlier that the impact of
that, or at least part of that impact, was that only one
PURPA contract came online or project came online during
that time period?
A. Yes, I heard that testimony.
Q. Is there any reason to expect that that would
be any different than today?
A. Again, I think as another witness has provided
information in this case, there were a lot of other
things that were also occurring in that previous window
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(208} 890-5198
288 ALLPHIN (X}
Idaho Power Company
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of time. Gas prices were low. Some other events were
happening that it's not known for sure if it was simply
the contract term that caused that reduction in PURPA
contracts.
Q. Isn't one of the reasons the Company is asking
to reduce from 20 to two years is because it doesn't feel
it needs the power?
A. Absolutely. Idaho Power, we do not need the
energy at this point. Our IRP has not identified a need
for energy.
Q. So in the pricing you've heard a discussion
about how each project potentially comes online at a
lower price or lower avoided cost price; is that
correct?
A. Yes, that's how the incremental cost model tool
works.
Q. Could that incremental cost model work to
eliminate projects that aren't feasible?
A. Again, the incremental cost model establishes
the avoided cost that Idaho Power Company is to pay, and
Idaho Power has no information whether or not a
project -- at what price a project is feasible or not
feasible.
Q. Now, my understanding is that 141 megawatts of
projects have dropped out of the queue, I say queue, out
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Idaho Power Company
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of the pool of projects; is that correct?
A. Yes .
Q. Do you have any reason -- what were the reasons
for that?
A. Again, they failed to comply within some
requirements within the contract and caused a material
breach of the contract.
Q. Would you agree that a PURPA project has to
receive at least some sort of sufficient price in order
to satisfy their financing obligations?
A. They have to, yes, absolutely, they have to
receive some price .
Q. So at some point the avoided cost price, the
incremental price, could be low enough that a PURPA
project would not be able to be satisfy its financing
obligations and therefore not become feasible; is that
correct?
A. Yeah, and, again, the avoided cost calculation
has no basis in what it costs a PURPA project to be
developed. The avoided cost is the cost that the Idaho
Power Company avoids and, therefore, again, if the
avoided cost enables a project to be built, so be it,
but, again, we have no knowledge of what that point is .
Q. I believe in PacifiCorp's testimony, it would
be Mr. Clements, and I may be misquoting and actually Mr.
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Idaho Power Company
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Dickman as well, discusses changing how the indicative
pricing is calculated. Have you had a chance to review
their testimonies?
A. Yes, I have.
Q. Would a proposal like that, being able to
change the indicative pricing up front or at least sooner
to the time the contract was in place, help mitigate how
much power came online or how many projects were
proposed? Would that help regulate the number of PURPA
projects that you might see?
A. I guess I don't understand your specific
question.
Q. So the pricing model or the -- PacifiCorp is
proposing changing how the indicative prices are
proposed, is that correct, or calculated?
A. Yes, they appear to be doing so.
Q. Would that -- a change to the pricing, a change
to how prices are calculated, would that help mitigate or
regulate how much PURPA power you might see apply?
A. The proposal, I believe, that they are
recommending is to price projects based upon, in the
indicative pricing model based on, the order in which the
requests are received. As you previously stated, as
additional projects are proposed to Idaho Power Company,
the prices decline for each progressive project. There
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Idaho Power Company
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would be no change in our pricing model.
Q. If the change was granted, PacifiCorp's
request, wouldn't it have the effect of reducing the
prices further?
A. Not for Idaho Power Company, no.
Q. If that change was -- my understanding is that
most of the utilities in this case want sort of the same
treatment, so if one is granted relief in one
circumstance, the other utilities want that relief; am I
wrong?
A. PacifiCorp, I believe, is asking for that
confirmation of executing the pricing model in that
manner. Idaho Power Company is executing the pricing
model in that manner.
Q. Let me ask this question: Has the Commission
considered when the indicative pricing should be
determined? Have they issued an Order, to your
knowledge?
A. There's been various Orders that have directed
how Idaho Power Company is to run the indicative price
model.
Q. In fact, isn't there a Commission Order that
requires that the Company calculate the indicative
pricing at the time the contract is signed?
A. Yes, there's an Order that specifies at the
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Idaho Power Company
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time the contract is signed.
Q. And did you just testify that Idaho Power is
instead determining indicative pricing and providing that
pricing to customers or to PURPA projects prior to the
contracts being signed?
A. Subsequent to that Order, there were 11
projects that Idaho Power Company, 11 projects Idaho
Power Company, executed contracts with. Upon submitting
those contracts to the Public Utilities Commission for
approval, the Public Utilities Commission Staff
communicated to Idaho Power Company that there were some
changes or some improvements to the incremental cost
model that were appropriate. Idaho Power Company re-ran
those prices using those suggested changes, reviewed
those negotiated prices with the developers, and
submitted those back to the Commission for approval.
Those contracts were subsequently approved in those cases
which included that pricing model.
Q. And so that pricing model with that change
would produce lower prices as each subsequent project
A. Yes, as you previously stated in your question.
MR. HAMMOND: I don't think I have anything
further. Thank you.
COMMISSIONER KJELLANDER: Thank you, and I'm
assuming we don't have any cross from Avista or
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293 ALLPHIN (X)
Idaho Power Company
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PacifiCorp?
MR. ANDREA: Avista does not have any cross.
COMMISSIONER KJELLANDER: Thank you, and so
we're ready now for the Deputy Attorney General for the
Idaho Public Utilities Commission Staff.
MR. HOWELL: Thank you, Mr. President. The
Staff only has a couple of questions for Mr. Allphin.
CROSS-EXAMINATION
BY MR. HOWELL:
Q. Good afternoon. If you could turn to your
direct testimony at page 8 and in particular Footnote
No. 1.
A. Yes .
Q. In that footnote which accompanies the text
above, the Company says or you testify that Idaho Power
cannot represent to customers that they are receiving
renewable energy. Can you explain to the Commission what
restricts the utility from representing to customers that
it's serving customers with renewable energy that it
purchases from QFs?
A. I think, again, as the footnote states, Idaho
Power does not receive the renewable energy certificates
or credits/RECs from these projects; therefore, if Idaho
CSB REPORTING
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294 ALLPHIN (X)
Idaho Power Company
• 1 Power Company does not actually receive the renewable
2 energy certificates from a QF project or any other
3 renewable project, Idaho Power Company is unable to claim
4 that project as being a renewable energy project in
5 various places.
6 Q. So just to be clear, then, there are some
7 existing QF contracts where the Company receives or
8 claims no ownership to the RECs; is that correct?
9 A. Absolutely. The vast majority of all of the
10 projects currently online, Idaho Power Company has no
• 11 rights to the renewable energy credits. The current
12 solar contracts that have been executed, Idaho Power
13 Company has the ability to claim 50 percent of the RECs
14 in those contracts.
15 Q. And so that statement doesn't mean that Idaho
16 Power is not purchasing renewable QF power; is that
17 correct?
18 A. We are purchasing energy from renewable energy
19 projects that is being integrated into our system.
20 Q. And maybe just to drill down a little bit more,
21 what specifically prohibits the Company, if you can • 22 explain, from claiming that it's not buying renewable
23 energy, simply the fact that you're not getting the
24 RECs?
25 A. Yes.
CSB REPORTING
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Idaho Power Company
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Q. And then finally, in your experience, does
PURPA mandate that states adopt a renewable portfolio
standard?
A. No.
MR. HOWELL: Thank you, Mr. Chairman. I have
no further questions.
COMMISSIONER KJELLANOER: Thank you. Are there
questions from the Commissioners? No questions. We're
ready for redirect.
MR. WALKER: No redirect, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you very much,
and we appreciate your testimony.
(The witness left the stand.)
COMMISSIONER KJELLANOER: Let's see how we do
with Mr. Olsen with the Idaho Irrigation Pumpers, if you
would like to call your witness.
MS. OLSEN: Thank you, Mr. Chair. We'd like to
call Mr. Anthony J. Yankel to the stand.
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Idaho Power Company
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ANTHONY J. YANKEL,
produced as a witness at the instance of the Idaho
Irrigation Pumpers Association, having been first duly
sworn to tell the truth, the whole truth, and nothing but
the truth, was examined and testified as follows:
DIRECT EXAMINATION
BY MS. OLSEN:
Q. Mr. Yankel, could you please state your name
and spell it for the record, please?
A. Anthony J. Yankel, Y-a-n-k-e-1.
Q. And in what capacity are you here today?
A. I'm a witness for the Idaho Irrigation Pumpers
Association.
Q. Okay, are you the same Anthony Yankel who filed
direct testimony on April 23rd in this matter?
A. Yes.
Q. Do you have any corrections or additions,
deletions from your testimony?
A. None of which I am aware.
Q. Okay, if I were to ask you the same questions
that's contained in your direct testimony that was filed
on the 23rd of April, would your answers still be the
same?
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A. Yes, they would.
MR. OLSEN: Okay, Mr. Chair, I would ask
that Mr. Yankel's prefiled direct testimony be spread on
the record as if read and incorporated herein.
COMMISSIONER KJELLANDER: And without
objection, the testimony will be spread across the record
as if read.
(The following prefiled testimony of
Mr. Anthony J. Yankel is spread upon the record.)
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Q. Please state your name, address, and
employment.
A. I am Anthony J. Yankel. I am President of
Yankel and Associates, Inc. My address is 29814 Lake
Road, Bay Village, Ohio, 44140.
Q. Would you briefly describe your educational
background and professional experience?
A. I received a Bachelor of Science Degree in
Electrical Engineering from Carnegie Institute of
Technology in 1969 and a Master of Science Degree in
Chemical Engineering from the University of Idaho in
1972. From 1969 through 1972, I was employed by the Air
Correction Division of Universal Oil Products as a
product design engineer. My chief responsibilities were
in the areas of design, start-up, and repair of new and
existing product lines for coal-fired power plants. From
1973 through 1977, I was employed by the Bureau of Air
Quality for the Idaho Department of Health & Welfare,
Division of Environment. As Chief Engineer of the
Bureau, my responsibilities covered a wide range of
investigative functions. From 1978 through June 1979, I
was employed as the Director of the Idaho Electrical
Consumers Office. In that capacity, I was responsible
for all organizational and technical aspects of
advocating a variety of positions before various
CASE No. IPC-E-15-1
April 23, 2015
299 Yankel, Di-1
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governmental bodies that represented the interests of the
consumers in the State of Idaho. From July 1979 through
October 1980, I was a partner in the firm of Yankel,
Eddy, and Associates. Since that time, I have been in
business for myself. I have been a registered
Professional Engineer in the states of Ohio and Idaho. I
have presented testimony before the Federal Energy
Regulatory Conunission (FERC), as well as the State Public
Utility Conunissions of Idaho, Montana, Ohio,
Pennsylvania, Utah, and West Virginia.
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CASE No. IPC-E-15-1
April 23, 2015
300 Yankel, Di-la
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Q. On whose behalf are you testifying?
A. I am testifying on behalf of the Idaho
A. My testimony will address:
Q. What is the purpose of your testimony in this
term of two years. I do not view this as a
My critique of Idaho Power's Exhibit 6 that
Supporting Idaho Power's initial request for
long-term solution to the glut of PURPA
a limitation on new PURPA contracts to a
problems with the present avoided cost model
a good stop-gap measure to give the Company
and the Commission an opportunity to correct
contracts that plague Idaho Power, but it is
assumptions.
must-run and must-take power on the
on Exhibit 6 with the manner in which the
attempts to illustrate the problems of
I provide a review and contrast of how the
differ from the manner in which costly
system is actually operated.
Company's system. I contrast what is shown
resources are actually utilized, while
Company's avoided cost model assumptions
*
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proceeding?
Irrigation Pumpers Association, Inc. (Irrigators).
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CASE No. IPC-E-15-1
April 23, 2015
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*
making sales-for-resale at substantially
lower prices.
My ultimate recommendation is that new PURPA
contracts be limited to a term of two years
and during that two year timeframe, the
Company and the Commission develop a more
accurate avoided cost methodology.
CASE No. IPC-E-15-1
April 23, 2015
302 Yankel, Di-2a
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Q. What is your overall understanding of the
purpose of the Qualifying Facilities ("QF") under the
Public Utility Regulatory Policies Act of 1978 ("PURPA")?
A. PURPA attempted to encourage the development of
cogeneration and small power production facilities which
were known as QF's. The purpose of these PURPA projects
was to help the Country become energy independent by
utilizing cogeneration and small power production
facilities as a means of capturing energy, but for PURPA,
may have been wasted. For more than 20 years Idaho Power
and the Commission have been successful in developing
these cogeneration and small production facilities.
However, with the advent of new wind and solar
technology, the general principles behind the PURPA
generation resources has become lost. We are no longer
talking about cogeneration and small power production
facilities, but installations/facilities that rival any
utility generation project. Rates paid to PURPA
facilities were meant to be just and reasonable to a
utility's customers. In this case, Idaho Power
appropriately points out that the present situation with
PURPA facilities is inappropriately causing rates to the
customers to go up and are thus, no longer just and
reasonable.
Q. What is the present situation with PURPA
• CASE No. IPC-E-15-1
April 23, 2015
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facilities and the Idaho Power system?
A. The present situation is well described by
Idaho Power in this case. The capacity level of PURPA
facilities that are presently on the system or that have
signed contracts, far out-weigh the Company's ability to
economically integrate them into the system. There are
two basic problems-must-take contracts and price. Given
the level of the present facilities and signed
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CASE No. IPC-E-15-1
April 23, 2015
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contracts on the system, the Company will run into many
times when it will simply have too much capacity and will
need to choose between curtailing its own must-run
facilities or the PURPA must-take contracts. The
situation is further compounded by the fact that the
prices being paid to these PURPA facilities is usually
higher than the running cost of any of the Company's
facilities. Backing down Idaho Power's facilities (to
the point of must-run levels), in order to allow more
generation from these PURPA facilities simply means that
the customers will be paying more. The most egregious
problem is that there have been times in the past when
Idaho Power has had to pay other utilities to take its
excess power.
Q. Why are you supporting Idaho Power's request to
limit the term of future contracts to just two years,
when you indicate that the fundamental problem is the
must-take provision as well as the price?
A. I support the reduction of new contract terms
to two years as a stopgap measure. I assume that it will
take at least two years to work out the complexities of
what has gone wrong and how to correct it. If new PURPA
contracts were priced appropriately, Idaho Power would
either not have a glut of such facilities on its system
now (and proposed to get much worse), or it would be able
•
CASE No. IPC-E-15-1
April 23, 2015
305 Yankel, Di-4
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to sell and/or deliver this energy in a manner that would
not adversely impact its customers. It is going to take
some time to determine how to best integrate new PURPA
facilities into the system without exacerbating an
already bad situation. If solutions can be developed in
two years, then they can be incorporated into the
new/renewed contracts. If the new contract terms coming
out of this case were for five years and solutions were
developed in two years, Idaho Power (and its customers)
would have to wait an additional three years before
finding some
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CASE No. IPC-E-15-1
April 23, 2015
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relief from a bad situation that has the potential to
make things worse with each new contract that is signed.
Q. Do you support limiting all new PURPA contracts
to a two year term?
A. No. I support only limiting the new solar and
wind contracts to the two year term. These are the
contracts for intermittent power that got us into trouble
in the first place. The original purpose of the PURPA
contracts was for "cogeneration and small power
production". These are the types of facilities that may
require long-term contracts in order to get financing.
PURPA was designed to stimulate cogeneration and small
power production and not utility size projects. I
support the continuation of long-term contracts for new
cogeneration and small power production facilities.
IPCo's Exhibit 6 Compared To Actual Operation
Q. Idaho Power's Exhibit 6 portrays the first week
of each of 24 months of estimated system load on an
hourly basis compared to the company's must-run
resources, must-take PURPA generation and must-take
non-PURPA power purchase agreements. Does that exhibit
demonstrate the problems Idaho Power could incur with
respect to too much must-take capacity on the system?
A. Yes. Idaho Power's Exhibit 6 depicts the
problem of having more must-take capacity on the system
CASE No. IPC-E-15-1
April 23, 2015
307 Yankel, Di-5
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(in addition to its own resources) than system load.
However this exhibit should be considered for
illustrative purposes only. The system is far more
involved than simply assuming forecasted load and minimum
must-run and must-take capacity levels.
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CASE No. IPC-E-15-1
April 23, 2015
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Q. Idaho Power's Exhibit 6 demonstrates that Idaho
Power not only has excess must-take capacity from PURPA
generation, but there is often excess capacity from only
its own must-run generation as well. Is that a problem?
A. No. First, it must be remembered that this
exhibit is for illustrative purposes only. The excess
must-run capacity shown in Idaho Power Exhibit 6 does not
reflect any additional sales or obligations of Idaho
Power. Thus, most of the extra Company-owned capacity on
the system can be absorbed by other than system
customers. Very simply, Idaho Power's Exhibit 6 is for
illustrative purposes, and does not necessarily reflect
how the system is actually operated.
Second, based upon Exhibit 6, the Company
statesl that 14% of the time there would be excess
capacity on the system, if one only included IPCo's
must-run generation and the generation from its own
PPA's. I have worked on Idaho Power cases for over 35
years and have never heard of a time where the Company
had too much operating capacity on an ongoing basis .
Yes, there are times when generation exceeds system load,
but during these times energy is sold off-system or
generation is simply taken off-line.
Q. With respect to excess must-run capacity, how
does the actual system operation differ from the
CASE No. IPC-E-15-1
April 23, 2015
309 Yankel, Di-6
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illustration in Idaho Power Exhibit 6?
A. On page 5 of 25 of Idaho Power Exhibit 6, is
portrayed the "Forecasted Must Run or Take Generation"
for the first week of April 2016 compared to the "Idaho
Power Forecasted
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1 See Testimony of Company witness Allphin at page 10.
• CASE No. IPC-E-15-1
April 23, 2015
310 Yankel, Di-6a
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Load" (system only). As would be expected, April is the
month with the most must-run capacity compared to system
load. During most of the forecasted hours for April 2016
(primarily the last two hours of each day), the Idaho
Power must-run capacity (excluding IPCo's own must-take
PPA's, PURPA excluding wind and solar, PURPA wind, PURPA
solar under contract, and the 885 MW of proposed PURPA
solar) is well above the forecasted load. Based upon the
assumptions contained on page 5 of that Exhibit, one
would expect that April would be the month when most of
the curtailments due to excess capacity on the system
would occur.
Idaho Power indicated2 that over the timeframe May
2011 through December 2014, there were 21 reliability
curtailments of PURPA generation because of an
over-generation position on the system. Of these 21
curtailments, [redacted testimony] during the month of
April. However, compared to the magnitude of the
potential resource load/capacity imbalance demonstrated
on Exhibit 6 for April 2016, these [redacted testimony]
curtailments only represented [redacted testimony] of the
number of hours of curtailment that occurred during these
21 events3.
Q. With respect to excess must-run capacity during
other months, how does the actual system operation differ
CASE No. IPC-E-15-1
April 23, 2015
311 Yankel, Di-7
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from the illustration in Idaho Power Exhibit 6?
A. Unlike April, the graphs for October and
November of 2016 on Exhibit 6 pages 11 and 12 portray the
forecasted system load well in excess of Idaho Power's
own must-run generation. In fact the graph for October
portrays no hours where the minimum must-run levels of
the Company's resources (plus IPCo must-take PPA) even
approaches the level of the forecasted system load.
Additionally, with all of the resources (Company and none
Company) listed on
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2 See testimony of Company witness Grow at page 21 and
response to Simplot Request to Produce 6a.
3 [Redacted testimony)
•
CASE No. IPC-E-15-1
April 23, 2015
312 Yankel, Di-7a
Irrigation Pumpers
November are two months where Idaho Power should have
In contrast to the forecasted data in Exhibit 6, of
minimal problems with excess capacity on the system.
Exhibit 6 there was only approximately 15 hours out of
PURPA wind, PURPA solar under contract,
IPCo's must-run hydro and coal generation,
PURPA excluding wind and solar,
IPCo's own must-take PPA's,
and
885 MW of proposed PURPA solar.
*
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including:
the 168 total hours in that week where the system load is
less than the summation of all must-take capacity
The graph for November portrays essentially the same
thing. There are no hours in which the must-run IPCo
facilities plus IPCo's must-take PPA's exceeds the
when the system load is less than the summation of all
of proposed solar) there are only approximately 25 hours
forecasted system load. Even including the PURPA
resources, (including solar under contract and the 885 MW
the proposed solar does not yet exist, October and
must-run and must-take capacity. In other words, under
today's conditions, where the solar under contract and
the actual 21 curtailments that occurred between May 2011
and December 2014, [redacted testimony) occurred during
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CASE No. IPC-E-15-1
April 23, 2015
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the months of October and November4. However, compared
to the minimal potential resource load/capacity imbalance
(in the future with added wind and solar) demonstrated on
Exhibit 6 for October and November, 2016, these [redacted
testimony] historic curtailments represented [redacted
testimony]S of the number of hours of curtailment that
occurred during these 21 events-under conditions of less
PURPA wind and solar capacity than
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4 See Confidential Response to Simplot Request 6d.
5 Confidential response to Simplot Request 6d-[redacted
testimony]
CASE No. IPC-E-15-1
April 23, 2015
314 Yankel, Di-Ba
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Idaho Power's Exhibit 6 and the actual level of
Idaho Power's actual curtailments indicate about the need
Exhibit 6 demonstrates that over the 2016-2017 period,
Q. What should be concluded from a comparison of
[redacted testimony] what is listed in Exhibit 6.
Q. What does this comparison of Exhibit 6 and
A. It means that Exhibit 6 does not give any
actual events combined that occurred during the months of
IPCo system?
for reliability curtailments of PURPA generation on the
April 6.
Non-PURPA must-take power purchases (without the addition
tells nothing about the operation of the system. Looking
curtailments lasted longer than all [redacted testimony]
for reliability curtailments of PURPA generation because
of excess must-take capacity on the system. Exhibit 6 is
a good illustration, but it is only an illustration and
only at Idaho Power's own must-run hydro and coal, plus
of PURPA generation-purchases), the Company states? that
quantifiable insight into the need of the Company to call
system load will be exceeded 14% of the time. By
comparison, the actual 21 curtailments that occurred
amounted to only [redacted testimony]8 of that timeframe.
curtailments that have had to be taken on the system over
during the May 2011 through December 2014 (44 months),
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CASE No. IPC-E-15-1
April 23, 2015
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the 44 month period under review?
A. It should be recognized that Idaho Power's
Exhibit 6 is a good illustration of the problems the
Company is facing, but it is not an accurate reflection
of how the Company operates
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6 Confidential response to Simplot Request 6d-[redacted
testimony]
7 See Company witness Allphin's testimony page 10 line 19-25.
8 Confidential response to Simplot Request 6d-[redacted
testimony]
CASE No. IPC-E-15-1
April 23, 2015
316 Yankel, Di-9a
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was called?
data and its actual level of curtailments over the recent
model assumptions do not reflect this same logic, the
A. Yes. One of the 21 curtailments called by
Yankel, Di-10
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317
in the real world. If the Company's modeling assumption
Q. As opposed to the general comparison that you
[redacted testimony]. It lasted [redacted testimony] and
in this case is the avoided cost price that comes out of
not recognize the way that IPCo uses Term purchases and
conclusion may be drawn from the models-of most concern
Sales, Beginning of Month ("BOM") purchases and sales;
its avoided cost pricing will be too high. The Company
the Company's IRP model. If the IRP model assumption do
uses Term, BOM, and Day-Ahead activity to hedge its
do not reflect actual operation, then inappropriate
and Day-Ahead purchases and sales, to balance its load,
Exhibit 6 compare to actual operations when a curtailment
resulting avoided costs will be too high.
just made between Idaho Power's illustrative operation
how the assumptions of must-run capacity in Idaho Power's
supply in order to keep costs down. If the Company's IRP
44 month period, can you demonstrate more specifically
light load hours between these two days as well as
spanned two days. The curtailment lasted over all of the
Idaho Power during 44 recent month period occurred during
CASE No. IPC-E-15-1
April 23, 2015
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[redacted testimony] additional hours.
Table 1 below lists the capacity figures from the
last 12 hours of the first day when this particular
curtailment took place.10 The "gray areas" reflects the
first of the light-load hours (for the last two hours of
the day) when the curtailment was taking place. The
capacity figures listed are significantly higher than
those that are represented as must-run and must-take
capacity levels
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9 Confidential response to Simplot Request 6d-the curtailment
occurred on [redacted testimony]
10 Data from the date and times listed from the confidential
response to Irrigation Request 10.
CASE No. IPC-E-15-1
April 23, 2015
318 Yankel, Di-lOa
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found in Idaho Power's Exhibit 6. A reliability
curtailment was taking place during these two light-load
hours when generation was significantly above the minimum
levels listed on IPCo's Exhibit 6.
Table 1
Hour 13 14 15 16 17 18 19 20 21 22 23 24
coal [redacted testimony)
hydro [redacted testimony)
gas [redacted testimony)
PURPA/other [redacted testimony)
For example, the capacity coming out of the coal
facilities ([redacted testimony]) is significantly higher
than the "must-run" level of 266 MW listed on the graphs
of Idaho Power's Exhibit 6. Although there is a definite
drop in coal generation from what occurred during the
midafternoon hours, the drop is nowhere near the
"must-run" level of 266 MW.
The capacity coming out of the hydro facilities is
similarly higher than that used to establish Idaho
Power's Exhibit 6 page 9 for the last two hours of the
first day. Measuring the height of the "must-run" level
depicted for "hydro plus coal" in Exhibit 6, it can be
estimated that the "must-run" capacity for these two
sources is 700 MW. With coal generation taking up 266 MW
of this total, this leaves 434 MW as the "must-run"
•
CASE No. IPC-E-15-1
April 23, 2015
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minimum level for hydro generation. The actual hydro
generation was more than [redacted testimony] greater
than this minimum during these last two hours of the day
when the curtailment was called.
Of even more significance, the gas plants, because
of their nature, are not forecasted to run during any of
the minimum generation levels found on Idaho Power
Exhibit 6. However, as seen on Table 1 above, the gas
plants were operating in the [redacted testimony] range
during the last two hours of the day when the curtailment
was called.
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CASE No. IPC-E-15-1
April 23, 2015
320 Yankel, Di-lla
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For completeness, Table 1 includes the amount of
PURPA and other generation on the Idaho Power system
during these same hours.
Q. How does purchase power and sales for resale
fit into the mix of resources and requirements on the
August 2012 day that you are addressing?
A. Purchase Power and Sales for Resale are listed
for each of the same last 12 hours of that day on Table
2 .11
Table 2
Hour 13 14 15 16 17 18 19 20 21 22 23 24
Term purchase [redacted testimony]
BOM purchase [redacted testimony]
Day Ahead purchase [redacted testimony]
Day Ahead sales [redacted testimony]
Real Time sales [redacted testimony]
Real Time purchases [redacted testimony]
The Term purchases and Beginning of Month (BOM) purchases
are all a part of the system balance, but they are set
well ahead of the time when critical decisions need to be
made regarding the need for curtailment because of excess
capacity. Day-Ahead sales and purchases reflect some
knowledge of what will occur during the following day.
[Redacted testimony]
[Redacted testimony]
CASE No. IPC-E-15-1
April 23, 2015
321 Yankel, Di-12
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excess capacity situation .
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[Redacted testimony]
[Redacted testimony]
Real Time sales and purchases can definitely impact the
CASE No. IPC-E-15-1
April 23, 2015
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[Redacted testimony]
[Redacted testimony]
Q. Please continue to demonstrate how the
assumptions of must-run capacity in Idaho Power's Exhibit
6 compare to actual operations during the second day when
the curtailment in question was called?
A. As pointed out above, the curtailment in
question lasted [redacted testimony] and spanned two
days. The curtailment lasted over all of the light-load
hours between these two days as well as [redacted
testimony] hours. Like the first day addressed above,
for the second day of the curtailment, I will primarily
focus on what took place during light-load hours and
contrast them with the rest of the hours in the first
half of the second day.
Table 3 below lists the capacity figures from the
first 12 hours of the second day when this particular
curtailment took place12. The "gray areas" for the first
six hours of the day reflect the remainder of the
light-load hours when the curtailment was taking place.
The significance of these first six hours of the day is
that the capacity figures listed are very different than
those that are represented as must-run capacity levels
found in Idaho Power's Exhibit 6.
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CASE No. IPC-E-15-1
April 23, 2015
323 Yankel, Di-13
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1 Table 3
2 Hour 1 2 3 4 5 6 7 8 9 10 11 12 -
3 coal [redacted testimony]
4 hydro [redacted testimony]
• 5 gas [redacted testimony]
6 PURPA/other [redacted testimony]
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CASE No. IPC-E-15-1
April 23, 2015
324 Yankel, Di-13a
Irrigation Pumpers
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For example, the capacity coming out of the coal
facilities ([redacted testimony]) is significantly higher
than the "must-run" level of 266 MW listed on the graphs
of Idaho Power's Exhibit 6. Although the coal generation
that occurred during the first six hours (light-load
hours) is lower than the coal generation during the later
morning hours, the drop is nowhere near the "must-run"
level of 266 MW-in spite of the fact that a reliability
curtailment was taking place.
The capacity coming out of the hydro facilities is
similarly higher than that used to establish Idaho
Power's Exhibit 6 page 9 for the first four hours of the
second day. It can be seen that on the graph on Exhibit
6 page 9 that the height of the "must-run" level depicted
for "hydro plus coal" is at the same height as the last
two hours of the previous day, i.e., 700 MW. With coal
generation taking up 266 MW of this total, this leaves
434 MW as the "must-run" minimum level for hydro
generation. The hydro generation was about [redacted
testimony]% greater than this minimum during these first
four hours of the second day when the reliability
curtailment was called.
Of even more significance, the gas plants, because
of their nature, are not forecasted to run during any of
the minimum generation levels found on Idaho Power
CASE No. IPC-E-15-1
April 23, 2015
325 Yankel, Di-14
Irrigation Pumpers
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Exhibit 6. However, as seen on Table 3 above, the gas
plants were operating in the [redacted testimony] MW
range during the first six hours of the second day when
the reliability curtailment was called.
for completeness, Table 3 includes the amount of
PURPA and other generation on the Idaho Power system
during these same hours.
Q. How does purchase power and sales for resale
fit into the mix of resources and requirements on the
second day in [redacted testimony] that you are
addressing?
I
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• CASE No. IPC-E-15-1
April 23, 2015
326 Yankel, Di-14a
Irrigation Pumpers
A. Purchase Power and Sales for Resale are listed
these non-Real Time transactions result in [redacted
[redacted testimony].
[redacted testimony] the following day of excess
[redacted testimony]
Real Time sales and purchases can definitely impact
Table 4
Hour 1 2 3 4 5 6 7 8 9 10 11 12
Term purchase [redacted testimony]
BOM purchase [redacted testimony]
Day Ahead purchase [redacted testimony]
Day Ahead sales [redacted testimony]
Real Time sales [redacted testimony]
Real Time purchases [redacted testimony]
for each of the first 12 hours of that day on Table 4.
Once again, the Term purchases and Beginning of Month
they are set well ahead of the time when critical
Day-Ahead transactions during these hours resulted in
Day-Ahead sales and purchases reflect some knowledge of
(BOM) purchases are all a part of the system balance, but
what will occur during the following day. The combined
reliability curtailments because of excess capacity.
decisions need to be made regarding the need for
testimony]
capacity. For the particular hours in question, all of
the excess capacity situation.
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CASE No. IPC-E-15-1
April 23, 2015
327 Yankel, Di-15
Irrigation Pumpers
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Q. Does this comparison of Idaho Power's Exhibit
6, page 9 with an actual curtailment that occurred during
August 2012 indicate that Idaho Power was operating its
system inappropriately and/or it should not have
curtailed PURPA load?
A. Absolutely not. At this time, I am assuming
that Idaho Power operated its system during the time of
this reliability curtailment to the best of its
abilities-including the curtailment. Once again, this
comparison shows is that there is a great deal of
difference between many of the Company's modeling
assumptions and the way the system works on an
hour-to-hour basis.
Q. What is the significance to this case of the
difference between modeling assumptions and hour-to-hour
operations?
A. The modeling indicates that there are potential
problems regarding excess capacity that cannot be
addressed by backing down units below a must-run level.
However, the large differences between the model results
and actual operation demonstrates the limited ability of
the model assumptions to reflect actual system operation,
and more importantly, actual system costs. This
inability of the Company's model assumptions to reflect
actual system operation and actual system cost is
CASE No. IPC-E-15-1
April 23, 2015
328 Yankel, Di-16
Irrigation Pumpers
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particularly important to this case, because if the
avoided costs that are developed to be paid to PURPA
generators are inaccurate, so will the inducement to
build these projects. If the IRP model assumptions do
not recognize the way that IPCo uses Term purchases and
Sales, Beginning of Month ("BOM") purchases and sales;
and Day-Ahead purchases and sales, to balance its load,
its avoided cost pricing will be too high. The Company
uses Term, BOM, and
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CASE No. IPC-E-15-1
April 23, 2015
329 Yankel, Di-16a
Irrigation Pumpers
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Day-Ahead activity to hedge its supply in order to keep
costs down. If the Company's IRP model assumptions do
not reflect this same logic, the resulting avoided costs
will be too high.
A far better way to control the growth of PURPA
generation on the Idaho Power system is not to reduce the
terms of the contracts, but to develop avoided cost model
assumptions that more accurately reflect the operation of
the system. These avoided cost model assumptions must
not only recognize the glut of PURPA generation that is
presently on the system, but how the system actually
operates today. Having a model assumption that assumes
that new/additional PURPA generation will replace the
Company's owned resources is simply invalid. This may
have been an acceptable assumption when the amount of
PURPA generation on the system was small, but today this
assumption is not only causing operation problems, but is
resulting in significantly higher prices for ratepayers.
PURPA Generation Replacing The Highest Cost Resource
Q. Can you give any other examples of how the
actual operation of the system may differ from the
assumptions used in the IRP model to develop avoided
costs?
A. Yes. It is my understanding that a prime
assumption used in the IRP model is that, except for
CASE No. IPC-E-15-1
April 23, 2015
330 Yankel, Di-17
Irrigation Pumpers
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system operating limitations, the least expensive options
in the resource stack will be used to supply load. Very
simply, this means that a more expensive resource will be
backed-off, if a cheaper resource is available. However,
there are times when the actual operation does not
strictly follow this rule. I assume that the Company is
operating its system at the lowest cost it can, given the
minute-to-minute and hour-to-hour balancing of loads and
resources that are
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CASE No. IPC-E-15-1
April 23, 2015
331 Yankel, Di-17a
Irrigation Pumpers
•
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required. However, if the Company's IRP model
assumptions, as a whole, do not accurately reflect the
minute-to-minute and hour-to-hour operation of the
Company, one cannot expect the resulting avoided cost
that comes out of the model to be accurate.
Q. Can you demonstrate how Idaho Power's actual
operations differ from the general principle that only
the lowest cost resources should be utilized?
A. Yes. As a component of the concept of using
the lowest cost resources first, it is generally agreed
that when a sales-for-resale is made, the price received
for the energy should be equal to or above the highest
cost unit/resource operating. In other words, it is
assumed that if the sale were not made, then the highest
priced resource could be backed-off by the quantity of
the energy sold. Of course, this does not apply to
energy coming from PURPA projects or if there is some
operational limitation in effect at the time.
By way of example, during actual operations Idaho
Power does in fact sell energy off-system at prices lower
than the cost of its most expensive operating resource
(and often below the cost of more than just its highest
cost operating resource). In order to demonstrate this,
I have constructed Table 5. In [redacted testimony]
Idaho Power started Langley Gulch on [redacted
CASE No. IPC-E-15-1
April 23, 2015
332 Yankel, Di-18
Irrigation Pumpers
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testimony]and ran it constantly (24x7) [redacted
testimony]. Generally speaking, Langley Gulch ran
[redacted testimony] generally at a stable level during
each period. Table 5 lists the hours [redacted
testimony] when the weighted-average pricel3 received for
day-ahead sales-for-resale fell well below the cost of
running Langley Gulch
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13 Data from the date and times listed from the confidential
response to Irrigation Request 10.
CASE No. IPC-E-15-1
April 23, 2015
333 Yankel, Di-18a
Irrigation Pumpers
1 ($35.0 per MWH)14, and in many cases below the cost of
2 operating some of the Company's coal plant: Valmy at
3 $49.6 per MWH15; Boardman at $32.1 per MWH16; and Jim
4 Bridger at $28.6 per MWH17.
5
Table 5
Price Ht H2 H3 H4 H5 Ht H7 HS H9 HtO H11 H12 H13 H14 H15 H16 H17 H1S H19 H20 H21 H22 H23 H24
....... ·• .
• • • • • • • • • • • • • • • • • • • • I I I I • • • • • • • • • • • • • • • • • • - . - . • •
• • • •
• • • • • • • • • • • •
• •
• •
• • • •
•
• • • •••• • ••••••• ••••••• • • • • • • • • •
• • • • • • • • • • • • • • • • • • • • • • • I I I I I I I I I I I I I I I I I I I I I I I I • • • • • • • • • • • •
- - - - .:. - - - - - - - - - - . - . - . - . - . - . - . - .
15
• 16 Q. Please further describe what is contained on
17 Table 5.
• 18 A . Table 5 indicates for the hours between
19 [redacted testimony] whether or not the price received
20 for day-ahead sales-for-resale was less than the cost of
21 operating Langley Gulch. The first column lists the date
22 and the first row lists the hours in each day. The
23 second column lists the average-weighted price received
24 for the "low priced" sales-for-resale for a given day and
25 hour being addressed here. An "X" marks the hour during
• CASE No. IPC-E-15-1
April 23, 2015
334 Yankel, Di-19
Irrigation Pumpers
• 1 a given day when Langley Gulch was operating and when
2 sales-for-resale have occurred at the weighted-average
3 price listed in Column 2. When there is an "XX", Langley
4 Gulch is operating as well as one other gas generator.
5 When there is an "XXX", all three of the Idaho Power's
6 gas units are operating (note
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20 14 Idaho Power's 2013 FERC Form 1 page 402.1 for Langley
•
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Gulch.
15 Idaho Power's 2013 FERC Form 1 page 403 for Valmy.
16 Idaho Power's 2013 FERC Form 1 page 402 for Boardman .
17 Idaho Power's 2013 FERC Form 1 page 402 for Jim Bridger.
23 that Danskin operates at $54.3 per MWH and Bennett
24 Mountain at $59.0 per MWH18). An "XV" indicates that
25 Langley Gulch is operating and that Valmy is operating
CASE No. IPC-E-15-1
April 23, 2015
335 Yanke!, Di-19a
Irrigation Pumpers
hours are marked with a "XV".
time. Sales-for-resale were sold at this
hour, these hours are marked with a "XV".
Yankel, Di-20
Irrigation Pumpers
336
By way of further example, the weighted-average
Q. What can be concluded from Table 5 with respect
Bridger and Boardman), which were both operating at the
By way of example, [redacted testimony]. The
price of the energy sold on [redacted testimony). On
was [redacted testimony]. This price is well below the
Mountain at $59.0 per MWH18). An "XV" indicates that
operating cost of Langley Gulch and Valmy (as well as
above minimum must-run level. No marking indicates that
there were no sale-for-resale during that particular day
and hour at the "low prices" listed in Column 2.
that Danskin operates at $54.3 per MWH and Bennett
weighted-average price of [redacted testimony). These
Valmy was operating above minimum levels after the 6:00
Valmy was operating above minimum levels after the 6 a.m.
average-weighted price of the energy sold at this time
a.m. hour. Because both Langley Gulch was operating and
this time period. On this day, the sales-for-resale at
the weighted-average price of [redacted testimony].
this day Valmy was operating at minimum levels during the
first six hours so the table only displays an "X" for
Langley Gulch is operating and that Valmy is operating
CASE No. IPC-E-15-1
April 23, 2015
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1 to the differences between the assumptions in the Company
2 models for avoided costs and the way the Company actually
3 operates its system?
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24 18 Idaho Power's 2013 FERC Form 1 page 403 Danksin and Bennett
Mountain
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CASE No. IPC-E-15-1
April 23, 2015
337 Yankel, Di-20a
Irrigation Pumpers
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A. As I pointed out above, I assume that the
Company operates its system in order to minimize costs.
Table 5 demonstrates that Idaho Power does not operate
its system based upon the simplifying assumption that
(absent certain operational constraints) the lowest cost
resources will be used to supply load. Under this
assumption in the model, the Company would not be selling
power at prices significantly lower than the marginal
cost to produce the energy. The model assumptions used
to establish avoided costs must reflect how the Company
actually operates and not rely upon general assumptions
that ignore many of the realities of the system.
Conclusion and Recommendations
Q. What are your conclusions and recommendations?
A. From the above differences that I have pointed
out, it is obvious that Idaho Power's models and modeling
assumptions do not sufficiently reflect actual Company
operations. Without the Company's model assumptions
accurately reflecting actual system operation, it must be
assumed that the models do not adequately predict avoided
costs.
I recommend that the Commission limit the term of
all future PURPA contracts to 2-years for all three of
the major electric utilities operating in the Idaho.
Hopefully, this will be sufficient time to review the
CASE No. IPC-E-15-1
April 23, 2015
338 Yankel, Di-21
Irrigation Pumpers
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modeling assumptions and the avoided costs of all three
utilities. Assuming that adequate modeling assumptions
can be put in place within two years, then it may be
desirable to change the length of the term at that time.
If adequate modeling cannot be put in place within two
years, then the 2-year term should stay in place.
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CASE No. IPC-E-15-1
April 23, 2015
339 Yankel, Di-21a
Irrigation Pumpers
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER KJELLANDER: And so you're
4 tendering your witness now for cross-examination?
5
6
MS. OLSEN: Yes.
COMMISSIONER KJELLANDER: Why don't we begin
7 with the Deputy Attorney General representing Staff and
8 the Public Utilities Commission.
9 MR. HOWELL: Thank you, Mr. Chairman. Staff
10 has no questions.
11
12 Power.
13
COMMISSIONER KJELLANDER: Thank you. Idaho
MR. WALKER: No questions from Idaho Power,
14 Mr. Chairman.
15
16
17 you.
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COMMISSIONER KJELLANDER: PacifiCorp.
MS HOGLE: No questions from PacifiCorp. Thank
COMMISSIONER KJELLANDER: Avista.
MR. ANDREA: No questions from Avista.
COMMISSIONER KJELLANDER: Mr. Richardson.
MR. RICHARDSON: No questions from Clearwater,
22 Mr. Chairman.
23
24 Micron.
25
COMMISSIONER KJELLANDER: Pamela Howland for
MS. HOWLAND: No questions.
CSB REPORTING
[phone]
340 YANKEL
Irrigation Pumpers
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COMMISSIONER KJELLANDER: Mr. Arkoosh.
MR. ARKOOSH: No, thank you, Your Honor.
COMMISSIONER KJELLANDER: Mr. Hammond.
MR. HAMMOND: No questions.
COMMISSIONER KJELLANDER: Mr. Sanger.
MR. SANGER: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Kelsey Nunez with
8 Snake River Alliance.
9
10
MS. NUNEZ: No questions.
COMMISSIONER KJELLANDER: Mr. Miller. You have
11 one, okay.
12
13
14
CROSS-EXAMINATION
15 BY MR. MILLER:
16 Q. Not to leave the string unbroken, just a
17 couple, Mr. Yankel. As I understand your testimony,
18 you're suggesting there's some deficiencies in the
19 current IRP model and proposing changes to that model.
20 A. I'm more proposing changes to the way the model
21 applies to PURPA contracts, and I think looking at the
22 IRP model with respect to the IRP is really a different
23 question. I'm not -- I have problems with the model
24 itself, yes, but whether or not that should impact or
25 change the IRP process, I've not taken a position on
CSB REPORTING
[phone]
341 YANKEL (X)
Irrigation Pumpers
1 that.
2 Q. Just, then, to clarify, you haven't
3 participated in the IRP process and proposed these
4 changes within the context of that process?
5
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A. That is correct.
MR. MILLER: That's all I have.
COMMISSIONER KJELLANDER: Thank you,
8 Mr. Miller. Mr. Otto.
9
10
11 Adams.
12
13
MR. OTTO: No questions.
COMMISSIONER KJELLANDER: Thank you, and Mr.
MR. ADAMS: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Did I
14 miss anyone? Questions from the Commission.
15
16
COMMISSIONER RAPER: No.
COMMISSIONER KJELLANDER: None. Well, there is
17 an opportunity for redirect.
18
19
MS. OLSEN: We don't have any, Your Honor.
COMMISSIONER KJELLANDER: I didn't think you
20 did. Thank you very much, and Mr. Yankel, you're
21 excused, and my assumption is that, Mr. Olsen, you have
22 an additional request regarding your witness?
23 MS. OLSEN: I'd like to request to release the
24 witness and allow him to return to Cincinnati.
25 COMMISSIONER KJELLANDER: So without objection,
CSB REPORTING
[phone]
342 YANKEL (X)
Irrigation Pumpers
1 Mr. Yankel, thank you very much for being here.
2 (The witness left the stand.)
3 COMMISSIONER KJELLANDER: We now move to the
4 Renewable Energy Coalition. Mr. Sanger.
5 MR. SANGER: Thank you, Your Honor. We'd call
6 Mr. John Lowe on behalf of the Renewable Energy
7 Coalition.
8 COMMISSIONER KJELLANDER: Let's see if we can't
9 get a microphone in front of you.
10
11
MR. SANGER: Thank you.
12 JOHN R. LOWE,
13 produced as a witness at the instance of the Renewable
14 Energy Coalition, having been first duly sworn to tell
15 the truth, the whole truth, and nothing but the truth,
16 was examined and testified as follows:
17
18
19
20 BY MR. SANGER:
DIRECT EXAMINATION
21 Q. Mr. Lowe, can you please state your name and
22 spell your last name?
23
24
A.
Q.
Yes, John R. Lowe, L-o-w-e.
In what capacity are you appearing today before
25 this Commission?
CSB REPORTING
[phone]
343 LOWE (Di)
Renewable Energy Coalition
1 A. I am the director of the Renewable Energy
2 Coalition.
3 Q. And are you the same John Lowe who filed
4 testimony in this proceeding on April 23rd, 2015?
5
6
A.
Q.
Yes, I am.
Do you have any corrections or changes to your
7 testimony?
8
9
A.
Q.
No, I don't.
And if I were to ask you the same questions
10 that are in your prefiled testimony today, would your
11 answers be the same?
12
13
A. Yes, they would.
MR. SANGER: I would move the prefiled direct
14 testimony to be spread onto the record as if those
15 questions were asked today.
16 COMMISSIONER KJELLANDER: And without
17 objection, we'll spread the testimony across the record
18 as if read. Hearing no objection, it is so ordered.
19 (The following prefiled testimony of
20 Mr. John R. Lowe is spread upon the record.)
21
22
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CSB REPORTING
[phone]
344 LOWE (Di)
Renewable Energy Coalition
1 I. INTRODUCTION
2
3
Q.
A.
Please state your name and business address.
My name is John R. Lowe. I am the director of
4 the Renewable Energy Coalition (the "Coalition"). My
5 business address is 12040 SW Tremont Street, Portland,
6 Oregon 97225.
7
8
Q.
A.
Please describe your background and experience.
In 1975, I graduated from Oregon State with a
9 B.S. I was employed by PacifiCorp for thirty-one years,
10 most of which was spent implementing the Public Utility
11 Regulatory Policies Act ("PURPA") regulations throughout
12 the utility's multi-state service territory. My
13 responsibilities included all contractual matters and
14 supervision of others related to both power purchases and
15 interconnections. Since 2009, I have been directing and
16 managing the activities of the Coalition as well as
17 providing consulting services to individual members
18 related to both power purchases and interconnections.
19 Q. On behalf of you are you appearing in this
20 proceeding?
21
22
23
A.
Q.
A.
I am testifying on behalf of the Coalition.
Please describe the Coalition and its members.
The Coalition was established in 2009, and is
24 comprised of thirty members who own and operate nearly
25 forty non-intermittent small renewable energy generation
345 Lowe, Di 1
Renewable Energy Coalition
1 qualifying facilities ("QFs") in Oregon, Idaho,
2 Washington, Utah, and Wyoming. Several types of entities
3 are members of the Coalition, including irrigation
4 districts, water districts, corporations, and
5 individuals. Except two, all are small hydroelectric
6 projects less than 7 megawatts. The Coalition's Idaho
7 members sell power to both Idaho Power Company and
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346 Lowe, Di la
Renewable Energy Coalition
1 PacifiCorp pursuant to PURPA contracts, all of which are
2 projects under the published rate eligibility cap.
3 Q. What are the Coalition's interests in this
4 proceeding?
5 A. The Coalition has a number of key interests in
6 this proceeding. First, our goal is to ensure fair and
7 reasonable contract terms and conditions, and avoided
8 cost rates for small projects under the published rate
9 eligibility cap. Second, the Coalition's members are
10 primarily existing QFs, and our goal is to ensure that
11 any final order in this proceeding recognizes and
12 accounts for the unique circumstances and benefits of
13 existing projects. Finally, the Coalition recognizes
14 that PURPA must work to benefit all interested parties,
15 including the utilities, ratepayers, and new and existing
16 QFs of various sizes. The Coalition's goal is that PURPA
17 policies account for all these interests, and the changes
18 (if any) adopted by the Idaho Public Utilities Commission
19 (the "Commission") are narrowly tailored to resolve
20 specific problems. Any policy changes should not unduly
21 harm any one, especially parties not causing the problems
22 that led to the utilities' filings.
23
24
Q.
A.
Please summarize your testimony.
The alleged problems facing Idaho Power,
25 PacifiCorp, and Avista are not being caused by small QFs
347 Lowe, Di 2
Renewable Energy Coalition
1 under the published rate eligibility cap, and any policy
2 changes that result from these proceedings should exempt
3 smaller projects. Second, I explain that there should be
4 no change in policy for existing projects under the rate
5 eligibility cap. Existing projects are also not causing
6 any problems, and in fact are providing significant
7 benefits to the utilities. In addition, imposing a
8 policy change like a shortened contract term
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348 Lowe, Di 2a
Renewable Energy Coalition
1 on existing QFs could have significant and unnecessary
2 harm on these projects, the utilities, and ratepayers.
3 Finally, the Coalition is not clear as to what the
4 recommendations of other parties will be in this
5 proceeding, and I intend to review these parties'
6 testimony and potentially respond in the next round of
7 testimony. For example, other parties may agree that
8 small projects under the published rate should not have
9 their contract terms shortened, which would reduce the
10 Coalition's need to participate in these proceedings.
11 II. THERE SHOULD BE NO POLICY CHANGES FOR SMALL AND
EXISTING PROJECTS UNDER THE RATE ELIGIBILITY CAP
12
13 Q. Please describe what you mean by small projects
14 under the published rate eligibility cap.
15 A. The rate eligibility cap is the maximum size
16 for a QF to be eligible to sell power at a utility's
17 published avoided cost rates. The current rate
18 eligibility cap is 100 kilowatts for wind and solar, and
19 10 average megawatts for all other generation resources
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Q.
A.
Is the rate eligibility cap important?
Yes. It is much more difficult for QFs to
22 negotiate contracts over the rate eligibility cap than
23 those below the cap. All states that I work in allow
24 smaller QFs to obtain published rates instead of
25 negotiating rates or having their rates determined by a
349 Lowe, Di 3
Renewable Energy Coalition
2 Q. Why are small projects treated differently than
1 utility computer model.
3 larger projects?
4 A. There are a number of important reasons for
5 treating smaller projects differently, some which include
6 developer sophistication, transaction costs, economies of
7 scale, and the inability to economically access
8 alternative markets. It is important to recognize the
9 unique difficulties facing smaller
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1 projects, and allowing smaller projects to sell power at
2 a published rate helps mitigate some of these
3 difficulties.
4 Negotiating contracts can be costly in terms of
5 upfront transactional costs. Small QFs do not typically
6 have in house attorneys and experts with the skills to
7 assist in the evaluation and negotiation of contracts.
8 Therefore, they often need to hire outside experts. In
9 addition, negotiating a QF contract with a utility can
10 take a great deal of time. All of these transactional
11 costs can impose significant economic burdens, and even
12 make a smaller project uneconomical.
13 Small projects also do not have the options
14 available to larger projects. For example, large scale
15 resources developed by utilities or large independent
16 power producers benefit from being sized so that the
17 dollar-per-kilowatt investment required to build the
18 plant is less than for a much smaller sized QF of the
19 same basic technology. Similarly, it is my understanding
20 that the typical short-term power sale trades in the
21 Pacific Northwest electricity market are for blocks of 25
22 MW power, and small QFs cannot effectively participate in
23 this market.
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25
Q.
A.
Please explain what you mean by existing QFs?
Existing QFs are those projects that are
351 Lowe, Di 4
Renewable Energy Coalition
1 already operating and are generally selling power to the
2 interconnected utility. Some of these projects have been
3 operating since the mid 1980s.
4 Existing projects face some unique challenges.
5 Existing projects must enter into a replacement power
6 purchase agreement ("PPA") when their current PPA
7 expires. This always means that their new PPA starts
8 during a
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1 term that includes an initial period of utility resource
2 sufficiency. Most existing projects have been operating
3 for years, and may require upgrading of their equipment
4 and facilities including interconnections. New
5 interconnection agreements are often required. There can
6 be significant costs involved in addressing these needs
7 or requirements.
8
9 QFs?
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Q.
A.
Are existing QFs treated differently than new
Yes. For example, existing QFs are included in
11 the utilities' resource plans. These QFs have been and
12 will continue to contribute to the utilities' capacity
13 needs, which justifies paying existing QFs a capacity
14 payment that recognizes their capacity value when they
15 renew their contracts regardless of the utilities'
16 resource position. Therefore, there is precedent for
17 recognizing that existing QFs should sometimes be treated
18 differently from new QFs given that they have been
19 selling, and are expected to continue to sell, power to
20 the utilities.
21 Q. Would changing PURPA policy to include a
22 two-year or other short contract term harm these existing
23 and small projects?
24 A. Yes. Currently, small QFs can enter into a
25 twenty-year contract term.
353 Lowe, Di 5
Renewable Energy Coalition
1 Renegotiating PPAs can be time consuming and costly,
2 especially for small and existing QFs, and could be
3 expected to be very burdensome if required every five
4 years or less. As I explained above, small existing
5 facilities nearly always do not have the option of
6 selling their power to other entities, and typically only
7 have the choice of continuing to sell their power to
8 their interconnected utility or shutting down. Also,
9 since existing QFs, especially small hydro projects that
10 are FERC licensed or exempted are not
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1 going mobile, there is no need to place a significant
2 burden and the cost of constantly entering into new
3 short-term contracts.
4 Significantly shortening the contract term for small
5 QFs would also harm the utilities and ratepayers. It is
6 my understanding that that small hydroelectric QFs below
7 the rate eligibility cap make up the majority of
8 individual PURPA projects. Idaho Power Petition at
9 17-18. According to Idaho Power, small hydroelectric
10 projects make up 68 of the total 133 that utility's PURPA
11 projects under contract. Id. at 18. Requiring the
12 utilities to renegotiate all of these small QF contracts
13 every two years, for example, would be costly for the
14 utilities. These unnecessary costs would be passed on to
15 ratepayers.
16 Q. Please describe the alleged problems facing the
17 utilities.
18 A. The utilities have supported their request to
19 reduce the contract term with claims regarding the harm
20 caused by new large wind and solar QFs. For example,
21 Idaho Power and PacifiCorp state that they have a large
22 amount of new wind and solar projects under contract, and
23 a large number of additional wind and solar QFs seeking
24 new contracts. They allege significant customer rate and
25 reliability concerns associated with this large amount of
355 Lowe, Di 6
Renewable Energy Coalition
1 large wind and solar QFs.
2 Q. Do you agree with the utilities that they are
3 facing significant problems associated with new PURPA
4 projects?
5 A. I have not independently verified the accuracy
6 of the utilities expected new QF contracts, rate impacts,
7 or reliability concerns. In my experience, not all of
8 the QFs that request contracts, or that even enter into
9 contracts, ever come
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1 on line. Utilities also typically over estimate the
2 costs and harms associated with QFs, and underestimate
3 their benefits. That said, I believe that the utilities
4 have raised legitimate concerns that warrant careful
5 review, and justify some changes in policy to account for
6 the significant volume of large scale intermittent QFs.
7 Q. How should the Commission address the alleged
8 problems facing the utilities?
9 A. I recommend that the Commission open a generic
10 investigation into PURPA issues to review whether other
11 solutions might better protect the utilities and
12 ratepayers without unduly harming QFs. There is no need
13 to make long-term decisions without considering all the
14 potential impacts and solutions.
15 The Commission should not revise PPA term limits
16 without a thorough review of the issues and potential
17 solutions typically achieved by a broader investigation.
18 By this, I mean that any solution should be narrowly
19 tailored to the specific problems that can be proven, and
20 should not cause unintended or harmful consequences.
21 Simply reducing the contract term may achieve the
22 utilities' goal of reducing the amount of QF development,
23 but it may not be the best solution to the problem of
24 large amounts of new wind and solar QFs. For example,
25 the Commission could instead revise avoided cost rates
357 Lowe, Di 7
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1 for certain QFs, better account for integration costs,
2 limit the amount of unneeded power that a utility must
3 purchase, or change the utilities' computer models.
4 I understand that many parties want the scope of the
5 proceeding to be narrow and only focus on the issue of
6 contract length, but the Commission should be aware that
7 there are other, potentially more appropriate, solutions.
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1 Q. Are small and existing projects contributing to
2 the utilities' alleged problems?
3 A. No. Assuming that all of the utilities alleged
4 problems are true, these problems are not being caused by
5 existing and small QFs.
6 For example, Idaho Power explains that the
7 hydroelectric projects under the rate eligibility cap
8 provide only 154 megawatts of the total current 1,302
9 megawatts of PURPA nameplate generation. Idaho Power
10 Petition at 18. While there is a large number of QFs
11 under the published rate eligibility cap, the total
12 megawatt size of these existing projects is small and not
13 causing the alleged rate or reliability concerns
14 identified by the utilities.
15 In fact, these projects provide Idaho Power with
16 significant benefits. For example, many of these
17 projects are seasonal, which means that they provide
18 Idaho Power with valuable capacity. Limiting the
19 contract length to these projects not only does not
20 address the problems identified by Idaho Power, but may
21 harm both Idaho Power and its ratepayers. The
22 Corrunission's final order in this proceeding should be
23 careful not to harm those QFs that are not contributing
24 to the problems faced by the utilities.
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359 Lowe, Di 8
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1 III. CONCLUSION
2 Q. Do other parties support your position that
3 projects under the rate eligibility cap should be exempt
4 from shortening the contract length?
5 A. Yes. It is my understanding that Idaho Power,
6 the Snake River Alliance, Twin Falls Canal Company, North
7 Side Canal Company and American Falls Reservoir District
8 No. 2, and AgPower, all support or do not oppose keeping
9 the current contract term for projects under the current
10 rate eligibility cap. We think it would be inappropriate
11 for the Commission to lower the contract term
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1 when Idaho Power has not requested such an action. Given
2 that Idaho Power did not request a lower contract term
3 for projects under the rate eligibility cap, it is likely
4 that there are parties that would have participated in
5 the case if they knew there was a chance that their
6 future contract terms could be shortened.
7 Given that it is unclear what other parties'
8 positions on this issue will be, the Coalition is only
9 submitting this limited testimony at this time. We will
10 review the testimony of other intervenors and may respond
11 to their arguments in rebuttal testimony.
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Q.
A.
Does this conclude your testimony?
Yes.
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1 {The following proceedings were had in
2 open hearing.)
3 MR. SANGER: And I tender Mr. Lowe for
4 cross-examination.
5 COMMISSIONER KJELLANDER: Thank you very much.
6 Let's start with Idaho Power.
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MR. WALKER: Thank you, Mr. Chairman.
CROSS-EXAMINATION
11 BY MR. WALKER:
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Q.
A.
Q.
Good afternoon, Mr. Lowe.
Hi, Donovan.
Mr. Lowe, your organization, membership of your
15 organization, is entirely comprised of projects which
16 would be considered under the published rate eligibility
17 cap; is that correct?
18 A. Almost. We have one project that would not.
19 Of course, they're in five different states, but if they
20 were all in the State of Idaho, they would all be below
21 the cap, except for one.
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Q.
A.
Which one is that?
We have a 30 megawatt biomass project called
24 Biomass One that's located in White City, Oregon.
25 Q. So barring that one project of 30 megawatts
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362 LOWE {X)
Renewable Energy Coalition
1 by the way, does that project sell to Idaho Power?
2
3
A.
Q.
No.
So none of your other Idaho projects would be
4 affected by the Company's request in this case; is that
5 correct?
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A.
Q.
Would you restate that one?
So none of your other Coalition member projects
8 which are under the published rate eligibility cap would
9 be affected by Idaho Power's request in this case; is
10 that correct?
11 A. No. We have members in the State of Idaho who
12 would be affected by this request.
13 Q. Okay, are you familiar with the Commission's
14 interim Order taking the contract term to five years
15 maximum?
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A.
Q.
Yes.
And you're aware that that Order applies only
18 to projects if you're over the published rate eligibility
19 cap?
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A.
Q.
A.
Q.
Yes.
So that wouldn't affect any of your projects?
No, that's correct, with that clarification.
And if I were to represent to you that Idaho
24 Power's request is also only for projects which are over
25 the published rate eligibility cap, would you agree that
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363 LOWE (X)
Renewable Energy Coalition
1 that doesn't affect your other members?
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3
A. Correct.
MR. WALKER: No further questions,
4 Mr. Chairman.
5 COMMISSIONER KJELLANDER: Thank you. Let's
6 move to Rocky Mountain Power.
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9 Avista?
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MS HOGLE: No questions.
COMMISSIONER KJELLANDER: No questions.
MR. ANDREA: No questions.
COMMISSIONER KJELLANDER: Staff for the Public
12 Utilities Commission.
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MS. HUANG: No questions.
COMMISSIONER KJELLANDER: Thank you. Mr.
15 Richardson.
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MR. RICHARDSON: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Ms. Howland.
MS. HOWLAND: No questions.
COMMISSIONER KJELLANDER: Mr. Arkoosh.
MR. ARKOOSH: No questions. Thank you.
COMMISSIONER KJELLANDER: Mr. Hammond.
MR. HAMMOND: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER KJELLANDER: Ms. Nunez.
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364 LOWE (X)
Renewable Energy Coalition
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MS. NUNEZ: No questions. Thank you.
COMMISSIONER KJELLANDER: Mr. Miller.
MR. MILLER: No, thank you, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Adams.
MR. ADAMS: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: And Mr. Otto.
MR. OTTO: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Are there
9 any questions from members of the Commission?
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COMMISSIONER RAPER: I have just one.
COMMISSIONER KJELLANDER: We have a question
12 from the Commission.
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16 BY COMMISSIONER RAPER:
EXAMINATION
17 Q. Mr. Lowe, I just have a question, you make a
18 comment at the bottom of page 6 of your testimony at line
19 23, the sentence starts, "In my experience, not all of
20 the QFs that request contracts, or that even enter into
21 contracts, ever come online," so my question to you would
22 be at what point do you think it would be reasonable for
23 the utilities to begin to include a proposed QF project
24 within their resource mix?
25 A. When they have a signed contract. I would be
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365 LOWE (Com)
Renewable Energy Coalition
1 glad to elaborate on that statement and the experience to
2 back it up. Going back to the beginning of PURPA in
3 about 1981, and a lot of you may recall, there was what
4 was referred to as a hydroelectric gold rush where
5 numerous, numerous projects around the country,
6 particularly the Northwest, were filing preliminary
7 permits and initiating FERC standing type of actions to
8 get in line for potential development of projects.
9 As one of the lead people for PacifiCorp at the
10 time, we were literally tracking, my recollection is,
11 somewhere nearly 3,000 projects, many of which were in
12 PacifiCorp's service territory. A lot of those were
13 hydro projects, of course, some of them weren't. After
14 that flurry of interest and activity, the company ended
15 up with about 70 contracts, and out of the 70 contracts,
16 I think we ended up with approximately, my recollection
17 is a little hazy after 30 years, but there was an
18 attrition of probably another 10 to 15 projects from
19 contracts signed to actual development, and so I think
20 that it probably would be fair and safe to say when you
21 actually have a contract signed, many times that's going
22 to result in a project and so it's probably an
23 appropriate time to consider it as part of your planning
24 process.
25 COMMISSIONER RAPER: Okay, thank you.
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366 LOWE (Com)
Renewable Energy Coalition
1 COMMISSIONER KJELLANDER: Mr. Sanger, do you
2 have any redirect?
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MR. SANGER: No, Your Honor.
COMMISSIONER KJELLANDER: Thank you. Mr. Lowe,
5 thank you very much for your testimony.
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THE WITNESS: Thank you.
COMMISSIONER KJELLANDER: And Mr. Sanger, did
8 you have any request of the Commission?
9 MR. SANGER: Yes, Your Honor, I would request
10 that Mr. Lowe be excused from further participation in
11 these proceedings as a witness in today and tomorrow's
12 hearing.
13 COMMISSIONER KJELLANDER: Thank you. Without
14 objection, we'll allow that to happen. Thank you, sir,
15 again for your testimony.
16 (The witness left the stand.)
17 COMMISSIONER KJELLANDER: Let's move now to
18 Mr. Miller with Intermountain Energy Partners.
19 MR. MILLER: Thank you, Mr. Chairman,
20 Intermountain Energy Partners would call Mark Van
21 Gulik.
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367 LOWE (Com)
Renewable Energy Coalition
1 MARK VAN GULIK,
2 produced as a witness at the instance of the
3 Intermountain Energy Partners, having been first duly
4 sworn to tell the truth, the whole truth, and nothing but
5 the truth, was examined and testified as follows:
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9 BY MR. MILLER:
DIRECT EXAMINATION
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Q.
A.
Q.
Sir, would you state your name, please?
Yes, it's Mark W. Van Gulik.
And the spelling of your last name for the
13 record, please?
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Q.
V-a-n G-u-1-i-k.
Mr. Van Gulik, are you the same Mark Van Gulik
16 who previously in this case had occasion to file prefiled
17 written testimony consisting of 10 pages?
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Q.
Yes.
Are there any additions or corrections to your
20 testimony?
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A.
Q.
No.
If I asked you the questions that are contained
23 in your written testimony today, would the answers that
24 are contained in your written testimony be the same?
25 A. Yes.
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368 VAN GULIK (Di)
Intermountain Energy Partners
1 Q. Are your answers true and correct to the best
2 of your knowledge?
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Q.
Yes.
MR. MILLER: Mr. Chairman, we'd request that
BY MR. MILLER: Oh, were there any exhibits
6 accompanying your testimony?
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A. No, there were not.
MR. MILLER: Mr. Chairman, we'd request that
9 the prefiled written testimony of Mr. Van Gulik be spread
10 on the record as if read and would tender the witness for
11 cross-examination.
12 COMMISSIONER KJELLANDER: Thank you, and
13 without objection, the direct testimony will be spread
14 across the record as if read.
15 (The following prefiled testimony of Mr. Mark
16 Van Gulik is spread upon the record.)
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369 VAN GULIK (Di)
Intermountain Energy Partners
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Q.
A.
Please state your name and business address.
Mark van Gulik, 1109 Main Street, Suite 402,
3 Boise Idaho.
4 Q. Please describe your educational and training
5 background.
6 A. I am a graduate with a Bachelor of Science in
7 Construction Management, Boise State University. I
8 worked as a Construction Professional in a capacity as a
9 Project Manager to Division Manager for over 27 years.
10 Beginning in 2010, I have worked specifically in the
11 Renewable Energy Market focusing on Solar Energy
12 Production. I have completed several courses relating to
13 the Solar Industry including the North American Board of
14 Certified Energy Practitioners, (NABCEP).
15 Q. Please describe your professional experience in
16 the electric power industry.
17 A. Beginning in 2010, I formed a Renewable Energy
18 Development firm, Sunergy World, Inc. and installed and
19 developed a variety of smaller projects (10 KW) to (100
20 KW) in eastern Oregon. I then continued the development
21 of a variety of larger Utility Scale Projects in Idaho,
22 Oregon and California. To date, I have been involved
23 with the completion of a 3 MW Distributed Solar Project
24 in California, a 500 KW Project in Oregon, and numerous
25 developments in Idaho including Boise City Solar (40 MW),
370 Van Gulik, Di 1
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1 Mt. Home Solar (20 MW), and Pocatello Solar (20 MW).
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Q.
A.
What is your current position?
I am a principal member and President of
4 Intermountain Energy Partners (IEP).
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Q.
A.
In what business is IEP engaged?
IEP is a utility scale alternative energy
7 development company, focusing on solar, wind, hydro, and
8 natural gas technologies in the North America markets.
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1 Q. Are you testifying today on behalf of
2 Intermountain Energy Partners?
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Q.
A.
Yes I am.
Please summarize your testimony.
Based on my experience in the industry
6 generally and based on our recent experience in Idaho in
7 particular, I will express two perspectives:
8 First, the downward trend in avoided cost
9 pricing in Idaho is such that fewer projects will be able
10 to obtain financing and there is not an urgency for the
11 Commission to shorten contract length, if the
12 Commission's goal is to slow down or stop the pace of
13 PURPA renewable energy development.
14 Second, the market for investment in energy
15 sales agreements with short durations of two to five
16 years is non-existent. The consequence of a Commission
17 order limiting energy sales agreements to two or five
18 years would be to bring any meaningful PURPA development
19 in Idaho to a halt.
20 Recent experience with pricing.
21 Q. Based on your experience in renewable energy
22 development, does IEP have connections with potential
23 equity investors and/or debt institutions in renewable
25 A. Yes. IEP has strong relationships with
372 Van Gulik, Di 2
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24 solar projects?
1 approximately 25 potential equity investors and 12
2 potential debt institutions. Our relationships include:
3 Fortune 100 companies, the largest vertically integrated
4 renewable energy companies in the United States market,
5 smaller niche companies, international companies, major
6 US Banks, and hard money lenders. These corporations
7 also include a number of top utility companies
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1 across the US interested in this type of investment that
2 will provide a long-term stable return.
3 Q. Based on this experience, are you familiar with
4 the criteria potential equity investors take into account
5 in evaluating potential equity investment in renewable
6 solar projects?
7 A. Yes I am. In general terms, as potential risk
8 increases, investors require correspondingly higher
9 returns. Currently the market is a seller's market for
10 viable renewable energy projects as the available equity
11 supply outpaces viable project demand. However, projects
12 still need to meet an acceptable risk profile for the
13 expected financial returns. The market has established
14 clear criteria required for projects at different risk
15 profiles. Examples of risk elements include: the status
16 of entitlements, tax treatment (sales income, property),
17 provisions in energy sales agreements that create
18 uncertainty (including the 90-110 provisions and a
19 provision triggering a material default in the event of
20 undefined material deviations from energy estimates in
21 recent Idaho Power contracts), power rates, ESA term
22 length, technology type, status of land control and
23 permitting, status of interconnection, environmental
24 impact studies, and many other minor elements.
25 Q. Has IEP developed PURPA solar projects in
374 Van Gulik, Di 3
Intermountain Energy Partners, LLC
1 Idaho?
2 A. Yes. IEP obtained from Idaho Power Company
3 (Idaho Power) Energy Sales Agreements for these projects:
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Boise City Solar-Case No. IPC-14-20 (20 MW)
Mountain Home Solar-Case No. IPC-14-26 (20MW)
375 Van Gulik, Di 3a
Intermountain Energy Partners, LLC
• 1
• 2
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6 Q.
7 today?
Pocatello Solar 1-Case No. IPC-14-27 ( 20MW)
Clark 1-Case No. IPC-14- 28 ( 71 MW)
Clark 2-Case No . IPC-14-29 (20 MW)
Clark 3-Case No. IPC-14- 30 ( 30 MW)
Clark 4-Case No. IPC-14-31 (20 MW)
What is the status of these projects as of
8 A. The Boise City, Mountain Home and Pocatello
9 projects have made security deposits required by the
10 Energy Sales Agreements, totaling approximately
11 $3,600,000 and IEP is in the process of finalizing
12 agreements with equity investors. The Clark projects were
13 unable to make security deposits by the required dates
14 and Idaho Power has terminated those ESAs.
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Q.
A.
What were the prices contained in the Energy
On a twenty year levelized basis, and taking
16 Sales Agreements for these projects?
18 into account the Corrunission approved Solar Integration
19 Charge, the "net prices" (levelized Price - levelized
20 Solar Integration Charge) were:
21 Boise City Solar-Case No. IPC-14-20 (20 MW):
22 $71.43
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• Mountain Home Solar-Case No. IPC-14-26 (20MW):
$59.42
Pocatello Solar 1-Case No. IPC-14-27 (20MW):
376 Van Gulik, Di 4
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$59.32
• Clark 1-Case No. IPC-14- 28 ( 71 MW) : $57.96
Clark 2-Case No. IPC-14-29 (20 MW) : $56.72
• Clark 3-Case No. IPC-14- 30 ( 30 MW) : $56.07
Clark 4-Case No. IPC-14-31 ( 20 MW) : $55.66.
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Interrnountain Energy Partners, LLC
1 Q. Did IEP expose the Energy Sales Agreements for
2 these projects to potential equity investors?
3 A. Yes. IEP expended considerable efforts
4 exposing those projects to potential equity investors
5 including many of the most reputable companies in the
6 market. In total, we put each of the projects in front
7 of at least four distinct financial companies that
8 conducted a thorough review process. This process
9 included site tours of each property along with extensive
10 due diligence that required many dedicated man-hours from
11 both IEP and these potential investment companies.
12 Q. In this process, did you learn of risks that
13 potential investors perceive with investment in Idaho
14 PURPA projects?
15 A. Yes. We learned investors perceive risk
16 resulting from a number of factors, most importantly
17 factors that create uncertainty. In regards to projects
18 in Idaho, the primary sources of perceived risk were: the
19 "90-110" provision in existing Energy Sales Agreements, a
20 contractual term in existing Energy Sales Agreements
21 triggering a material default for undefined ''material
22 deviations" from energy estimates, and the current and
23 future treatment of solar projects for state personal
24 property tax purposes. Each of these perceived risk
25 factors elevated the required equity investment return
378 Van Gulik, Di 5
Intermountain Energy Partners, LLC
1 threshold for individual projects primarily due to the
2 uncertainty perceived by equity investors.
3 Q. As net prices (defined above) ranged downward
4 from the $71.43 per MwH for Boise City Solar to $55.66
5 for Clark 4, did it become more difficult to attract
6 equity capital?
7 I
8
9 I
10
11 I
12
13
14
15
16
17
18
19
20
21
22
23
24
25
379 Van Gulik, Di Sa
Intermountain Energy Partners, LLC
1 A. Yes. Investors' interest in projects decreased
2 with decreasing net energy rates. The end result was the
3 inability of capital partners to post security deposits
4 for Clarks 1-4 even though Clark Solar 1-4 were evaluated
5 by the same capital groups that posted security deposits
6 for Boise Solar 1, Mountain Horne Solar 1, and Pocatello
7 Solar 1.
8 Q. Do you have any other projects in Idaho Power's
9 service territory that you have attempted to develop?
10 A. We have an additional 10 projects totaling
11 200MW that have requested and received 5 year indicative
12 pricing from Idaho Power. That pricing is below the
13 rates for Clark Solar 1-4, and we think it is highly
14 unlikely that they will attract equity investment with
15 the indicative pricing for 5 years provided by Idaho
16 Power in January. The perceived risk is much higher than
17 the perceived risk for Clark's 1-4, because the term is
18 only 5 years and not 20 years, and the other major
19 perceived risk issues remain. While we can only
20 speculate as to the perceived success of the remaining
21 projects Idaho Power has in their ESA queue, knowing that
22 this is a hot seller's market and no further ESAs have
23 been executed, is consistent with our experiences in the
24 Idaho market that current avoided cost pricing has
25 rendered further development very unlikely.
380 Van Gulik, Di 6
Interrnountain Energy Partners, LLC
1 Q. What conclusions have you drawn from your
2 recent experience in attempting to obtain equity
3 financing for Idaho renewable solar projects?
4 A. The equity investment companies we were working
5 with evaluated each project separately to create an
6 overall risk profile and projected financial forecast and
7 associated expected return. They would then evaluate the
8 strength of the return
9 I
10
11 I
12
13 I
14
15
16
17
18
19
20
21
22
23
24
25
381 Van Gulik, Di 6a
Intermountain Energy Partners, LLC
1 against the perceived risk profile and determine the
2 strength and viability of a project. This evaluation
3 process was not disclosed to us, but we were made aware
4 of the relative weakness of all projects. We were also
5 made aware of material changes to the perceived risk
6 profiles that increased or decreased the interest of each
7 capital partner for each project as those changes
8 happened. For risk elements that had high uncertainty,
9 typically the potential capital investor would use the
10 worst-case scenario to evaluate return potential,
11 reducing the interest in projects with a low return. Of
12 all the perceived risk components, the most chilling
13 effect has been seen for the projects with only 5 year
14 terms however, followed by the other uncertainties I have
15 mentioned above.
16 Q. What effect did the termination of the Clark
17 1-Clark 4 contracts have upon the total amount of PURPA
18 solar projects under contract but not yet constructed?
19 A. According to Exhibit 2, page 4 of 6
20 accompanying the testimony of Randy Alphin, as of January
21 30, 2015, there were 411 MW of Idaho solar PURPA
25 PURPA solar capacity under contract but not yet
23 that total, reducing the total to 270 MW.
22 contracts. The Clark projects accounted for 141 MW of
Based on your experience, is the amount of Q.
382 Van Gulik, Di 7
Intermountain Energy Partners, LLC
24
1 constructed a good predictor of the amount of solar PURPA
2 capacity that will actually come into existence?
3 A. As our experience indicates, even after
4 obtaining an executed Energy Sales Agreement, a developer
5 faces many hurdles before bringing a project on-line. A
6 signed Firm Energy Sales Agreement is not be any means a
7 guarantee of eventual success and requests for indicative
8 pricing is much less so.
9 I
10
11 I
12
13 I
14
15
16
17
18
19
20
21
22
23
24
25
383 Van Gulik, Di 7a
Intermountain Energy Partners, LLC
3 Q. You previously mentioned the IEP obtained
2 contract length.
1 Market for investment in renewable projects depending on
4 indicative pricing from Idaho Power for projects with
5 five year contract lengths. Based on your experience, do
6 you believe there is a market for equity investment in
7 five year contracts?
8 A. An investment in a five year contract would be
9 highly speculative-the investor would have to gamble that
10 prices for a subsequent replacement contract would be
11 higher or at least the same as the existing agreement.
12 We have not found any investors willing to undertake that
13 kind of speculation.
14 Q. Do you have specific projects with indicative
15 pricing from Idaho Power in Idaho?
16
17
A.
Q.
Yes.
Have you attempted to find equity investors
18 and/or debt lenders for those projects?
19
20
A.
Q.
Yes, as I have discussed above.
Has there been any interest from equity
21 investors and/or debt lenders for those projects?
22
23
A.
Q.
No.
What are the primary reasons given for the lack
24 of interest?
25 A. Utility scale renewable energy projects have an
384 Van Gulik, Di 8
Intermountain Energy Partners, LLC
1 amortization period longer than 5 years, typically 15-30
2 years. If the ESA term is shorter than the amortization
3 period, the project is considered speculative by
4 potential financing partners and is not typically
5 financeable as an independent power production facility.
6 Q. What is the shortest term that is typically
7 acceptable to potential financing partners in the United
8 States PURPA project market?
9 I
10
11 I
12
13 I
14
15
16
17
18
19
20
21
22
23
24
25
385 Van Gulik, Di Ba
Intermountain Energy Partners, LLC
1 A. I am aware of projects with an ESA with a
2 10-year term finding financing. However, that financing
3 has only been in states with attractive state tax
4 incentives. For states without attractive state tax
5 incentives, a 15-year term is typically the minimum term
6 required to attract market financing.
7 Q. Does Idaho have attractive state tax
8 incentives?
9
10
A.
Q.
No.
Is it reasonable to expect a shorter term to be
11 acceptable to potential financing partners for projects
12 that have attractive energy payments in Idaho?
13 A. No. Rates would need to be much higher than we
14 would expect in Idaho for a term shorter than 15 years to
15 be attractive to investors due to our lack of state tax
16 incentives. They would have to be even higher yet for a
17 term shorter than 10 years to be attractive to investors.
18 Since energy rates have been dropping for each successive
19 issued indicative pricing and integration charges have
20 been increasing it is reasonable to assume the
21 combination of projected energy rates with shorter terms
22 will not be acceptable to financing partners in the near
23 or medium term future. This effect is further compounded
24 by the reduction in the federal Investment Tax Credit
25 from 30% to 10% at the end of 2016.
386 Van Gulik, Di 9
Intermountain Energy Partners, LLC
1 Conclusion.
2 Q. Based on your testimony, do you have any
3 concluding observations for the Commission?
4 A. In my testimony, I have not touched on issues
5 such as the legality of reducing contract lengths to the
6 levels proposed by the utility companies and associated
7 public policy
8 I
9
10 I
11
12 I
13
14
15
16
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18
19
20
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22
23
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25
387 Van Gulik, Di 9a
Intermountain Energy Partners, LLC
1 considerations. I have, however, attempted to
2 demonstrate that the downward trend in avoided cost
3 pricing coupled with increasing integration charges will
4 likely slow the pace of solar PURPA development in Idaho.
5 I therefore think it would be premature for the
6 Commission to reduce contract lengths as requested by the
7 utility companies because that would certainly bring
8 further renewable development under PURPA to an immediate
9 halt.
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Q.
A.
Does that conclude your testimony?
Yes it does.
388 Van Gulik, Di 10
Intermountain Energy Partners, LLC
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER KJELLANDER: And we will begin
4 with Mr. Walker.
5
6
7
8
10 Q.
MR. WALKER: Thank you, Mr. Chairman.
CROSS-EXAMINATION
Mr. Van Gulik, in a general sense, your
9 BY MR. WALKER:
11 testimony provides that you've -- you have a lot of
12 contacts in the financial world and that, in your
13 experience, they wouldn't finance projects, PURPA
14 projects, under a short-term contract because they feel
15 that's too risky.
16
17
A.
Q.
That is correct.
So let me ask you if that same risk that's too
18 risky for the financial community to take on, Idaho Power
19 and its customers take that risk in a long-term contract,
20 PURPA contract, don't they?
21 A. In some respects, yes, but in other respects
22 you've also determined that predetermined price rate for
23 the length of the contract, so if prices were to go up
24 and escalate, we have, you have, a guaranteed rate that's
25 published through the 20-year length of the contract.
CSB REPORTING
[phone]
389 VAN GULIK (X)
Intermountain Energy Partners
1 Q. So let me ask you about the development model
2 for your projects. In your proposed projects that were
3 under contract or are under contract with Idaho Power,
4 were they set up as limited liability companies?
5
6
A.
Q.
Initially, yes.
And did they have any assets or collateral that
7 they could put up to shoulder some of that risk of
8 financing?
9 A. The companies that were set up were a single
10 purpose entity and it was a vehicle to contract with all
11 of the land lease agreements, power purchase agreements
12 that made up the assets of that single purpose entity,
13 and that entity was then transferred to the finance or
14 the buyer of the project.
15
16
17
18
19
Q.
A.
Q.
So your answer would be no, then?
Yes, it would.
And so wouldn't -- strike that.
No further questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Let's
20 move to Avista.
21
22
MR. ANDREA: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you.
23 PacifiCorp.
24
25
MS HOGLE: No questions, thank you.
COMMISSIONER KJELLANDER: Mr. Howell.
CSB REPORTING
[phone]
390 VAN GULIK (X)
Intermountain Energy Partners
1
2
MS. HUANG: No questions, thank you.
COMMISSIONER KJELLANDER: Thank you.
3 Mr. Adams.
4
5 you.
MR. ADAMS: No questions, Mr. Chairman. Thank
6 COMMISSIONER KJELLANDER: Thank you. Mr.
7 Richardson.
8
9
10
11
12 Ms. Nunez.
13
MR. RICHARDSON: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Mr. Otto.
MR. OTTO: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you.
MS. NUNEZ: No questions, thank you.
14
15
16
17
18
19
COMMISSIONER KJELLANDER: Mr. Olsen.
MR. OLSEN: Yes, I have some questions.
COMMISSIONER KJELLANDER: Please proceed.
CROSS-EXAMINATION
20 BY MR. OLSEN:
21 Q. Mr. Van Gulik, you characterize your testimony
22 or Idaho Energy Partners as being on page 1, line 21, a
23 utility scale alternative to energy -- a utility scale
24 alternative energy development company; is that right?
25 A. That's correct.
CSB REPORTING
[phone]
391 VAN GULIK (X)
Intermountain Energy Partners
1 Q. Okay, and up further in answer to a question
2 beginning on line 10, you talk about the renewable
3 projects that you've dealt with from the 10 kilowatt to
4 100 kilowatt thing. Isn't it fair to say that Idaho
5 Energy Partners would -- the market you address is more
6 on the 10 to 500 megawatt range as opposed to 10 to 100
7 kilowatt range?
8 A. Could you please repeat the question? I'm
9 sorry.
10 Q. Would it be fair to say that your business,
11 Idaho Energy Partners, is in the business of developing
12 projects in the scale of 10 to 500 megawatts as opposed
13 to the 10 to 100 kilowatts that you had experience
14 with?
15 A. We actually have a diverse portfolio and a
16 diverse business plan and in the last year we were
17 focused in on the large scale utility projects and
18 currently we're now focusing on more of the smaller scale
19 projects.
20 Q. Okay. Turning to page 2, you indicate down
21 beginning on line 18 that you have a lot of
22 relationships, and I think Mr. Walker kind of sununarized
23 that, you know, with investors, bankers, that type of
24 thing, so would it be fair to say that you only deal with
25 larger entities as opposed to smaller ones?
CSB REPORTING
[phone]
392 VAN GULIK (X)
Intermountain Energy Partners
1 A. Not exactly true. We're working currently with
2 two forms of financial vehicles, if you will. One is a
3 smaller boutique firm and the other is a large national
4 bank, if you will.
5 Q. Okay. Are any of these potential investors you
6 discuss here from Idaho?
7 A. Currently, no, but we're in discussions with
8 Idaho-based companies currently.
9 Q. So is it fair to say that your pool of
10 investors or other hard money lenders have no concerns
11 for Idaho or attachments to Idaho?
12
13
14
A.
Q.
A.
That wouldn't be an accurate statement, no.
Why wouldn't it be?
Because when they enter the state, they will be
15 paying property tax here in the state and they do have an
16 investment in the State of Idaho.
17 Q. So certainly a return on investment is what
18 they're looking at as opposed to the good of Idaho
19 ratepayers or Idahoans in general?
20
21
A.
Q.
That's a fair assessment, sure.
Now, when you talk about risk, you always say
22 the higher the risk the higher the return, the return
24
25
A.
Q.
Yes.
Okay; so the main driving force here for these
23 needed to attract the money; is that correct?
CSB REPORTING
[phone]
393 VAN GULIK (X)
Intermountain Energy Partners
1 investors is not for the good of Idaho or Idaho
2 ratepayers or renewable energy, it's just a good return;
3 isn't that fair to say?
4 A. I can't really answer that. Some of the
5 investors have an internal goal to invest in renewable
6 energy, so I wouldn't say that's an accurate statement.
7 It's not all about the return on investment.
8 Q. Okay, fair enough. Now, on the same page 2
9 where you give your general perspectives here, the first
10 one you talk about the downward, I guess, trend in the
11 pricing for PURPA projects, specifically the solar here.
12 By trending downward, do you mean like on page 4, your
13 line 16 through 23, where the prices have dropped from
15
16
A.
Q.
Correct.
Okay. Now, with respect to the lowest figure,
14 $71.00 to $55.00, approximately?
17 $55.66, do you think it's appropriate for the Company and
18 its ratepayers to pay $55.00 that displaces its own
19 resource at $30.00?
20 A. Going back to Randy Allphin's testimony, that's
21 all done with the IRP method, so in the basis of asking
22 me that question, I think that's a fair and reasonable
23 price to pay, yes.
24 Q. Well, the IRP method doesn't ask the question
25 of whether it's needed or not. You know, if you can
CSB REPORTING
[phone]
394 VAN GULIK (X)
Intermountain Energy Partners
1 still produce power with your own resources at a lower
2 amount, why would it be fair to purchase power at a
3 higher amount when you already have that in your resource
4 stack?
5 A. In our belief, we think it's a better project
6 because we're delivering energy at the time of need.
7 Q. Well, with respect to the lowest figure there
8 on page 4 that's $55.66, do you believe it's appropriate
9 for the Company and the ratepayers to pay $55.66 for
10 power that displaces possible market power purchases in
11 the 10 to $20.00 range?
12 A. I think you would have to look at the
13 time-of-day pricing, also, to answer that question
14 accurately.
15 Q. Yeah, certainly it does shift depending on
16 whether it's a load or no load area. Now, with respect
17 to the term in the market or, I guess, the contract
18 period, your second perspective talks about that. Do you
19 see that beginning on line 10, talking about durations of
20 two to five years, that there is really a non-existent
21 market? With respect to that, I guess, your perspective
22 that you're putting here, if the current avoided cost
23 price is above the actual cost that Idaho Power can
24 obtain power for, do you think it's just and reasonable
25 for the Idaho ratepayers and Idaho Power to offer
CSB REPORTING
[phone]
395 VAN GULIK (X)
Intermountain Energy Partners
1 contracts for two, five, or even 20 years?
2 A. Again, according to -- yes, I do think it's
3 reasonable.
4
5
Q.
A.
And why would you think that's reasonable?
Because we believe that the pricing is fair in
6 the way it's calculated.
7 Q. Well, at this point in time certainly Idaho
8 Power, Avista, and Rocky Mountain Power have come forward
9 and shown or are asking the Commission to look at the
10 issue and there appears to be a disconnect, and certainly
11 how they have come about it is looking at the contract
12 term to reduce the risk, I guess, down to a reasonable
13 level for its company and also ratepayers; however,
14 another way to look at it is more of a pricing issue;
15 would that be fair to say? In other words, if the price
16 was appropriate, if it was appropriately priced at any
17 given time, whether it was variable over the term of the
18 contract or going into the contract, that would be
19 another way to address the issue that the company is
20 raising or the companies are raising here in this case?
21 A. Again, I think they are coming up -- they're
22 using their analysis and their tools to come up with this
23 price. I think that question -- if we offered a price
24 and they accepted it, I think that would be a different
25 discussion, but, again, they are the ones, the companies
CSB REPORTING
[phone]
396 VAN GOLIK (X)
Intermountain Energy Partners
1 are the ones, that are determining these prices using the
2 models and all of the variable inputs.
3
4
MS. OLSEN: No further questions, Mr. Chair.
COMMISSIONER KJELLANDER: Thank you.
5 Mr. Sanger.
6
7
8
MR. SANGER: No questions, Your Honor.
COMMISSIONER KJELLANDER: Mr. Hammond.
MR. HAMMOND: No questions, Chairman
9 Kjellander.
10
11
12
COMMISSIONER KJELLANDER: Mr. Arkoosh.
MR. ARKOOSH: No, thank you, Your Honor.
COMMISSIONER KJELLANDER: And none from Ms.
13 Howland. Any from members of the Commission? And I
14 think there is an opportunity for redirect, Mr. Miller,
15 very limited opportunity.
16
17
18
19
MR. MILLER: Just a couple, Mr. Chairman.
REDIRECT EXAMINATION
20 BY MR. MILLER:
21 Q. Mr. Van Gulik, in the course of developing
22 solar projects, have you had discussions with owners of
23 agricultural properties about siting projects on
24 agricultural properties?
25 A. Yes, we have.
CSB REPORTING
[phone]
397 VAN GULIK (Di)
Intermountain Energy Partners
1
2
3
Q.
A.
Q.
And have any of those developed into leases?
Yes, they have.
Have you found that in the course of those
4 discussions the owners of agricultural properties are
5 interested in profit?
6
7
A.
Q.
Sure, yes.
All right, have any of those owners of
8 agricultural properties who have entered into leases
9 offered to take some kind of a discount for the good of
10 Idaho?
11 MR. WALKER: Mr. Chairman, I object to the
12 leading nature of these questions. This is redirect and
13 it's also questionable as to if he's beyond the scope of
14 the cross-examination.
15
16
17 Q.
COMMISSIONER KJELLANDER: Mr. Miller.
MR. MILLER: I could rephrase it.
BY MR. MILLER: Have any -- could you tell us
18 what as far as you can tell the criteria agricultural
19 lessors have taken into account in determining a lease
20 amount?
21 A. Those lease amounts are all determined by
22 market and the early leases that we signed were at a
23 lower rate than the leases that we are signing now, so
24 it's market driven.
25 MR. MILLER: All right, that's about it.
CSB REPORTING
[phone]
398 VAN GULIK (Di)
Intermountain Energy Partners
1 That's all I have.
2 COMMISSIONER KJELLANDER: Thank you. We
3 appreciate your testimony. Thank you for your
4 participation today.
5
6
7
THE WITNESS: Thank you.
(The witness left the stand.)
COMMISSIONER KJELLANDER: Mr. Miller, were you
8 seeking to have your witness excused?
9 MR. MILLER: Mr. Chairman, with the permission
10 of the Commission and the parties, the indulgence of the
11 parties, we would ask that Mr. Van Gulik be excused from
12 further attendance.
13 COMMISSIONER KJELLANDER: And without
14 objection, it is permitted.
15 MR. MILLER: While I'm here, this morning I
16 neglected to move for the admission of Exhibits 401 and
17 402 and perhaps I could do that at this time.
18 COMMISSIONER KJELLANDER: Identified and marked
19 as 401 and 402, without objection, are then marked and
20 identified.
21 (Idaho Energy Partners Exhibit Nos. 401 and 402
22 were marked for identification.)
23 COMMISSIONER KJELLANDER: Thank you, Mr.
24 Miller. Let's get back to my list and let's move to
25 Avista Corporation.
CSB REPORTING
[phone]
399 VAN GULIK (Di)
Intermountain Energy Partners
1
2
3
4
5 here.
6
7
MR. OTTO: Mr. Commissioner?
COMMISSIONER KJELLANDER: Yes.
MR. OTTO: We also have my two witnesses and
COMMISSIONER KJELLANDER: I'm aware you're
MR. OTTO: I just wanted to make sure.
COMMISSIONER KJELLANDER: I haven't forgotten
8 you, but I'd kind of like to see if we couldn't get a
9 little further down the road with some of the
10 applicants.
11
12
MR. OTTO: Of course.
MR. ANDREA: Mr. Chairman, Avista calls Clint
13 Kalich as its witness.
14
15
COMMISSIONER KJELLANDER: Thank you.
16 CLINT KALICH,
17 produced as a witness at the instance of Avista
18 Corporation, having been first duly sworn to tell the
19 truth, the whole truth, and nothing but the truth, was
20 examined and testified as follows:
21
22
23
24 BY MR. ANDREA:
DIRECT EXAMINATION
25 Q. Can you please state your name for the
CSB REPORTING
[phone]
400 KALICH (Di)
Avista Corporation
1 record?
2
3
A.
Q.
My name is Clint Kalich.
And by whom are you employed and in what
4 capacity?
5 A. I work for Avista Corporation as the manager of
6 resource planning and power supply analyses.
7 Q. And did you file the direct and rebuttal
8 testimony of Clint Kalich in this case?
9
10
A.
Q.
I did.
If you were asked the same questions in your
11 direct and rebuttal testimony today, would your answers
12 be the same as those provided in that prefiled direct and
13 rebuttal testimony?
14
15
A. Yes.
MR. ANDREA: Mr. Chairman, I request that Mr.
16 Kalich's direct and rebuttal testimony be spread into the
17 record as though read therein.
18 COMMISSIONER KJELLANDER: Thank you. Without
19 objection, we will spread the direct and rebuttal
20 testimony of Mr. Kalich across the record as if read. No
21 objection, it is so ordered.
22 (The following prefiled direct and rebuttal
23 testimony of Mr. Clint Kalich is spread upon the record.)
24
25
CSB REPORTING
[phone]
401 KALICH (Di)
Avista Corporation
10 Avista Utilities.
6 Washington.
I. INTRODUCTION
Please state your name, the name of your
My name is Clint Kalich. I am employed by
I am the Manager of Resource Planning & Power
In what capacity are you employed?
Please state your educational background and
A.
Q.
A.
Q.
Q.
1
4
2
7
8
9 Supply Analyses in the Energy Resources Department of
3 employer, and your business address.
5 Avista Corporation at 1411 East Mission Avenue, Spokane,
11
12 professional experience.
13 A. I graduated from Central Washington University
14 in 1991 with a Bachelor of Science Degree in Business
15 Economics. Shortly after graduation, I accepted an
16 analyst position with Economic and Engineering Services,
17 Inc. (now EES Consulting, Inc.), a Northwest
18 management-consulting firm located in Bellevue,
19 Washington. While employed by EES, I worked primarily
20 for municipalities, public utility districts, and
21 cooperatives in the area of electric utility management.
22 My specific areas of focus were economic analyses of new
23 resource development, rate case proceedings involving the
24 Bonneville Power
25 I
402 Kalich, Di 1
Avista Corporation
1 Administration, integrated (least-cost) resource
2 planning, and demand-side management program development.
3 In late 1995, I left Economic and Engineering
4 Services, Inc. to join Tacoma Power in Tacoma,
5 Washington. I provided key analytical and policy support
6 in the areas of resource development, procurement, and
7 optimization, hydroelectric operations and re-licensing,
8 unbundled power supply rate-making, contract
9 negotiations, and system operations. I helped develop,
10 and ultimately managed, Tacoma Power's industrial market
11 access program serving one-quarter of the company's
12 retail load.
13 In mid-2000 I joined Avista Utilities and accepted
14 my current position assisting the Company in resource
15 analysis, dispatch modeling, resource procurement,
16 integrated resource planning (IRP), and rate case
17 proceedings. Much of my career has involved resource
18 dispatch modeling of the nature described in this
19 testimony.
20 Q. What relief is the Company requesting in this
21 proceeding?
22 A. Avista requests the Corrunission provide the
23 Company the same relief granted Idaho Power in Order No.
24 33222, namely to limit the maximum required contract
25 I
403 Kalich, Di 2
Avista Corporation
1 terms for "IRP Methodology" wind and solar PURPA
2 contracts to five (5) years. A term beyond five (5)
3 years should be an option for the utility in the event a
4 very favorable PURPA opportunity arises. Avista also
5 requests that the Commission provide the Company with any
6 other interim or final relief granted to any other
7 utility subject to PURPA in the State of Idaho.
8
9
Q.
A.
Why is Avista requesting relief?
Developers generally look for the highest
10 returns on their projects, including the certainty of
11 long-term fixed-price contracts. QF developers appear to
12 prefer longer-term contracts. This may be because the
13 long-term price certainty makes it easier to finance
14 their projects. The Idaho experience with wind, and now
15 solar, bears this out. Developers have consistently
16 favored Idaho Power, the utility with the highest
17 calculated avoided cost rates for PURPA projects ("QFs")
18 that qualify for such rates. Accordingly, if Avista is
19 required to enter into QF contracts with a longer term
20 than Idaho Power is required to enter, QF developers may
21 choose a longer-term contract with Avista rather than a
22 five-year contract with Idaho Power.
23 Q. Can you provide a specific example illustrating
24 how a PURPA developer might choose a 20-year contract
25 I
404 Kalich, Di 3
Avista Corporation
1 from Avista rather than a five-year contract from Idaho
2 Power?
3 A. Yes. Kootenai Electric Cooperative
4 ("Kootenai"), located in the state of Idaho, requested an
5 Oregon 20-year PURPA contract from Idaho Power for its
6 landfill gas project. This was rational economic
7 behavior because the terms of Idaho Power's Oregon PURPA
8 contract were, even with some additional transmission
9 costs, more favorable at that time than the alternatives,
10 including a long-term contract with Kootenai's
11 neighboring utility, Avista.
12 Due to a dispute over the delivery point, Kootenai
13 decided that during the dispute it would deliver the
14 output from its QF to Avista under a short-term QF
15 contract. Again, this decision demonstrated rational
16 economic behavior because, while Avista's long-term rates
17 were much lower than Idaho Power's, Avista's short-term
18 rates were similar to Idaho Power's short-term rates. By
19 selling to Avista under a short-term QF contract,
20 Kootenai was able to retain flexibility to enter into a
21 long-term Oregon QF contract with Idaho Power if it
22 prevailed in its dispute and, in the interim, could
23 obtain a rate from Avista similar to Idaho Power's.
24 I
25 I
405 Kalich, Di 4
Avista Corporation
1 Q. Did Kootenai make any other decisions that, in
2 your opinion, demonstrate the tendency of PURPA
3 developers to seek the best overall prices and terms for
4 their output?
5 A. Yes. Though Kootenai's project was located in
6 Idaho, it chose to sell its output to Idaho Power in
7 Oregon where the terms of Idaho Power's PURPA contracts
8 were even more favorable than in the state of Idaho. In
9 fact, in order to obtain an Oregon QF contract from Idaho
10 Power, Kootenai took the issue regarding whether its
11 output would be delivered to Idaho Power in Idaho or in
12 Oregon to the Federal Energy Regulatory Commission
13 ("FERC"). Kootenai ultimately obtained a ruling that its
14 output would be delivered to Idaho Power in Oregon. This
15 later step demonstrates just how sophisticated and
16 motivated PURPA developers are to identify and obtain the
17 PURPA contract with the most favorable terms.
18 Q. Do you think that PURPA developers might find a
19 20-year PURPA contract with Avista more favorable than a
20 five-year contract with Idaho Power?
21 A. Yes. As explained above, developers look for
22 the PURPA contract with the terms that are most favorable
23 to them. PURPA rates for a 20-year term are generally
24 higher than PURPA rates for a 5-year term. Therefore, in
25 I
406 Kalich, Di 5
Avista Corporation
1 the absence of the ability to obtain a 20-year Idaho
2 Power PURPA contract, wind and solar developers likely
3 will pursue longer-term contracts with Avista.
4
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Q.
A.
Does this conclude your testimony?
Yes.
24
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407 Kalich, Di 6
Avista Corporation
1 Q. Please state your name, the name of your
2 employer, and your business address.
3 A. My name is Clint Kalich. I am employed by
4 Avista Corporation ("Avista") at 1411 East Mission
5 Avenue, Spokane, Washington.
6 Q. Did you provide direct testimony in this
7 proceeding?
8 A. Yes. I filed direct testimony in this
9 proceeding on behalf of Avista Corporation on February
10 27, 2015.
11 Q. Please summarize Avista's position in this
12 case.
13 A. As stated in my direct testimony beginning on
14 page 2 at line 22:
15 Avista requests the Commission provide the Company
the same relief granted Idaho Power in Order No.
16 33222, namely to limit the maximum required contract
terms for "IRP Methodology" wind and solar PURPA
17 contracts to five (5) years. A term beyond five (5)
years should be an option for the utility in the
18 event a favorable PURPA opportunity arises. Avista
also requests that the Commission provide the
19 Company with any other interim or final relief
granted to any other utility subject to PURPA in the
20 State of Idaho.
21 Q. Parties to this docket have introduced evidence
22 addressing many issues in addition to the issue of the
23 appropriate contract term for Qualifying Facilities
24 ( "QFs") . Does Avista believe the Commission should
25 broaden the docket beyond the issue of the appropriate
contract term for QFs?
408 Kalich, Di -Reb 1
Avista Corporation
1 A. No, Avista believes the Commission should focus
2 exclusively on the issue of the appropriate contract term
3 for QFs, for reasons explained below.
4 Q. Some parties to this case appear to advocate
5 re-opening the IRP methodology? Does Avista see a need
6 to do so?
7 A. No. In Avista's view, the existing avoided
8 cost methodology works well. The IRP methodology allows
9 Avista to account for its needs while providing QFs an
10 avoided cost rate that reflects Avista's actual avoided
11 cost. Further, there is insufficient information in the
12 record for the Commission to make an informed
13 determination on any changes to the IRP Methodology. In
14 the event that the Commission decides to revisit the IRP
15 Methodology, a new generic docket should be initiated for
16 that purpose to ensure that all parties have an
17 opportunity to develop a complete record. However, I
18 emphasize that Avista does not believe any changes to the
19 IRP methodology are warranted, so a generic docket is not
20 necessary.
21 Q. Does Avista take any position on the
22 non-variable IRP Methodology contract term or Staff's
23 position that SAR-based contracts retain the flexibility
24 to extend out 20 years at the option of the QF?
25 I
409 Kalich, Di-Reb 2
Avista Corporation
1 A. No. Avista's interest, as explained in its
2 petition and my testimony, is to ensure a level playing
3 field across the Commission-regulated utilities. To the
4 extent the Commission makes changes affecting any QF
5 resource type, Avista should be afforded similar
6 treatment to ensure that a level playing field is
7 maintained.
8 Q. Do you support the five-year maximum term for
9 QF contracts?
10 A. Yes, but with a caveat. Avista believes that
11 the five-year term should be a maximum required term. In
12 other words, utilities should be allowed to contract for
13 longer terms where such terms are found by Avista and the
14 IPUC to be in the interest of utility customers. It is
15 not possible to know every circumstance where a longer
16 term agreement may be warranted.
17 Q. Idaho Conservation League and Sierra Club
18 witness Mr. Wenner states in his direct testimony that an
19 !PUC order establishing a maximum required term of
20 two-years for Idaho QF PURPA contracts would not be
21 consistent with PURPA or FERC's regulations thereunder.
22 Do you agree?
23 A. No. As Mr. Sterling notes in his direct
24 testimony beginning on page 10, FERC regulations
25 implementing PURPA are silent on contract length and
410 Kalich, Di-Reb 3
Avista Corporation
1 20-year contract terms may be inconsistent with PURPA.
2 The Fifth Circuit recently
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411 Kalich, Di-Reb 3a
Avista Corporation
1 stated in Exelon Wind 1, 1.1.C. v. Nelson, 766 F.3d 380,
2 400 (5th Cir. 2014) ("Nelson") that:
3 mandatory long-term contracts between generators and
utilities can burden customers by imposing prices
4 well above the actual market prices. The [Texas
Public Utility Commission) made a reasonable
5 decision that only those Qualifying Facilities
capable of providing reliable and predictable power
6 may enter into such [long-term) arrangements.
7 Mr. Wenner himself acknowledges, at line 7 on page 5
8 of his testimony, that there is no FERC regulation
9 specifying the number of years, or other time period, for
10 the term over which the QF, which accepts a legally
11 enforceable obligation, is entitled to receive avoided
12 cost rates calculated at the time the obligation is
13 incurred.
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Q.
A.
Does this conclude your testimony?
Yes.
412 Kalich, Di-Reb 4
Avista Corporation
1 (The following proceedings were had in
2 open hearing.)
3 COMMISSIONER KJELLANDER: And let's move
4 forward with Mr. Howell.
5 MS. HUANG: Actually, Ms. Huang for this
6 witness. No questions, Mr. Chairman.
7
8 Walker.
9
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. WALKER: No questions from Idaho Power,
10 Mr. Chairman.
11 COMMISSIONER KJELLANDER: Questions from
12 PacifiCorp.
13 MS. HOGLE: Rocky Mountain Power has no
14 questions. Thank you.
15 COMMISSIONER KJELLANDER: Thank you. Let's
16 see, Mr. Adams.
17 MR. ADAMS: Simplot will have no questions for
18 this witness.
19 COMMISSIONER KJELLANDER: Thank you, Mr. Adams.
20 Mr. Richardson.
21 MR. RICHARDSON: Thank you, Mr. Chairman.
22 Clearwater does have a couple of questions.
23
24
25
COMMISSIONER KJELLANDER: Please proceed.
MR. RICHARDSON: Thank, you Mr. Chair.
CSB REPORTING
[phone]
413 KALICH
Avista Corporation
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CROSS-EXAMINATION
BY MR. RICHARDSON:
Q. Good afternoon, Mr. Kalich.
A. Good afternoon.
Q. Now, you're not alleging, are you, that Avista
is facing a lot of QF contract requests or has had a lot
of recently signed PURPA contracts, are you?
9 A. We have not received a number of requests nor
10 have we signed any contracts.
11 Q. So how many solar QF contracts has Avista
12 signed that are large enough to have rates set by the IRP
13 methodology?
14
15
17
A.
Q.
A.
Zero.
How many megawatts of Idaho-based PURPA
Mr. Richardson, I knew you were going to ask me
16 contracts does Avista currently have online?
18 that question right as a follow-up, I don't have that
19 statistic in front of me. It is published in our
20 integrated resource plan if you have some data, subject
21 to check.
22 Q. Would you accept, subject to check, that it's
23 eight megawatts?
24
25
A.
Q.
In total?
Online Idaho QF contracts.
CSB REPORTING
[phone]
414 KALICH (X)
Avista Corporation
1
2
A.
Q.
That sounds right, subject to check.
So on page 3 of your rebuttal testimony, you
3 were asked whether you agree with the ICL and Sierra Club
4 witness when he testified that a two-year contract term
5 would be inconsistent with PURPA and FERC's regulations.
6 Do you see that?
7 A. Could you repeat the cite again? I somehow
8 grabbed my direct.
9
10
Q.
A.
That's page 3 of your rebuttal testimony.
What line were you referring to,
11 Mr. Richardson?
12
14
15
Q.
A.
Q.
Line 16 is the question. You were asked
Yes, I did.
And then in your answer, you refer to a -- you
13 whether or not you agree and you testified no.
16 say on the bottom of the page, you say, The Fifth Circuit
17 recently stated in Exelon Wind v. Nelson, do you see
18 that?
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A. Yes.
Q. Do you know what circuit Idaho is in?
A. Certainly not that circuit.
Q. Do you know what circuit Idaho is in?
A. I should, but I cannot recall.
Q. Okay; so then you probably don't have an
25 opinion as to how this case would be decided in the
CSB REPORTING
[phone]
415 KALICH (X)
Avista Corporation
1 circuit in which Idaho is located?
2 A. I believe that's what we're here for today or
3 at least to set some record there. The representation I
4 made was only to the effect that there have been issues
5 where the commissions can set not only, amongst other
6 things, the term of the agreement, and further in the
7 Texas, the proceeding here for resources such as wind and
8 solar, in fact, long-term contracts were not even offered
9 to those individuals, but
10 Q. So the question was do you have an opinion as
11 to how this case would be decided in the circuit in which
12 Idaho is located?
13 MR. ANDREA: Mr. Chairman, I object to the
14 question. It calls for speculation and it's really
15 beyond the scope of his testimony.
16 MR. RICHARDSON: Mr. Chairman, I was just
17 asking if the witness had an opinion on that topic. I
18 wasn't asking him to speculate. I was asking him if he
19 had an opinion and what it is.
20 COMMISSIONER KJELLANDER: Are you asking him
21 for a legal opinion?
22
23 opinion.
24
MR. RICHARDSON: I'm asking him for his
COMMISSIONER KJELLANDER: His opinion, but it's
25 not a legal opinion.
CSB REPORTING
[phone]
416 KALICH (X)
Avista Corporation
1 MR. RICHARDSON: I'm assuming it's not,
2 although he has legal testimony in his testimony, but
3 we're working around it.
4 COMMISSIONER KJELLANDER: I'll allow the
5 question. He either has an opinion or he doesn't.
6
7 Q.
THE WITNESS: And I don't have a opinion.
BY MR. RICHARDSON: Do you know if the Exelon
8 Wind v. Nelson case was a unanimous or a split
9 decision?
10
11
A. I don't.
MR. RICHARDSON: Thank you. That's all I have,
12 Mr. Chairman.
13 COMMISSIONER KJELLANDER: Thank you, Mr.
14 Richardson. Mr. Otto.
15
16
17
18
MR. OTTO: I'll move up here.
CROSS-EXAMINATINON
19 BY MR. OTTO:
20 Q. I just have one question, so in your rebuttal
21 testimony on page 2, lines 7 through 10, you testify in
22 your view the existing avoided cost methodology works
23 well and it reflects need and actual avoided cost. Do
24 you stand by that testimony today?
25 A. Yes, I do.
CSB REPORTING
[phone]
417 KALICH (X)
Avista Corporation
1
2
MR. OTTO: Thank you.
COMMISSIONER KJELLANDER: Okay, thank you, Mr.
3 Otto. I'm assuming you're done.
4
5
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11
12 Sanger.
13
MR. OTTO: Yes, sorry.
COMMISSIONER KJELLANDER: Mr. Miller.
MR. MILLER: No, thank you.
COMMISSIONER KJELLANDER: Ms. Nunez.
MS. NUNEZ: No questions, thank you.
COMMISSIONER KJELLANDER: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chair.
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. SANGER: Yes, I've got a couple of
14 questions, Your Honor.
15 COMMISSIONER KJELLANDER: Just get near a
16 microphone. Thank you.
17
18
19
20 BY MR. SANGER:
CROSS-EXAMINATION
21 Q. I just have a couple of questions about
22 Avista's position in this case. I'm specifically
23 referring to your rebuttal testimony at page 1. You can
24 probably answer this without referring to it, but at page
25 1, lines 19 through 22, you state that Avista essentially
CSB REPORTING
[phone]
418 KALICH (X)
Avista Corporation
1 requests that the Commission provide it with any interim
2 or final relief that is granted to the other utilities in
3 this case; is that correct?
4
5
A.
Q.
Yes, sir.
And would Avista be satisfied with the
6 Commission granting Idaho Power's relief in this case,
7 the requested relief by Idaho Power?
8
9
A. Yes.
MR. SANGER: No further questions, Your
10 Honor.
11
12 Hammond.
13
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. HAMMOND: I have no questions,
14 Mr. Chairman. Thank you.
15 COMMISSIONER KJELLANDER: Thank you, Mr.
16 Hammond. Mr. Arkoosh.
17 MR. ARKOOSH: No questions. Thank you,
18 Mr. Chairman.
19
22
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24
COMMISSIONER KJELLANDER: Thank you, and I'm
We do have some opportunity for redirect.
MR. ANDREA: No redirect, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you, and we
21 from members of the Commission? None.
20 assuming no questions from Mr. Howell. Any questions
25 appreciate your testimony, Mr. Kalich.
CSB REPORTING
[phone]
419 KALICH (X)
Avista Corporation
1
2
(The witness left the stand.)
COMMISSIONER KJELLANDER: Let's move on now to
3 PacifiCorp/Rocky Mountain Power.
4 MS. HOGLE: Thank you, Mr. Chairman. Rocky
5 Mountain Power calls Mr. Paul Clements.
6
7 PAUL H. CLEMENTS,
8 produced as a witness at the instance of Rocky Mountain
9 Power Company, having been first duly sworn to tell the
10 truth, the whole truth, and nothing but the truth, was
11 examined and testified as follows:
12
13
14
15 BY MS. HOGLE:
DIRECT EXAMINATION
16
17
18
Q.
A.
Q.
Good afternoon, Mr. Clements.
Good afternoon.
Can you please state and spell your name for
19 the record?
20
21
A.
Q.
Yes, Paul Clements, last name C-1-e-m-e-n-t-s.
And by whom are you employed and what is your
22 current position with Rocky Mountain Power?
23 A. I'm employed by Rocky Mountain Power as
24 director of commercial services.
25 Q. And are you the same Paul Clements who filed
CSB REPORTING
[phone]
420 CLEMENTS (Di)
Rocky Mountain Power
1 direct testimony and an exhibit on March 2nd, 2015, in
2 this proceeding?
3
4
A.
Q.
Yes.
And did you also file rebuttal testimony on
5 June 11th, 2015?
6
7
A.
Q.
Yes, I did.
Do you have any additions or corrections that
8 you'd wish to make to either of those prefiled
9 testimonies at this time?
10 A. I have one correction in my direct testimony.
11 My exhibit, my single exhibit, was labeled as Exhibit
12 No. 1, which may have been a bit presumptuous of me as
13 our numbering started at 601, so the change would be my
14 exhibit which is currently labeled as Exhibit No. 1
15 should be relabeled as Exhibit 601. That's my only
16 change.
17 Q. Thank you; so if I were to ask you the
18 questions in your testimony again here today, would your
19 answers be the same?
20 A. They would. I would note one caveat to that.
21 In my testimony, I speak of the current pricing queue. I
22 will note that in my testimony, I'm speaking of the queue
23 that was effective or existing at the time I drafted my
24 testimony. The pricing queue has since changed, of
25 course, as new QFs have come in or dropped off.
CSB REPORTING
[phone]
421 CLEMENTS (Di)
Rocky Mountain Power
1 MS. HOGLE: Mr. Chairman, I would move that the
2 prefiled direct, including Exhibit 601, and the rebuttal
3 testimony of Mr. Paul Clements be spread upon the record
4 as if read and that Exhibit 601 be marked as such for
5 admission into the record. Thank you.
6 COMMISSIONER KJELLANDER: Thank you, and
7 without objection, the testimony prefiled by Mr. Clements
8 will be spread across the record as if read and we will
9 mark for identification Exhibit 601.
10 (The following prefiled direct and rebuttal
11 testimony of Mr. Paul H. Clements is spread upon the
12 record.)
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CSB REPORTING
[phone]
422 CLEMENTS (Di)
Rocky Mountain Power
1 Q. Please state your name, business address, and
2 present position with Rocky Mountain Power (the
3 "Company"), a division of PacifiCorp.
4 A. My name is Paul H. Clements. My business
5 address is 201 S. Main, Suite 2300, Salt Lake City, Utah
6 84111. My present position is Senior Originator/Power
7 Marketer for PacifiCorp Energy. PacifiCorp Energy and
8 Rocky Mountain Power are divisions of PacifiCorp.
9 Q. How long have you been in your present
10 position?
11 A. I have been in my present position since
12 December 2004.
13 Q. Please describe your education and business
14 experience.
15 A. I have a S.S. in Business Management from
16 Brigham Young University. I have been employed with
17 PacifiCorp since 2004 as an originator/power marketer
18 responsible for negotiating qualifying facility
19 contracts, negotiating interruptible retail special
20 contracts, and managing wholesale or market-based energy
21 and capacity contracts with other utilities and power
22 marketers. I also worked in the merchant energy sector
23 for approximately six years in pricing and structuring,
24 origination, and trading roles for Duke Energy and
25 Illinova.
423 Clements, Di - 1
Rocky Mountain Power
1 PURPOSE AND SUMMARY OF TESTIMONY
2
3
Q.
A.
What is the purpose of your testimony?
The purpose of my testimony is to support and
4 present the Company's application to modify certain terms
5 and conditions related to contracting and pricing for
6 non-standard qualifying facility ("QF") contracts that
7 the Company must enter into under the Public Utility
8 Regulatory Policies Act of 1978 ("PURPA"). The Company is
9 seeking immediate relief on one item in order to protect
10 its customers
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424 Clements, Di - la
Rocky Mountain Power
1 in the near term. The Company is also seeking permanent
2 implementation of two modifications to QF contracting and
3 pricing procedures. These changes are necessary in order
4 to maintain the "ratepayer indifference" standard
5 required by PURPA in both the immediate near term and on
6 a permanent basis. Specifically, the Company is
7 requesting an order from the Idaho Public Utilities
8 Commission ("Commission") directing implementation of the
9 following:
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21
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1.
2.
3.
Immediate reduction, on a temporary basis, of
the maximum contract term for PURPA contracts
between QFs and PacifiCorp from 20 years to
five years, pending litigation of this case.
Permanent reduction of the maximum contract
term for PURPA contracts from 20 years to three
years, to be consistent with the Company's
hedging and trading policies and practices for
non-PURPA energy contracts and more aligned
with the Integrated Resource Plan ("IRP")
cycle.
Modification of the Company's avoided cost
methodology such that preparation of indicative
prices for QFs shall reflect all active QF
projects in the pricing queue ahead of any
newly proposed QF request for indicative
425 Clements, Di - 2
Rocky Mountain Power
1 prices.
2 I provide evidence demonstrating how PacifiCorp customers
3 could be adversely impacted by the Commission's February
4 6, 2015 order in Idaho Power Company's ("Idaho Power")
5 Case No. IPC-E-15-01 if the Commission does not take
6 immediate action in this proceeding. I also describe the
7 significant increase the Company has experienced in PURPA
8 contract requests in 2014 and 2015, how
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426 Clements, Di - 2a
Rocky Mountain Power
1 the increased activity harms customers, and why the
2 requested modifications to the avoided cost contracting
3 and pricing procedures are needed.
4 PacifiCorp currently has 189.6 megawatts ("MW") of
5 existing PURPA contracts in Idaho and 275.5 MW of
6 proposed PURPA contracts in Idaho, together totaling
7 465.1 MW of nameplate capacity. The magnitude and
8 potential impact of this increased PURPA activity is best
9 measured by comparing the total amount of existing and
10 proposed Idaho PURPA projects to PacifiCorp's Idaho
11 retail load. Using 2014 as an example, PacifiCorp's
12 average total Idaho retail load was 432 MW and its
13 minimum total Idaho retail load was 169 MW. The 465.1 MW
14 of existing and proposed PURPA contracts in Idaho at
15 their nameplate capacity would be enough to supply 108
16 percent of PacifiCorp's average Idaho retail load and 275
17 percent of PacifiCorp's minimum retail load. Expanding
18 the analysis to PacifiCorp's six-state system, PacifiCorp
19 currently has requests for 3,641 MW of new PURPA
20 contracts system-wide, in addition to the 1,732 MW of QF
21 contracts that are already executed.
22 I explain how this material increase in the number
23 of PURPA projects requesting pricing in both Idaho and on
24 PacifiCorp's system in other states will result in
25 proposed Idaho projects receiving and entering into
427 Clements, Di - 3
Rocky Mountain Power
1 purchase obligations based upon pricing that is not
2 reflective of the actual cost of the resource the QF will
3 displace under the currently effective IRP methodology.
4 I also provide evidence demonstrating the impact of PURPA
5 contracts on customers' rates, and illustrate how the
6 required 20-year contract term is (1) inconsistent with
7 the Company's hedging and resource acquisition policies
8 and practices for non-
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428 Clements, Di - 3a
Rocky Mountain Power
1 PURPA energy purchases and (2) not aligned with the
2 Company's IRP planning cycle and action plan. Lastly, I
3 describe how, without the requested modification to
4 contract term, PacifiCorp will be forced to continue to
5 acquire long-term fixed price PURPA contracts even though
6 PacifiCorp's 2013 IRP Update, which was filed with this
7 Commission, shows that new long-term resources are not
8 required until 2027. PacifiCorp's 2015 IRP, which is
9 scheduled to be filed in March 2015, will show no new
10 resource is required until 2028.
11 Q. Is the application supported by other
12 witnesses?
13 A. Yes. Company witness Mr. Brian S. Dickman
14 describes how the current avoided cost rate methodology
15 does not recognize the impact of proposed QF contracts
16 that are not yet signed but have requested indicative
17 avoided cost prices and are actively pursuing a power
18 purchase agreement ("PPA") with the Company - a
19 shortcoming that leads to inflated and incorrect avoided
20 cost prices in PURPA contracts due to QFs ability to
21 enter into purchase obligations unilaterally. This
22 shortcoming is particularly impactful when there are
23 multiple PURPA contract requests at the same time, which
24 is currently the case in Idaho and across PacifiCorp's
25 six state system.
429 Clements, Di - 4
Rocky Mountain Power
1 Q. Why are the requested modifications critical at
2 this time?
3 A. First, the Company is seeking expedited and
4 temporary relief based on the following event: Within
5 five days of the Commission's February 6, 2015 Order
6 ("Idaho Power Order"), PacifiCorp received four pricing
7 requests totaling 130 MW from PURPA developers located in
8 Idaho Power's service territory, who are now planning to
9 obtain a transmission wheel to PacifiCorp in search of a
10 PPA
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430 Clements, Di - 4a
Rocky Mountain Power
1 with more favorable terms. Because of this arbitrage,
2 which could potentially cause immediate harm to the
3 Company's retail customers, the Company is seeking an
4 expedited order temporarily lowering the Company's
5 maximum PURPA contract tenor from 20 years to five years.
6 Second, the Company seeks permanent changes to its
7 PPA terms and conditions in general. The Company has
8 reviewed its PURPA contracting and pricing procedures and
9 believes that permanent, long-term changes to its PURPA
10 contracts are critical to maintain the customer
11 indifference standard required by PURPA and to protect
12 the welfare of the Company's Idaho retail customers. In
13 Order No. 33204, the Commission stated that utilities are
14 in the best position to advise the Commission when
15 changes to PURPA contract terms and conditions are
16 warranted:
17 While we are pleased with the progression of the IRP
methodology, avoided cost rates are not the only
18 terms to a PURPA contract. The utilities are in the
best position to inform the Commission if review of
19 additional PURPA contract terms and conditions is
warranted.1
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21 PacifiCorp routinely reviews PURPA contract terms and
22 conditions and avoided cost methodologies, and recent
23 events dictate that PacifiCorp petition this Commission
24 for changes at this time.
25 Like Idaho Power, the Company has experienced a
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1 significant increase in QF pricing requests in Idaho and
2 across its six-state system. Similar to Idaho Power, the
3 Company has no need for resources for the next decade.
4 Also similar to Idaho Power, the Company's hedging
5 practices and policies are short-term in
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1 nature. The Company's hedging program was modified as a
2 result of a series of hedging collaborative workshops the
3 Company held with stakeholders in 2011 and 2012 which
4 reduced the Company's standard hedging horizon from 48
5 months to 36 months.
6 Given the magnitude of new QF requests, and
7 considering the inherent uncertainties in projecting
8 avoided cost rates out 20 years or more, current Idaho
9 avoided cost rates are adversely impacting customers and
10 will continue to do so for 20 years. Thus, in addition
11 to the temporary, immediate change noted above, the
12 Company also seeks two permanent changes. First, the
13 Company requests approval of a permanent reduction in the
14 maximum contract term for PURPA contracts, from 20 years
15 to three years. Such a term would be more consistent
16 with the Company's hedging and trading policies and
17 practices for non-PURPA energy contracts and more aligned
18 with the !RP cycle.
19 Second, Company witness Mr. Dickman reviewed the
20 impact of the Company's large QF pricing queue on avoided
21 costs in Idaho and determined that the currently approved
22 methodology distorts avoided cost pricing because each
23 project must be priced as if it were first in the queue.
24 Because a purchase obligation may be created before each
25 QF project can be re-priced to account for other projects
433 Clements, Di - 6
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1 that have entered into an obligation around the same
2 time, the current methodology artificially inflates
3 indicative avoided cost pricing for projects lower in the
4 queue, harms retail customers if multiple purchase
5 obligations are entered into based on that inaccurate
6 pricing, and violates the ratepayer indifference standard
7 under PURPA.
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1 These events and the resulting consequences prompted
2 the Company to file this petition to inform the
3 Commission that changes are warranted.
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Q.
A.
Describe the history and purpose of PURPA.
Congress enacted PURPA in response to the
6 nationwide energy crisis of the 1970s. Its goal was to
7 reduce the country's dependence on imported fuels by
8 encouraging the addition of cogeneration and small power
9 production facilities to the nation's electrical
10 generating system.2 PURPA requires electric utilities to
11 purchase all electric energy made available by QFs at
12 rates that (a) are just and reasonable to electric
13 consumers, (b) do not discriminate against QFs, and (c)
14 do not exceed "the incremental cost to the electric
15 utility of alternative electric energy."3 The
16 incremental cost to the utility means the amount it would
17 cost the utility to generate or purchase the electric
18 energy but for the purchase from the QF.4 The
19 incremental cost standard is intended to leave customers
20 economically
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10 2 See, e.g., 16 U.S.C. § 2601 (Findings).
3 The provisions of 16 U.S.C. § 824a-3 provide in pertinent part:
11 (a) Cogeneration and small power production rules
Not later than 1 year after November 9, 1978, the
Commission [FERC) shall prescribe, and from time to time
thereafter revise, such rules as it determines necessary to
encourage cogeneration and small power production, which
rules require electric utilities to offer to -
(1) sell electric energy to qualifying cogeneration
facilities and qualifying small power production
facilities and
(2) purchase electric energy from such facilities ...
16 (b) Rates for purchases by electric utilities
The rules prescribed under subsection (a) of this section shall
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insure that, in requiring any electric utility to offer to
purchase electric energy from any qualifying cogeneration
facility or qualifying small power production facility, the
rates for such purchase -
(1) shall be just and reasonable to the electric
consumers of the electric utility and in the
public interest, and
{2) shall not discriminate against qualifying
cogenerators or qualifying small power producers.
No such rule prescribed under subsection {a) of this section
22 shall provide for a rate which exceeds the incremental cost to
the electric utility of alternative electric energy.
23 4 The provisions of 16 U.S.C. § 824a-3(d) provide the following
definition of ''incremental cost of alternative electric energy":
24 For purposes of this section, the term "incremental cost of
alternative electric energy" means, with
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1 indifferent to the source of a utility's energy by
2 ensuring that the cost to the utility of purchasing power
3 from a QF does not exceed the cost the utility would
4 incur in the absence of the QF purchase.5
5 In 1980, FERC issued rules implementing PURPA in
6 which it adopted what it called a utility's "avoided
7 costs" as the standard for implementation of the
8 incremental cost requirement.6 While the applicable
9 statutes and rules are matters of federal law, PURPA
10 gives to state regulatory authorities the responsibility
11 of determining a utility's avoided costs as well as terms
12 and conditions of PURPA contracts.?
13 Q. Under PURPA, are utilities or their customers
14 intended to subsidize QFs in order to achieve PURPA's
15 policy goals?
16 A. Absolutely not. As this Commission and state
17 regulators across the country have stated time and time
18 again, under PURPA's original intent, retail customers
19 should be indifferent to the purchase of QF power. This
20 Commission stated as early as 1987 that,
21 Under current FERC regulations implementing the
Public Utility Regulatory Policies Act, ratepayers
22 are supposed to be indifferent
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respect to electric energy purchased from a qualifying
cogenerator or qualifying small power producer, the cost to the
electric utility of the electric energy which, but for the
16 purchase from such cogenerator or small power producer, such
utility would generate or purchase from another
17 source.
5 See, e.g., Armco Advanced Materials Corp. v. Pennsylvania Pub.
18 Util. Comm'n, 535 Pa. 108, 634 A.2d 207, 209 (Pa. 1993).
6 See American Paper Inst. v. American Elec. Power Serv., 461 U.S.
19 402, 406(1982) (stating that "the term full 'avoided costs' used in
the regulations is the equivalent of the term 'incremental cost of
20 alternative electric energy' used in§ 210(d) of PURPA"). FERC's
definitions of terms used in implementing PURPA are found at 18
21 C.F.R. § 292.101. The term "avoided costs" is defined as "the
incremental costs to an electric utility of electric energy or
22 capacity or both which, but for the purchase from the qualifying
facility or qualifying facilities, such utility would generate itself
23 or purchase from another source." 18 C.F.R. § 292.lOl(b) (6).
7 Idaho Power Co. v. Idaho Pub. Util. Comm'n., 155 Idaho 780, 782
24 (2013) ("Idaho Power Co.") (citing FERC v. Mississippi, 456 U.S. 742,
751 (1982)).
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1 or neutral as to whether they receive energy through
a QF or a regulated utility. Stated differently, the
2 price structure should enable utilities to integrate
in a neutral and unbiased manner both utility and
3 non-utility owned generating facilities into the
long-run planning process and should provide similar
4 economic criteria for development and operation of
generating facilities regardless of facility
5 ownership.8
6 FERC has likewise affirmed the need to ensure customer
7 indifference to utility purchases of QF power, noting
8 that, in enacting PURPA, "[t]he intention [of Congress]
9 was to make ratepayers indifferent as to whether the
10 utility used more traditional sources of power or the
11 newly-encouraged alternatives."9
12 Under PURPA, then, customers must remain indifferent
13 or unaffected by QF contracts. Further, as this
14 Commission has noted "avoided cost rates are not the only
15 terms to a PURPA contract.1110 Indeed, both avoided costs
16 and other terms and conditions of PURPA contracts affect
17 whether retail customers remain indifferent to the
18 purchase of QF power. The modifications requested by the
19 Company in this application are necessary to maintain
20 this ratepayer indifference standard and are the primary
21 means by which the Company and the Commission can protect
22 customers from unnecessary price risk.
23 Q. Does the Commission have discretion to
24 determine the appropriate contract term and avoided cost
25 pricing methodology under PURPA?
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1 A. Yes. Although PURPA's federal mandate requires
2 utilities to purchase QF power, PURPA's scheme of
3 cooperative federalism gives state regulatory agencies
4 the
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21 8 In re Review of the Idaho Pub. Utils. Comm'n Policies Establishing
Avoided Costs Under the Pub. Util. Regulatory Policies Act of 1978,
22 Case No. U-1500-170, Order No. 21249 (May 1987).
9 Southern Cal. Edison Co., et al., 71 FERC 61,269 at p. 62,080
23 (1995), overruled on other grounds, Cal. Pub. Util. Comm'n, 133 FERC
61, 059 (2010).
24 10 In re Application of Idaho Power Co., Case No. IPC-E-14-30, Order
No. 33204 at 8 (Jan. 8, 2015).
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1 authority to protect retail customers from any unintended
2 negative consequences of these mandatory purchases by
3 delegating to state authorities the freedom to establish
4 the key terms and conditions of PURPA contracts.11 In
5 crafting their methodologies for the details of PURPA
6 contracts, FERC has explained its view that "states are
7 allowed a wide degree of latitude in establishing an
8 implementation plan for section 210 of PURPA, as long as
9 such plans are consistent with [FERC's) regulations."12
10 A critical element of the utility's must-purchase
11 requirement under PURPA is the contract term. This is
12 because FERC generally requires a utility to lock in
13 forecasted avoided cost rates for the entire contract
14 term.13
15 The contract term for PURPA contracts set by this
16 Commission has never been static-it has varied since
17 PURPA's inception. Initially, the Commission set PURPA
18 contracts at 35 years to match the amortization period
19 allowed for similar utility owned facilities, making
20 financing easier, thus encouraging QF development.14
21 Later, the Commission began to recognize concerns related
22 to the risk and uncertainty inherent in long range
23 forecasting and shortened the contract length to 20
24 years.ls This time frame was shortened to only 5 years
25 in 1996 and 1997 (first for QFs of 1 MW and larger, then
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1 for QFs under the 1 MW cap) in order to align the QF
2 contract time frame with the utilities' acquisition
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22 12 Cal. Pub. Util. Comm'n, 133 FERC 61,059 at P 24 (2010).
13 See Small Power Production and Cogeneration Facilities;
23 Regulations Implementing Section 210 of PURPA, 45 Fed. Reg. 12214,
12224 (1980).
24 14 See, e.g. Order No. 29029 at 2 (describing the origin of PURPA
regulation in Idaho).
25 15 Order No. 21630.
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1 strategies.16 The Commission noted in that case that a
2 20 year contract obligation did not reflect the manner in
3 which the utilities were acquiring power to meet new
4 load, which at the time was through contracts with terms
5 of five years or less, and that "it would be nothing more
6 than an artificial shelter to the QF industry to provide
7 those projects with contract terms not otherwise
8 available in the free market."17
9 In 2002, the Commission raised the contract length
10 back to 20 years, expressing concerns about a scarcity of
11 QF contracts signed since the prior change.is Since
12 then, concerns regarding the viability of QFs are no
13 longer at the forefront. In 2015, the key concerns about
14 PURPA contracts are similar to those that were present at
15 the time of the Commission's 1996 and 1997 orders
16 reducing the term to five years, i.e., the current
17 concerns flow from the magnitude of QF power flowing onto
18 utilities' systems without any finding of utility need
19 and resulting concerns about price risk, reliability, and
20 customer indifference. As the Commission noted in a
21 recent press release, the Commission has approved PURPA
22 contracts for 400 MW of solar energy in just the past
23 three months.19 But the Commission noted, "PURPA does
24 not address and FERC regulations do not adequately
25 provide for consideration of whether the utility being
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18 See Order No. 29029 at 7 (stating that it "could not ignore the
23 fact that since reducing the eligibility threshold to 1 MW and
contract term to 5 years, there has been only one PURPA contract
24 signed in Idaho.").
19 Press Release, Idaho Public Utilities Commission, PUC reduces
25 length of some PURPA contracts to five years (Feb. 5, 2015).
444 Clements, Di - lla
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1 purchase QF power is actually in need of such energy."20
2 The Commission has repeatedly expressed concerns about
3 price and reliability impacts on Idaho customers in the
4 past year, concerns that led the Commission to lower the
5 approved length of PURPA contracts for Idaho Power down
6 to five years in the Commission's February 6 Order.21
7 Q. Can a 20-year fixed-price contract term be
8 considered a "subsidy" to a QF?
9 A. Yes. Given the typical contracting and hedging
10 horizons for energy contracts in the utility industry,
11 which are commonly limited to less than 36 months, it is
12 extremely rare for a utility to voluntarily enter into a
13 20-year fixed-price energy contract without a specified
14 energy resource need due to concerns about price risk,
15 market liquidity, and other risk considerations. Under
16 the Commission's current PURPA policies, however, any QF
17 can obtain a 20-year, fixed-price energy contract at the
18 Company's projected avoided cost, without any economic
19 considerations or price adjustment to account for the
20 risk to utility customers from this unusual long-term
21 transaction, or to the QF to account for the price
22 certainty the QF enjoys from such a contract. As this
23 Commission has noted, "avoided cost rates are not the
24 only terms to a PURPA contract." Contract lengths are
25 also PURPA contract terms, and they carry with them their
445 Clements, Di - 12
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1 own economic value. To grant QFs access to long-term
2 price certainty with no adjustment to the price to
3 account for that certainty is granting QFs something no
4 other market participant
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1 enjoys. For this reason, I would view a guaranteed,
2 fixed-price, 20-year contract at avoided cost to be a QF
3 subsidy.
4 IMPACT OF THE COMMISSION'S IDAHO POWER ORDER: AN
5 IMMEDIATE INCREASE IN QF PRICING REQUESTS
6 Q. How has the Idaho Power Order affected
7 PacifiCorp?
8 A. On February 11, 2015, five days after that
9 order, PacifiCorp received four new PURPA pricing
10 requests in Idaho totaling 130 MW. In their requests,
11 the developers specifically noted that they plan to
12 interconnect the QF to Idaho Power Company's
13 distribution/transmission system and wheel the power to
14 Rocky Mountain Power. They further specifically request
15 proposals for a minimum contracting term of 20 years.
16 Their actions indicate that these developers would not
17 have sought to sell to PacifiCorp had the 20-year
18 contract term requirement not been reduced to five years
19 for Idaho Power. In addition to these four formal
20 requests, the Company has received several informal
21 inquiries and expects to receive additional requests from
22 projects located in Idaho Power's service territory.
23 Since the current 465.1 MW of existing and proposed PURPA
24 contracts in Idaho at their nameplate capacity is already
25 enough to supply 108 percent of PacifiCorp's 2014 average
447 Clements, Di - 13
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1 Idaho retail load and 275 percent of PacifiCorp's 2014
2 minimum Idaho retail load, immediate action must be
3 taken.
4 Q. Is it possible for projects to obtain the
5 transmission rights required to move energy from Idaho
6 Power's system to PacifiCorp's system?
7 A. Yes. PacifiCorp has reviewed Idaho Power's Open
8 Access Same Time Information System ("OASIS") and
9 confirmed that transmission is available.
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Q.
A.
Is this type of wheel permitted under PURPA?
Yes. FERC's rules and orders contemplate that
3 if a QF interconnects with one utility and wheels power
4 to another utility's system, the second utility is
5 required to purchase that power under PURPA. See, e.g.,
6 18 CFR §292.303.
7 Q. Is it just and reasonable and in the broad
8 public interest for the Commission to allow QFs the
9 ability to arbitrage between the various Idaho utilities
10 based on different contract terms?
11 A. No. One group of Idaho customers should not be
12 harmed by actions taken to protect another group of Idaho
13 customers. The customer indifference standard should
14 extend equally to all Idaho customers, regardless of the
15 utility that serves them. In this case, actions taken by
16 the Commission to protect Idaho Power customers may
17 inadvertently result in harm to Rocky Mountain Power
18 customers.
19 In a prior case brought before this Commission to
20 address a similar situation in 1996 and 1997, Commission
21 Staff stated its belief that "rules regarding contract
22 length for PURPA contracts should be the same for all
23 regulated electric utilities in Idaho to avoid disparate
24 treatment."22 The Commission ultimately agreed with the
25 Staff's position in that case and incorporated their
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1 position in its order. In today's situation, similar to
2 what occurred when found in these same circumstances in
3 the past, Rocky Mountain Power customers should be
4 afforded the same protections provided to other Idaho
5 customers.
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1 Q. Notwithstanding the consequences you describe
2 above that resulted from the Idaho Power Order, is there
3 other evidence that supports PacifiCorp's requested
4 modifications?
5 A. Yes. The Company will present substantial and
6 compelling evidence demonstrating why the Company's
7 requested modifications are necessary in order to
8 maintain the ''ratepayer indifference" standard. The
9 consequences of the Idaho Power Order support the need
10 for immediate relief but are not the sole reason the
11 immediate and permanent changes are warranted at this
12 time.
13 SIGNIFICANT INCREASE IN PURPA CONTRACT REQUESTS
14 Q. Has PacifiCorp executed a significant number of
15 PURPA contracts in recent years in response to its
16 federal obligation?
17 A. Yes. PacifiCorp currently manages 141 PURPA
18 contracts totaling 1,732 MW of nameplate capacity across
19 its six state system. Of this total, 97 projects totaling
20 1,553 MW (90 percent of the total PURPA MWs under
21 contract) have online dates of 2007 or later,
22 demonstrating that significant activity has occurred in
23 the last seven to eight years. Of this total, 47 projects
24 totaling 885 MW (slightly more than half of the total
25 PURPA MWs under contract) have online dates of 2014 or
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1 later, further demonstrating the exponential increase in
2 PURPA contract requests and resulting contracts that have
3 occurred in the last two years. In Idaho, four projects
4 totaling 164.7 MW came online in 2011 and 2012. Those
5 four Idaho projects alone are close in nameplate capacity
6 to PacifiCorp's minimum Idaho retail load in 2014 of 169
7 MW.
8 This dramatic increase in PURPA contract executions
9 and pricing requests
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in Idaho and system-wide in the last several years
demonstrates that additional review of contract and
pricing methodology for non-standard Idaho QFs is
warranted at this time and could not have been
anticipated when the Commission reviewed the issue of
contract term in previous cases.
Q. Please describe the current queue of pricing
requests for PURPA contracts in Idaho and across
PacifiCorp's system.
A. In Idaho, the Company currently has 12 project
requests totaling 275.5 MW of nameplate capacity. The
Company currently has requests from 89 projects totaling
3,641 MW of nameplate capacity system-wide. Table 1 shows
the number of project requests and the total MWs by
resource type for each of PacifiCorp's six states:
-- --
Table 1 --- � -- -
Wind Solar Other Total State Projects MWs Projecu MWs Projects MWs Projects MWs
California
Idaho 11.0 271.0 1.0 4.5 12.0 275.5
Oregon 25.0 312.4 1.0 3.5 26.0 315.9
Utah 5.0 354.0 38.0 2,075.6 43.0 2,429.6
Washington
Wyoming 8.0 620.0 8.0 620.0
10TAL 13.0 974.0 74.0 2,659.0 2.0 8.0 89.0 3,641.0.··
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1 Exhibit No. 601 provides detailed information on the
2 pricing queue, including each project location (state),
3 size (nameplate capacity), type (i.e. solar, wind), and
4 proposed online date. Project names have been withheld to
5 maintain confidentiality of the customer information.
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1 Q. How does the number of executed Idaho PURPA
2 contracts and proposed Idaho PURPA contracts compare to
3 PacifiCorp's typical Idaho load requirements?
4 A. PacifiCorp has 189.6 MW of existing PURPA
5 contracts in Idaho and 275.5 MW of proposed PURPA
6 contracts in Idaho, together totaling 465.1 MW of
7 nameplate capacity. Using 2014 as an example,
8 PacifiCorp's maximum total retail load in Idaho was 818
9 MW, its minimum load was 169 MW, and its average load was
10 432 MW. The 465.1 MW of existing and proposed PURPA
11 contracts in Idaho at their nameplate capacity would be
12 enough to supply 108 percent of PacifiCorp's average
13 Idaho retail load and 275 percent of PacifiCorp's minimum
14 Idaho retail load.
15 Q. How does the number of executed PURPA contracts
16 and proposed PURPA contracts across PacifiCorp's system
17 compare to PacifiCorp's typical six state system load
18 requirements?
19 A. PacifiCorp has 1,732 MW of existing PURPA
20 contracts and 3,641 MW of proposed PURPA contracts,
21 together totaling 5,373 MW of nameplate capacity. Using
22 2014 as an example, PacifiCorp's maximum total retail
23 load across its six state system was 10,314 MW, its
24 minimum load was 4,967 MW, and its average load was 6,844
25 MW. The 5,373 MW of existing and proposed PURPA contracts
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1 at their nameplate capacity would be enough to supply 79
2 percent of PacifiCorp's average retail load and 108
3 percent of PacifiCorp's minimum retail load.
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1 DISTORTION OF INDICATIVE AVOIDED COST PRICING DUE TO
2 INCREASE IN PURPA CONTRACT PRICING QUEUE
3 Q. How is indicative pricing calculated if you
4 have multiple proposed PURPA contracts in the pricing
5 queue?
6 A. Each proposed QF project is provided an
7 indicative price assuming the project requesting pricing
8 is at the top of the pricing queue, meaning the existence
9 of other proposed or queued QF projects is not factored
10 into the indicative price. Therefore, each project is
11 provided an indicative price based on the Company's
12 highest marginal or avoided resource costs. For example,
13 assuming PacifiCorp's highest marginal or avoidable cost
14 for a given time period is a 25 MW market purchase at $35
15 per megawatt-hour ("MWh"), and the next highest marginal
16 or avoidable cost for the same time period is a second 25
17 MW market purchase at $30 per MWh. Under the current
18 approved methodology, a proposed 20 MW QF would receive
19 an indicative price based on avoiding 20 MW of the 25 MW
20 purchase at $35 per MWh. If the Company were to receive
21 a second 20 MW pricing request for a different PURPA
22 project, it too would receive an indicative price based
23 on the assumption that it avoids 20 MW of the 25 MW
24 purchase at $35 per MWh, because the current methodology
25 does not allow the Company to account for the existence
457 Clements, Di - 18
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1 of the first proposed project when providing pricing for
2 the second proposed project. If both parties were to
3 unequivocally commit themselves to sell to PacifiCorp at
4 around the same time, PacifiCorp could not re-price the
5 second project to reflect the fact that the first project
6 already "avoided" the same resource. In my hypothetical
7 example, both 20 MW projects, or 40 MW
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1 total, would be priced as if they were avoiding the
2 single 25 MW resource at $35 per MWh. In reality, if
3 considered together they would be avoiding 25 MW of the
4 $35 per MWh resource and 15 MW of the $30 per MWh
5 resource. In this example, the inability to account for
6 the first proposed contract when providing pricing for
7 the second proposed contract results in customers paying
8 a QF $35 per MWh for 15 MW when the actual cost of the 15
9 MW being avoided by that QF is only $30 per MWh. This $5
10 per MWh difference violates the ratepayer indifference
11 standard.
12 Q. What is the impact of a very large pricing
13 queue (i.e. multiple proposed PURPA projects requesting
14 contracts) on indicative pricing?
15 A. A very large pricing queue results in
16 indicative pricing being provided to proposed PURPA
17 projects that is far in excess of actual avoided costs if
18 all queued projects are considered. The larger the
19 queue, the greater the problem. In my example above, I
20 described how two hypothetical 20 MW projects received
21 pricing based on the single highest cost resource, but
22 one of them actually avoided a lower cost resource when
23 considered together. The result was an avoided cost that
24 was $5 per MWh too high. If the queue has dozens of
25 PURPA projects requesting pricing, as is currently the
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1 case, this issue is exacerbated. Multiple projects may
2 receive indicative pricing based on the highest cost
3 resource, but when the dozens of projects are considered
4 together, the projects at the bottom of the queue are
5 likely avoiding much lower cost resources. This results
6 in payments to QFs that exceed the cost of the resource
7 that is being avoided. This increases costs to customers
8 and is not consistent with the ratepayer indifference
9 standard
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460 Clements, Di - 19a
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1 mandated by PURPA. Company witness Brian Dickman
2 provides additional evidence and supporting testimony
3 regarding the impact of the existing pricing queue on
4 avoided cost pricing. In his testimony, he describes how
5 the difference in avoided costs from the top to the
6 bottom of a pricing queue with approximately 3,000 MW, or
7 641 MW less than the current PacifiCorp pricing queue of
8 3,641 MW, is approximately $18 per MWh - meaning
9 indicative pricing for the last project request received
10 could be as much as $18 per MWh higher than avoided costs
11 if all the project requests ahead of it in the 3,000 MW
12 queue enter into purchase obligations.
13 THE COMPANY'S IDAHO PURPA CONTRACTS WILL RESULT IN HIGHER
14 CUSTOMER RATES, IN CONFLICT WITH THE RATEPAYER
15 INDIFFERENCE STANDARD
16 Q. What impact should PURPA contracts have on
17 customer rates?
18 A. PURPA contracts should have no impact on
19 customer rates. As this Commission and state regulators
20 across the country have stated time and time again,
21 retail customers should be indifferent to the purchase of
22 QF power. As FERC has noted, in enacting PURPA, ''[t]he
23 intention [of Congress] was to make ratepayers
24 indifferent as to whether the utility used more
25 traditional sources of power or the newly-encouraged
461 Clements, Di - 20
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1 alternatives." Southern Cal. Edison Co., San Diego Gas &
2 Elec. Co., 71 FERC i 61,269 at p. 62,080 (1995).
3 In short, customers must remain indifferent or
4 unaffected by PURPA contracts. The modifications
5 requested by the Company in this application are
6 necessary to maintain this indifference standard.
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1 Q. Why is it critical to make needed modifications
2 to pricing and contracting procedures quickly once they
3 have been identified?
4 A. As mentioned earlier in my testimony,
5 PacifiCorp currently has 189.6 MW of existing PURPA
6 contracts in Idaho and 275.5 MW of proposed PURPA
7 contracts in Idaho, together totaling 465.1 MW of
8 nameplate capacity. The Company has 141 existing
9 (executed) PURPA contracts totaling 1,732 MW of nameplate
10 capacity across its six state system. Under PacifiCorp's
11 multi-state jurisdictional cost allocation model, PURPA
12 contracts are considered system resources and are
13 allocated to each of the six states based on the System
14 Generation allocation factor. Idaho's allocated share is
15 typically around six percent. The expected system wide
16 costs (payments to QFs) over the next ten years from
17 PacifiCorp's executed PURPA contracts is $2.6 billion.
18 In 2015 alone, the projected payment to QFs is $170.5
19 million, with Idaho's allocated share at $10.2 million.23
20 If these projects had been priced incorrectly by just 10
21 percent, it would create a $1.0 million impact in 2015
22 for Idaho customers. That 10 percent impact would grow
23 to a total of $15.5 million in additional costs to Idaho
24 customers over the ten year period starting in 2015.
25 With a pricing queue that currently totals 3,641 MW, or
463 Clements, Di - 21
Rocky Mountain Power
1 more than double (in MW) the size of the $2.6 billion
2 worth of current PURPA contracts to which the Company is
3 already obligated, it is imperative that the indicative
4 pricing provided to prospective PURPA projects be
5 accurate and reflective of the Company's actual projected
6 avoided costs. Failure to implement the modifications
7 proposed by the Company in this case will result in
8 significant
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Rocky Mountain Power
1 irreversible harm to customers in the form of higher
2 retail rates than what would otherwise occur without the
3 PURPA contracts.
4 20 YEAR PURPA CONTRACTS ARE INCONSISTENT WITH CURRENT
5 HEDGING PRACTICES AND RISK POLICIES AND REQUIRE CUSTOMERS
6 TO BEAR AN INAPPROPRIATE AND UNNECESSARY LEVEL OF PRICE
7 RISK
8 Q. When the Company considers purchasing power
9 from a third party, does the Company first review the
10 proposed purchase from a resource need and a
11 risk-management perspective?
12 A. Yes. The Commission expects the Company to
13 serve its customers with least-cost, least-risk
14 resources. For that reason, the Company has integrated
15 resource planning processes and risk-management policies
16 it applies to evaluate any proposed energy contracts, to
17 ensure the contracts are reasonable and prudent.
18 Q. Does the Company apply its integrated resource
19 planning process and internal risk management policies to
20 PURPA contracts?
21 A. No, not in the same way as it does for
22 non-PURPA contracts. The Company cannot refuse to
23 execute PURPA contracts based on the price or the
24 contract term, or based on other transaction parameters
25 that it would normally not accept for non-PURPA
465 Clements, Di - 22
Rocky Mountain Power
1 contracts. Under PURPA, the Company must purchase QF
2 energy and capacity regardless of whether the Company
3 needs the power, on terms and conditions established by
4 its state commissions.
5 Q. How does the Company manage PURPA contract
6 risk?
7 A. While the Company has some limited ability to
8 negotiate PURPA contract terms
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Rocky Mountain Power
1 and conditions, and while the Company uses its non-QF
2 resources to integrate QF power into its system as
3 efficiently and reliably as possible, PURPA requires the
4 Company to rely primarily on its state regulatory
5 commissions to regulate customer exposure to risk through
6 the establishment of terms and conditions of its PURPA
7 contracts.
8 Q. PURPA contracts aside, please generally
9 describe the current electricity and natural gas hedging
10 practices and policies at PacifiCorp.
11 A. The Company modified its hedging horizon for
12 natural gas and power from 48 months to 36 months as a
13 result of hedging collaborative workshops it held with
14 stakeholders in 2011 and 2012. The Company's trading
15 policies and procedures are outlined in the PacifiCorp
16 Energy Commercial & Trading Risk Management Policy. That
17 policy sets forth how the Company identifies, assesses,
18 monitors, reports, manages and mitigates each of the
19 various types of commercial risk associated with energy
20 trading. Energy commodities include, but are not limited
21 to, physical and financial transactions of electricity
22 and natural gas, #2 fuel oil, unleaded gasoline,
23 renewable energy credits, S02 emission allowances, and
24 greenhouse gas allowances. PacifiCorp's commercial &
25 trading organization within PacifiCorp Energy manages the
467 Clements, Di - 23
Rocky Mountain Power
1 energy commodity position and utilizes PacifiCorp's
2 assets and liabilities (loads, generating resources,
3 contractual rights, and obligations) to (i) ensure
4 reliable sources of electric power are available to meet
5 PacifiCorp's customers' needs and (ii) reduce volatility
6 of net power costs for PacifiCorp's customers.
7 PacifiCorp's commodity risks are managed through a
8 control and limit
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Rocky Mountain Power
1 structure that defines the maximum levels of market risk
2 and credit capacity permissible for commercial & trading
3 to engage in trading and risk management activities.
4 Compliance with this policy is mandatory.
5 PacifiCorp's current practice is to actively manage
6 electricity and natural gas short and long positions that
7 are 36 months out and nearer, meaning up to three years
8 from today. Traders have risk limits that they must
9 maintain in order to limit customer price exposure to the
10 Company's open position over this three year time
11 horizon. This trading practice ensures reliable sources
12 of electric power are available to meet PacifiCorp
13 customers' needs and reduces volatility of net power
14 costs.
16 positions beyond the prompt 36 months?
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Q.
A.
Do PacifiCorp traders actively manage or hedge
No. The Company's practice since it completed
18 the hedging collaborative workshops in 2012 has been to
19 limit hedges to 36 months or less unless stakeholders
20 express interest for longer term hedges. There has been
23 metrics are also limited to 36 months.
21 no such expressed interest for electricity hedges beyond
22 36 months since that time. The Company's risk management
Why are these risk management and hedging Q. 24
25 policies and requirements not applicable to the Company's
469 Clements, Di - 24
Rocky Mountain Power
1 PURPA contracts?
2 A. The Company is obligated by law to purchase
3 electricity from QFs at prices and terms set forth by the
4 appropriate state commissions. In this sense, the
5 Company's primary vehicle for risk management review of
6 PURPA contracts are the policy decisions made by each
7 state commission.
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Rocky Mountain Power
1 Q. What process would PacifiCorp undertake when
2 contemplating a non-PURPA transaction that exceeds the
3 typical 36-month time horizon?
4 A. Non-PURPA transactions that exceed 36 months in
5 effective transaction period require extensive analysis
6 and progressively higher level of management review. The
7 analysis includes a review of the need for the
8 transaction, a comparison of the contemplated transaction
9 to other available transactions that meet the same need,
10 a thorough economic analysis to demonstrate that the
11 transaction is the least-cost, least-risk way to meet the
12 identified need, and an extensive review of credit terms
13 and contract terms. Typically the level of detail,
14 documentation, and review increases commensurate with the
15 size and duration of the transaction, which also
16 increases the level of management approval that is
17 required.
18 The Company primarily enters into long-term
19 transactions (those that exceed 36 months) only when
20 there is a clearly identified long-term resource need in
21 its IRP. Long-term resource needs are typically
22 identified in the IRP only after lower-cost, lower-risk
23 short-term resource opportunities are exhausted such that
24 a long-term resource is required to meet customer load
25 requirements.
471 Clements, Di - 25
Rocky Mountain Power
1 Q. When the Company enters into a long-term
2 transaction as a result of the IRP action plan, what
3 additional steps are taken to protect customers?
4 A. The Company typically utilizes a rigorous
5 request for proposal ("RFP") process to acquire any
6 long-term transaction or resource need directed by the
7 IRP action plan. This process often involves extensive
8 input from regulators in the drafting and management of
9 the RFP. In fact, the process often includes independent
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Rocky Mountain Power
1 evaluator24 review of the process and ultimate results.
2 This robust process ensures the Company acquires only
3 what is needed and results in a long-term transaction at
4 the lowest cost possible. In addition to the extensive
5 RFP process, any long-term transaction goes through the
6 analysis and review process I described in conjunction
7 with the PacifiCorp Energy Commercial & Trading Risk
8 Management Policy.
9 Q. Do these same steps occur prior to entering
10 into a PURPA contract?
11 A. No. PURPA contracts do not go through the same
12 extensive IRP process to determine if they are needed.
13 PURPA contracts do not go through the same competitive
14 bid RFP process including oversight by an independent
15 evaluator to ensure they are lowest cost. PURPA contract
16 executions are not limited to the size of the resource
17 need in the IRP action plan. And, PURPA contracts do not
18 receive the same upper management review and analysis
19 because upper management does not have the discretion to
20 refuse the mandatory purchase obligation and the 20 year
21 contract term established by the Commission. The Company
22 is asking the Commission to use its discretion to
23 implement the changes necessary to protect customers.
24 Q. Why is such a rigorous review process necessary
25 when entering into long-term transactions, and why does
473 Clements, Di - 26
Rocky Mountain Power
4 energy contracts carry significant
2 activities to the prompt 36 months?
1 the Company generally limit trading and hedging
The primary reason is long-term fixed price A. 3
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evaluated.
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474 Clements, Di - 26a
Rocky Mountain Power
1 price risk. The market becomes more and more uncertain as
2 you move further into the future, and it is difficult to
3 forecast with reasonable certainty what prices will be
4 far out into the future. Long-term fixed price
5 transactions often move in or out of the money over time
6 as the forward price curve changes. For these reasons,
7 unless the Company has a demonstrated need for resources
8 in its integrated resource plan, it does not pursue
9 long-term transactions.
10 Q. Is there additional market and industry
11 evidence that supports the Company's 36 month trading and
12 hedging horizon?
13 A. Yes. In the unregulated wholesale energy
14 marketplace, very few transactions occur beyond a six
15 year time horizon and the highest volume is within one
16 year. When the Company has entered into long-term,
17 non-QF transactions in the past several years it is the
18 result of a specific need for a resource identified in
19 the IRP and the contracts are typically backed by an
20 identified firm resource (i.e. a utility has load growth,
21 generating unit retirements, or expiring contracts and
22 needs a resource, so it contracts to buy the output from
23 a certain generator). Most of these long-term
24 transactions occur through a rigorous, transparent, and
25 competitive request for proposals processes.
475 Clements, Di - 27
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1 Further evidence of the industry preference for
2 shorter term fixed price contracts is found in the
3 practices of most of PacifiCorp's combined heat and power
4 (CHP} QFs. CHP QFs generally do not need long-term
5 contracts for financing purposes (most use balance sheet
6 financing), so these types of QFs evaluate a desired
7 contract term from a risk management perspective. Like
8 most utilities, CHP QFs typically elect short term
9 contracts with PacifiCorp even when
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1 20 year terms are available. In fact, most elect annual
2 contracts that are renewed each year at the then-current
3 avoided costs. These CHP QF customers have told
4 PacifiCorp that they are not energy traders and therefore
5 prefer to take the spot or near term avoided cost price
6 in order to eliminate the price risk that comes from
7 long-term fixed price contracts.
8 Q. Can you provide an example of the price risk
9 associated with a long-term fixed price contract?
10 A. Yes. The electricity and natural gas markets
11 have fallen dramatically in the past year as oil prices
12 have also declined. On August 1, 2014, a ten year fixed
13 price contract for a seven day by 24 hour electricity
14 product at the Mid-Columbia ("Mid-C") wholesale power
15 market trading hub was priced at $45.87 per MWh. On
16 February 2, 2015, just six months later, that same ten
17 year contract was priced at $38.11 per MWh. The 10 year
18 electricity market declined 17 percent in just six
19 months. Hypothetically, had the Company purchased 100 MW
20 of this ten year fixed price electricity on August 1,
21 2014 at $45.87 per MWh, just six months later the Company
22 would have a mark-to-market loss of $68.0 million on the
23 contract.
24 By comparison to this 100 MW ten-year example,
25 PacifiCorp currently has 275.5 MW of proposed PURPA
477 Clements, Di - 28
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1 contracts in Idaho seeking 20 year fixed price contracts.
2 The price risk associated with this large number of
3 proposed long-term fixed price contracts is substantial
4 and should not be borne by customers.
5 Q. How do you respond to the argument that market
6 prices are currently "low" and therefore PacifiCorp
7 should lock in as much energy as possible?
8 A. Locking in a price because you are speculating
9 that the price is "low" is not
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Rocky Mountain Power
1 hedging - it is speculative trading. PacifiCorp customers
2 are not commodity traders. PacifiCorp customers expect
3 the Company to provide safe and reliable energy while
4 employing the "least cost least risk" principle. Taking a
5 long-term fixed price position in a commodity does not
6 follow this principle.
7 Q. Has this long-term price risk been evidenced in
8 the Company's existing PURPA contracts?
9 A. Yes. The Company currently has 141 PURPA
10 contracts totaling 1,732 MW of nameplate capacity across
11 its six state system. As I mentioned above, Idaho's
12 allocated share of these contract costs averages
13 approximately 6 percent. Over the next ten years, the
14 Company is under contract to purchase 38.9 million MWhs
15 under its PURPA contract obligations at an average price
16 of $66.32 per MWh. The average forward price curve for
17 Mid-Cover this same ten years is $38.11 per MWh25, or a
18 difference of $28.21 per MWh.
19 Q. Under current policies and QF pricing methods,
20 can the Company protect customers from long-term price
21 risk when entering into PURPA contracts?
22 A. No. Unlike a need based long-term transaction,
23 a mandatory purchase under a PURPA long-term fixed price
24 contract must be executed regardless of need.
25 Consequently, these long-term contracts unnecessarily
479 Clements, Di - 29
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1 expose customers to price risk that is not reflected in
2 the contract price.
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480 Clements, Di - 29a
Rocky Mountain Power
1 LONG-TERM RESOURCE PLANNING: PACIFICORP'S IRP PROCESS AND
2 CURRENT RESOURCE NEEDS
3 Q. How does the Company determine its long-term
4 resource needs?
5 A. The Company's long-term planning and resource
6 decisions are thoroughly evaluated through the Company's
7 IRP process. PacifiCorp's IRP is developed with
8 participation from public stakeholders, including
9 regulatory staff, advocacy groups, and other interested
10 parties. The planning process entails: (1) developing an
11 assessment of resource need via a load and resource
12 balance, reflecting current load growth forecasts and
13 existing resources and contracts over a twenty year
14 planning horizon; (2) producing a range of different
15 resource portfolios that could be used to meet the
16 projected resource need; and (3) evaluating the
17 comparative cost and risks of each resource portfolio,
18 taking into consideration a wide range of planning
19 uncertainties, in order to identify the least cost and
20 least risk preferred portfolio. Once a preferred
21 portfolio is selected, an action plan is developed that
22 identifies the specific resource actions the Company will
23 take over the next two to four years to implement its
24 resource plan.
25 Q. How does the IRP influence the types of
481 Clements, Di - 30
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1 long-term transactions entered into by the Company?
2 A. The Company would not plan to enter into
3 long-term transactions unless a long-term resource need
4 is identified in the !RP preferred portfolio. As noted
5 above, long-term resource needs are typically identified
6 in the !RP only after lower-cost, lower-risk short-term
7 resource opportunities are exhausted such that a
8 long-term resource is required to meet customer load
9 requirements. If the !RP identifies the
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1 need for a long-term resource in the near-term, an IRP
2 action item would specify the Company's plans to acquire
3 the resource, which might include issuance of a request
4 for proposal.
5 Q. What long-term transactions have been included
6 in recent and current IRP action plans?
7 A. The 2013 IRP, which is the reference for
8 current avoided costs in Idaho, included a combined cycle
9 combustion turbine ("CCCT") gas plant in 2024. Due to
10 the timing of the identified need for this resource, the
11 2013 IRP action plan did not include any action items to
12 procure this long-term resource. The 2013 IRP Update,
13 filed with the Commission in March 2014, pushed the CCCT
14 out to 2027. Again, due to the timing of this identified
15 need, the Company has not developed an action item to
16 procure this long-term resource. The Company is in the
17 process of preparing its 2015 IRP, which will be filed
18 with the Commission in March 2015. The 2015 IRP draft
19 preferred portfolio pushes the CCCT out even further to
20 2028. As in the 2013 IRP and the 2013 IRP Update, the
21 2015 IRP draft action plan does not include any action
22 items to procure this long-term resource.
23 Q. What conclusion can you draw from the draft
24 2015 IRP preferred portfolio and associated draft action
25 plan?
483 Clements, Di - 31
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1 A. The Company does not have a need for a new
2 long-term resource until 2028, and due to the timing of
3 this need, the Company will not have any action items to
4 procure a new long-term resource in the next two to four
5 years.
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1 Q. How is the Company's proposal to limit QF
2 contract terms to three years in length aligned with the
3 IRP planning process?
4 A. The full IRP is published every other year,
5 with an update published in the off years. As described
6 earlier in my testimony, the IRP process includes a
7 rigorous review of the Company's resource needs by
8 evaluating its load and resource balance and establishing
9 a least cost, least risk resource plan through
10 comprehensive and rigorous modeling of numerous resource
11 alternatives. The planning environment is constantly
12 changing. This is evidenced by changes in the Company's
13 load and resource balance, state and federal
14 environmental policies, wholesale power and natural gas
15 prices, market products, market rules and contracting
16 practices, and cost and performance of new generating
17 technologies, to name a few. While the Company's
18 planning process is robust and designed to reasonably
19 capture a wide range of uncertainties, the magnitude of
20 the various planning uncertainties grows as you get
21 further out into the IRP 20-year planning horizon. It is
22 for this very reason that IRP action items focus on the
23 front two to four years of the planning period and that
24 the IRP planning process is repeated every two years with
25 updates in the off years. Even within these biannual
485 Clements, Di - 32
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1 planning cycles, material changes in Company's resource
2 needs have been observed from one IRP to the next. The
3 Company's proposal to limit QF contract terms to three
4 years in length is more aligned with the two year IRP
5 planning cycle, and the associated two to four year
6 action plan period. Aligning a QF contract term limit to
7 the IRP planning cycle will ensure avoided cost pricing
8 remains consistent with the most up-to-date information
9 regarding the Company's
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1 resource needs and limit long-term price risk.
2 Q. Please summarize your testimony and the
3 Company's requested relief.
4 A. The Company is seeking immediate relief on one
5 item and permanent implementation of two modifications to
6 QF contracting and pricing procedures. These changes are
7 necessary in order to maintain the ratepayer indifference
8 standard required by PURPA and to protect Idaho
9 customers. Specifically, the Company is requesting an
10 order from the Commission directing implementation of the
11 following:
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2.
3.
Immediate reduction, on a temporary basis, of
the maximum contract term for PURPA contracts
between QFs and PacifiCorp from 20 years to
five years, pending litigation of this case.
Permanent reduction of the maximum contract
term for PURPA contracts from 20 years to three
years, to be consistent with the Company's
hedging and trading policies and practices for
non-PURPA energy contracts and more aligned
with the IRP cycle.
Modification of the Company's avoided cost
methodology such that preparation of indicative
prices for QFs shall reflect all active QF
projects in the pricing queue ahead of any
487 Clements, Di - 33
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1 newly proposed QF requests for indicative
2 prices.
3 The immediate short-term relief is necessary to protect
4 Rocky Mountain Power customers from being adversely
5 impacted by the Idaho Power Order. The Company has
6 received 130 MW of pricing requests from proposed QFs who
7 now intend to wheel power to PacifiCorp to obtain PURPA
8 contracts with a 20-year
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1 term. This action, if allowed to continue, will result
2 in disparate treatment of Rocky Mountain Power's
3 customers, an unfair result that is inconsistent with the
4 Commission's historical treatment of utilities in similar
5 circumstances.26
6 In addition to seeking immediate, temporary relief,
7 the Company is seeking longer-term relief as a result of
8 a significant increase in PURPA contract requests
9 received in 2014 and 2015, activity that Rocky Mountain
10 Power believes will harm customers unless the Commission
11 directs permanent modifications to the Company's current
12 Idaho avoided cost contracting and pricing procedures.
13 As noted, PacifiCorp currently has pending requests for
14 275.5 MW of new PURPA contracts in Idaho, in addition to
15 the 189.6 MW of existing contracts. By comparison, Rocky
16 Mountain Power's minimum retail load in Idaho in 2014 was
17 169 MW. Across its six-state system, PacifiCorp currently
18 has 3,641 MW of new PURPA contract requests, in addition
19 to the 1,732 MWs of PURPA power already under contract.
20 This striking increase in new QF activity exposes
21 customers to higher price risk due to the sheer volume of
22 power that may become locked in at a fixed price for
23 decades under current Commission contract terms.
24 Given this exponential increase in QF contracting
25 activity, it is critical to quickly adjust pricing and
489 Clements, Di - 34
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1 contracting procedures now that problems with those
2 procedures have been identified. The current
3 Commission-approved PURPA contract length puts retail
4 customers at risk of harm due to significant and
5 unnecessary exposure to long-term price risk, a level of
6 risk the Commission would not accept in the context of a
7 non-PURPA transaction. The Company has
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490 Clements, Di - 34a
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1 no control over this price risk; it must purchase
2 essentially an unlimited quantity of QF power under terms
3 and conditions the Commission controls. Under PURPA, only
4 the Commission can mitigate this price risk to customers.
5 The Company can mitigate the risk to customers of
6 other long-term transactions. When the Company considers
7 non-PURPA transactions, the Company first reviews the
8 proposed purchase from a risk-management perspective.
9 The Company's practice since it completed the hedging
10 collaborative workshops in 2012 has been to limit hedges
11 to 36 months or less unless stakeholders express interest
12 for longer term hedges. As explained above, transactions
13 that exceed 36 months require extensive analysis and
14 progressively higher level of management review. The
15 primary reason that such a rigorous review process is
16 necessary when entering into long-term transactions, and
17 the reason the Company generally limits trading and
18 hedging activities to the prompt 36 months, is that
19 long-term fixed price energy contracts carry significant
20 price risk. The market becomes more and more uncertain
21 as you move further into the future, and it is difficult
22 to forecast with reasonable certainty what prices will be
23 far out into the future. Moreover, the Company does not
24 typically enter into long-term transactions unless those
25 transactions have been identified as least cost, least
491 Clements, Di - 35
Rocky Mountain Power
1 risk transactions through the IRP process. Even then,
2 the Company typically utilizes a rigorous RFP process to
3 acquire any long-term resource identified by the IRP
4 action plan. At this point in time, the Company does not
5 have a need for a new long-term resource until 2028, and
6 due to the timing of this need, the
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492 Clements, Di - 35a
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1 Company will not have any action items to procure a new
2 long-term resource in the next two to four years.
3 The situation facing the Company and its Idaho
4 customers is one that they have experienced in the past:
5 significant industry changes, low gas prices, surplus of
6 energy and capacity, and the primary use of short-term
7 purchases to meet load. In proceedings in 1996 and 1997,
8 the Commission appropriately responded to this precise
9 situation by reducing PURPA contract terms from 20 years
10 to five years:
11 Significant changes have swept through the electric
industry since we last examined the issue of
12 contract length. The FERC has mandated open access
to the transmission system, thermal technologies
13 have improved, gas prices are low, there is a
considerable surplus of energy available in this
14 region resulting in very low spot market prices for
electricity and, finally, even the continued
15 existence of PURPA is being called into question.
We find that as the industry as a whole continues to
16 transform to a more free market model, we cannot
justify obligating utilities to 20-year contracts
17 for PURPA power. As the utilities in this case note,
such an obligation does not reflect the manner in
18 which they are currently acquiring power to meet new
load; through short-term (five years or less)
19 purchases. Consequently, it would be nothing more
than an artificial shelter to the QF industry to
20 provide those projects with contract terms not
otherwise available in the free market. We can find
21 no justification for insisting that Idaho's
investor-owned utilities and their ratepayers assume
22 such an obligation simply to foster one particular
segment of an increasingly competitive industry. We
23 find, therefore, that Idaho's investor-owned
utilities shall not be required to offer contracts
24 to QFs in excess of five years until further action
is taken by this Commission. This ruling, however,
25 does not prevent utilities from offering for
493 Clements, Di - 36
Rocky Mountain Power
1
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approval QF contracts with terms that exceed five
years should the utilities believe that such
contracts are in the best interests of their
ratepayers.
4 See Case No. IPC-E-95-9, Order No. 26576; Case No.
5 IPC-E-97-9, Order No. 27111; Case No. WWP-E-97-8, Order
6 No. 27212; Case No. UPL-E-97-4, Order No. 27213 (emphasis
7 added). The Company requests that the Commission respond
8 to the current
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494 Clements, Di - 36a
Rocky Mountain Power
1 situation as it did in the 1996 and 1997 proceedings: by
2 reducing the maximum PURPA contract term; in this case,
3 from 20 years to three years.
4 Moreover, the current, Commission-approved
5 methodology allows QFs to lock in long-term contracts
6 with pricing that is above the Company's incremental cost
7 of energy and capacity because projects that are in the
8 pricing queue ahead of the next proposed project are not
9 considered and included in the calculation of indicative
10 pricing. Brian Dickman describes how this impact can be
11 as much as $18 per MWh for a queue that includes
12 approximately 3,000 MW of queued QF power, or 641 MW less
13 than the current queue. Given the magnitude of new QF
14 requests, this one-way error is becoming progressively
15 more harmful to retail customers. Therefore, the Company
16 requests the Commission direct that preparation of
17 indicative prices for QFs reflect all active QF projects
18 in the pricing queue ahead of any newly proposed QF
19 request for indicative prices.
20 The requested temporary relief and the permanent
21 modifications to the Company's current Idaho avoided cost
22 contracting and pricing procedures are required at this
23 time to maintain the ratepayer indifference standard
24 required by PURPA and to protect Idaho customers from
25 near-term and ongoing harm.
495 Clements, Di - 37
Rocky Mountain Power
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Q.
A.
Does this conclude your direct testimony?
Yes.
496 Clements, Di - 37a
Rocky Mountain Power
1 Q. Please state your name, business address, and
2 present position with Rocky Mountain Power ("Rocky
3 Mountain Power"), a division of PacifiCorp.
4 A. My name is Paul H. Clements. My business
5 address is 201 S. Main, Suite 2300, Salt Lake City, Utah
6 84111. My present position is Senior Originator/Power
7 Marketer for Rocky Mountain Power. Rocky Mountain Power
8 is a division of PacifiCorp.
9 Q. Are you the same Paul H. Clements who
10 previously submitted direct testimony in this proceeding?
11 A. Yes.
12 PURPOSE AND SUMMARY OF TESTIMONY
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Q.
A.
What is the purpose of your rebuttal testimony?
The purpose of my rebuttal testimony is to
15 address certain issues raised by Dr. Don Reading in his
16 direct and rebuttal testimony filed on behalf of J. R.
17 Simplot Company ("Simplot") and Clearwater Paper
18 Corporation ("Clearwater"), and Mr. R. Thomas Beach and
19 Mr. Adam Wenner in their direct testimony filed on behalf
20 of the Idaho Conservation League and the Sierra Club. My
21 testimony will also indirectly address the same or
22 similar issues raised by other witnesses on behalf of
23 intervenors that oppose the petition of Idaho Power
24 Company ("Idaho Power") in Case No. IPC-E-15-01 or the
25 petition of Avista Corporation ("Avista") in Case No.
497 Clements, Re - 1
Rocky Mountain Power
1 AVU-E-15-01.
2 My testimony will explain why:
3 (1) the citation of Dr. Reading to testimony of Mr.
4 Gregory N. Duvall on behalf of PacifiCorp in
5 Washington Utilities and Transportation
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498 Clements, Re - la
Rocky Mountain Power
1 Commission ("WUTC") cases does not support the
2 position of Simplot and Clearwater that the term of
3 power purchase agreements ("PPAs") with qualifying
4 facilities ("QFs") should not be reduced at this
5 time;
6 (2) it is appropriate for generation resources owned
7 and operated by public utilities to be treated
8 differently than generation resources owned and
9 operated by QFs;
10 (3) it is not a violation of the Public Utility
11 Regulatory Policies Act of 1978 ("PURPA") to limit
12 the term of PPAs with QFs to three years;
13 (4) the alternative proposal of Simplot and
14 Clearwater to maintain a 20-year term for QF
15 contracts, but to allow the energy component of the
16 price to vary during the last ten years of the term
17 does not significantly reduce the risks which
18 customers are exposed to by long-term contracts;
19 and,
20 (5) providing QFs with longer term contracts than
21 current hedging guidelines is potentially harmful to
22 customers.
23 My testimony also notes that no party has opposed the
24 recommendation of Mr. Brian S. Dickman that the
25 Integrated Resource Plan ("IRP") Method of determining
499 Clements, Re - 2
Rocky Mountain Power
1 indicative pricing for proposed QF projects on the
2 Company's system includes prior QF requests for
3 indicative pricing and that Commission Staff supports his
4 recommendation.
5 Q. Does the fact that you are not commenting on
6 other issues raised in the direct or rebuttal testimony
7 of these or other witnesses indicate that you agree with
8 their positions?
9 A. No. I believe that other issues raised by
10 witnesses for parties opposing the
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500 Clements, Re - 2a
Rocky Mountain Power
1 petitions of the utilities in these consolidated cases
2 have been more than adequately addressed in the direct
3 testimony filed by the utilities or in the direct and
4 rebuttal testimony of Mr. Rick Sterling filed on behalf
5 of the Staff of the Commission. I also understand that
6 Idaho Power and Avista are filing rebuttal testimony
7 addressing the issues raised by opponents to their
8 petitions.
9 Q. Is Rocky Mountain Power filing rebuttal
10 testimony of any other witness in these consolidated
11 cases?
12 A. No.
13 TESTIMONY OF MR. GREGORY N. DUVALL IN WASHINGTON
14 Q. Dr. Reading cites testimony of Mr. Duvall in
15 two Washington Utilities and Transportation Commission
16 ( "WUTC") cases in support of his argument that it is
17 inappropriate to compare the price of PURPA resources to
18 market prices. ( Reading Direct. page. 17, line 1 - page
19 18, line 2.) Does Mr. Duvall's testimony support
20 Simplot's and Clearwater's opposition to the petitions of
21 the utilities to shorten the term of QF contracts?
22 A. No. Mr. Duvall's testimony did not address the
23 subject of the appropriate term of QF contracts in the
24 current environment and did not in any way suggest that
25 QF contracts need to have a term of 20 years to ensure
501 Clements, Re - 3
Rocky Mountain Power
1 that they include capacity payments.
2 Q. What did Mr. Duvall's rebuttal testimony in the
3 2013 WUTC docket address?
4 A. Mr. Duvall's rebuttal testimony in WUTC Docket
5 UE-130043 was offered in response to claims by parties in
6 that general rate case that the costs of
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502 Clements, Re - 3a
Rocky Mountain Power
1 PacifiCorp's contracts with QFs located in California and
2 Oregon should not be included in its net power costs for
3 purposes of determining rates for customers in Washington
4 even though those projects were located in PacifiCorp's
5 West Control Area. As this Commission is aware,
6 Washington has a unique position among PacifiCorp's
7 states in refusing to include an attributable share of
8 system wide resources in Washington's cost of service and
9 limiting the cost of service to include only certain West
10 Control Area resources. Parties in the general rate case
11 took the position that the costs of existing contracts
12 with QFs located in California and Oregon should not be
13 included even though power purchased under those
14 contracts supported service to customers in Washington.
15 One of the party's arguments in support of that
16 position was that excluding the Oregon and California QF
17 contracts from West Control Area net power costs is
18 equivalent to replacing these resources with market
19 purchases. The sentence from Mr. Duvall's testimony
20 quoted by Dr. Reading was in response to that argument.
21 Mr. Duvall explained that PacifiCorp's Schedule 37 in
22 Washington requires the Company to pay QFs located in
23 Washington a payment for both energy and capacity, with
24 energy payments reflecting the Company's incremental cost
25 of market transactions and thermal output, and capacity
503 Clements, Re - 4
Rocky Mountain Power
1 payments reflecting the fixed costs associated with a
2 simple cycle combustion turbine for three months per
3 year. Thus, Mr. Duvall was pointing out that the
4 argument of the party was inconsistent with current
5 Washington regulations.!
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504 Clements, Re - 4a
Rocky Mountain Power
1 Dr. Reading failed to note that one of the reasons
2 for the opposition to inclusion of contract costs
3 associated with QFs located in California and Oregon
4 offered by WUTC Staff was that the avoided costs for QF
5 projects entering into contracts in California and Oregon
6 were determined for terms longer than the terms in
7 Washington. In Washington, PacifiCorp's standard avoided
8 costs are available only for terms of up to five years.
9 WUTC Staff argued, as do the utilities in this case, that
10 the longer terms in the QF contracts in California and
11 Oregon exposed customers to unreasonable risks.2 It was
12 also apparent that there was a recent significant
13 increase in purchases of power from new QF projects in
14 California and Oregon, consistent with the evidence in
15 this case.3 The Washington Commission accepted the
16 position of Staff and other parties in the 2013 general
17 rate case and excluded Washington's allocated share of
18 the costs associated with contracts with QF projects
19 located in California and Oregon from PacifiCorp's net
20 power costs in Washington.
21 Q. What was addressed in Mr. Duvall's testimony in
22 the 2014 WUTC docket?
23 A. Mr. Duvall's testimony in the 2014 general rate
24 case was an effort to have the Washington Commission
25 reconsider its prior ruling. The point of his testimony
505 Clements, Re - 5
Rocky Mountain Power
1 was that it is inappropriate for the Washington
2 Commission to disallow costs of PURPA contracts approved
3 by other state commissions. In support of this point, he
4 explained why avoided costs determined in the past may
5 have been reasonable then, but may differ from current
6 market prices. He did not testify that state
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3 Id. at 7-9 (pages 19-20 of Duvall Rebuttal Testimony).
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506 Clements, Re - Sa
Rocky Mountain Power
1 commission's should require long QF contract terms so
2 that capacity costs are included or that capacity costs
3 should be included if they are not avoided. His
4 testimony is not inconsistent with Rocky Mountain Power's
5 position in this case.
6 Rocky Mountain Power's position is that the
7 Commission should approve a modification to the current
8 requirements for new PPAs with QFs to reduce the term of
9 contracts from 20 to three years because in the current
10 environment a 20-year term creates too much price risk
11 for customers. Mr. Duvall's testimony urging the
12 Washington Commission to allow PacifiCorp to recover an
13 appropriate share of the costs of previously-approved QF
14 contracts is unrelated to that position.
15 UTILITY RESOURCES ARE NOT COMPARABLE TO QF FACILITIES
16 Q. Dr. Reading claims that reducing the term of QF
17 contracts is unfair because when utilities build or
18 acquire generation plants or contract for resources, they
19 have or may have much longer lives. (See, e.g., Reading
20 Direct page 9 lines 8-16, page 12 lines 1-5, page 13 line
21 13 - page 15 line 6; Reading Rebuttal page 7 lines 7-11,
22 page 8 lines 13-19.) Do you agree that QFs must be
23 treated the same as utility resources?
24 A. No. In my direct testimony, I identified most
25 of the differences between utility resources and QFs that
507 Clements, Re - 6
Rocky Mountain Power
1 justify different treatment. As I discussed there, before
2 a utility builds or acquires a resource, it goes through
3 an extensive management review and integrated resource
4 plan ("IRP") process identifying needs and potential
5 resources, including identifying the portfolio of
6 resources that will meet future requirements on a
7 least-cost and least-risk basis. The utility may also be
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508 Clements, Re - 6a
Rocky Mountain Power
1 required to obtain a certificate of public convenience
2 and necessity before constructing a new resource. This
3 requires a demonstration that the resource is needed and
4 that its construction is in the public interest. In
5 addition, major utility resources are acquired only
6 through a thorough request for proposals ("RFP") process
7 that is often monitored by an independent evaluator.
8 After a resource is acquired, it is used or dispatched by
9 the utility only when its use is the best available
10 alternative.
11 In addition, acquisition of utility resources that
12 are viewed as hedges against future price volatility,
13 (such as market-based PPAs), are done only for terms of
14 up to three years unless interested stakeholders,
15 including regulators and customer representatives, agree
16 that longer term hedges should be acquired. And hedges
17 are only transacted based on strict risk management
18 policies that consider need and that do not allow hedging
19 beyond a reasonable portion of the utility's anticipated
20 load.
21 PURPA contracts, on the other hand, are based on
22 projects built by a third party without any assessment of
23 the needs of the utility and without any of the scrutiny
24 imposed by the IRP, certificate of public convenience and
25 necessity or RFP processes, let alone the heightened
509 Clements, Re - 7
Rocky Mountain Power
1 management review associated with longer term resources.
2 The prices for the QF projects are based on the utility's
3 avoided costs rather than the costs of the project.
4 Depending on the nature of the PPA, the QF may sell power
5 to the utility whenever it wishes without regard to the
6 utility's needs at any given time and without regard to
7 the availability of lower cost resources to meet current
8 needs.
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510 Clements, Re - 7a
Rocky Mountain Power
1
2
Q.
A.
Do other witnesses agree with your position?
Yes. In addition to the witnesses for Idaho
3 Power and Avista, Mr. Rick Sterling of the Conunission
4 Staff has explained why it is appropriate to treat
5 utility generation resources differently than QF
6 resources in his rebuttal testimony. In addition to some
7 of the reasons, I have reiterated above, Mr. Sterling
8 points out that many of the differences in treatment are
9 required by PURPA and are advantageous to the QF. He also
10 notes that the fuel and variable costs of utility
11 resources are subject to annual adjustment, but PURPA
12 prices are fixed for the entire duration of the contract.
13 (Sterling Rebuttal, page 1 line 18 - page 2 line 22.)
14 Q. In the context of these differences, is your
15 reconunendation that the term of QF contracts be reduced
16 to three years fair in light of the fact that some
17 existing utility generation plants and other resources
18 have longer anticipated lives?
19 A. Yes. The fact that a PURPA contract only has a
20 term of three years does not mean that the project will
21 have only a three-year life. Rocky Mountain Power will
22 be required to purchase the power produced by the project
23 as long as PURPA requirements exist and the project
24 qualifies as a QF under PURPA. Limiting the term of the
25 contract to three years simply means that the price Rocky
511 Clements, Re - 8
Rocky Mountain Power
1 Mountain Power and its customers will be required to pay
2 to the QF will be subject to adjustment every three years
3 and be more closely aligned with Rocky Mountain Power's
4 current avoided costs.
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Rocky Mountain Power
1 PURPA DOES NOT REQUIRE LONG-TERM CONTRACTS
2 Q. Mr. Adam Wenner offers his opinion that
3 reducing the term of QF contracts from 20 to two years as
4 proposed by Idaho Power is inconsistent with FERC's
5 regulations and PURPA. (Wenner Direct page 2, lines 5-8.)
6 Do you agree?
7 A. Before answering, I want to make clear that I
8 am not an attorney and am not offering a legal opinion.
9 My answer is based on my knowledge of the contract terms
10 for PURPA contracts in PacifiCorp's states and my
11 understanding of the plain language of PURPA and FERC
12 regulations.
13 As I stated in my direct testimony, this Commission
14 previously reduced the term of contracts to five years
15 during the period from 1997 to 2002. I am not aware that
16 FERC or any Court concluded that this action by the
17 Commission was contrary to PURPA or FERC regulations.
18 I am also aware that the Company only offers fixed
19 standard avoided costs in Washington for up to five
20 years. Again, I am not aware that FERC or any court
21 concluded that these terms, significantly shorter than 20
22 years, are inconsistent with PURPA or FERC regulations.
23 I have reviewed both PURPA and the FERC regulations
24 under PURPA and have been unable to locate any statement
25 that contracts approved under PURPA are to have any
513 Clements, Re - 9
Rocky Mountain Power
1 specific term. I have also reviewed Mr. Wenner's
2 testimony and fail to see any citation in his testimony
3 that expressly requires contracts approved under PURPA to
4 have any specific term. On the other hand, as noted in
5 my direct testimony, I am aware of cases indicating that
6 state
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Rocky Mountain Power
1 commissions have wide discretion in establishing the key
2 terms and conditions of PURPA contracts as long as their
3 actions are consistent with FERC's regulations. {See
4 Clements Direct, page 9 line 20 - page 10 line 7.)
5 SIMPLOT'$ AND CLEARWATER'S ALTERNATIVE PROPOSAL IS NOT IN
6 THE PUBLIC INTEREST
7 Q. In his rebuttal testimony, Dr. Reading proposes
8 an alternative that he claims balances the interests of
9 utilities and QFs. {Reading Rebuttal, page 3 lines 6-16.)
10 Does this alternative proposal satisfy the concerns of
11 Rocky Mountain Power?
12 A. No. The primary concern of Rocky Mountain Power
13 that led to its petition is that it is currently
14 inundated with proposals for new QF projects to provide
15 power that is not needed to meet customers' needs.
16 Entering into contracts with these proposed projects for
17 a term of 20 years would expose customers to unreasonable
18 price risks. Dr. Reading's alternative proposal does not
19 significantly mitigate this risk.
20 The alternative QF contract terms suggested by Dr.
21 Reading, which include a fixed capacity payment for 20
22 years and fixed energy payments for 10 years, still
23 expose customers to unnecessary long term fixed price
24 risk for the same reasons set forth in my direct
25 testimony. Namely, they still:
515 Clements, Re - 10
Rocky Mountain Power
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2.
3.
exceed the Company's current hedging policies and
practices;
are not consistent with the Company's IRP-based long
term planning approach; and,
are not consistent with the Company's RFP-based
6 approach to obtaining long
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516 Clements, Re - lOa
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1 term resources.
2 The terms of Dr. Reading's alternative proposal expose
3 customers to risks that they would not otherwise have
4 absent the QF.
5 LONG-TERM QF CONTRACTS ARE NOT AN EFFECTIVE HEDGE
6 Q. Mr. Beach states in his direct testimony that
7 20-year QF contracts provide hedging benefits. (Beach
8 Direct, page 21, line 8 - page 25, line 25.) Do you
9 agree?
10 A. No. As discussed in my direct testimony, during
11 the collaborative process involving Rocky Mountain Power,
12 regulators and customer representatives in 2011 and 2012,
13 a consensus was reached that the Company should not hedge
14 beyond a three-year time horizon unless stakeholders
15 expressed a specific interest for longer term hedges
16 based on current market conditions. Contracts with QFs
17 for twenty years or even ten years are far beyond that
18 time horizon found reasonable in the collaborative
19 process. They are also far beyond the term of any other
20 hedge implemented by the Company as set forth in its risk
21 management policy.
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517 Clements, Re - 11
Rocky Mountain Power
1 THERE IS NO OPPOSITION TO MODIFYING THE AVOIDED COST
2 PRICING METHOD TO CONSIDER ALL PURPA CONTRACTS IN THE
4 Q. In his direct testimony, Mr. Brian Dickman
5 proposed that the Commission modify the IRP method for
6 determining avoided costs for non-standard QF projects to
7 account for proposed QF projects on the Company's system
8 prior to the next Idaho QF requesting indicative pricing.
9 (Dickman Direct page 11 lines 6-10.)
10 Did the witnesses for other parties comment on this
11 recommendation?
12 A. Yes. Commission Staff witness Mr. Yao Yin,
13 supports Rocky Mountain Power's proposal. (Yin Direct,
14 page 9, line 18 - page 10, line 4.) Dr. Reading,
15 testifying on behalf of Simplot and Clearwater, states
16 that "Rocky Mountain Power's suggestion to update the
17 resource stack more quickly to respond to large influxes
18 of QFs may also be appropriate." (Reading Direct, page
19 35, lines 5-7.)
20 CONCLUSION
21 Q. What is your conclusion and recommendation?
22 A. Witnesses for intervenors that oppose Rocky
24 or evidence for the Commission to reject Rocky Mountain
25 Power's request to reduce the term of QF contracts from
23 Mountain Power's petition have not provided sound reasons
Clements, Re - 12
Rocky Mountain Power
518
1 20 to three years.
2 My testimony that the Company has experienced a
3 significant increase in QF pricing requests in Idaho and
4 across its six-state system, the Company has no need for
5 new resources until 2028, and the Company's hedging
6 practices and policies are short-term in nature is
7 un-rebutted. My testimony that given the
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519 Clements, Re - 12a
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1 magnitude of new QF requests, and considering the
2 inherent uncertainties in projecting avoided cost rates
3 out 20 years or more, current Idaho avoided cost rates
4 are adversely impacting customers and will continue to do
5 so for 20 years is also un-rebutted.
6 The Company's request for approval of a permanent
7 reduction in the maximum contract term for PURPA
8 contracts, from 20 years to three years would be more
9 consistent with the Company's hedging and trading
10 policies and practices for non-PURPA energy contracts and
11 more aligned with the IRP cycle. This change is necessary
12 in order to maintain the ratepayer indifference standard
13 required by PURPA and to protect Idaho customers.
14 The Company's request that the Commission modify the
15 IRP Method to account for proposed QF projects on the
16 Company's system prior to the next Idaho QF requesting
17 indicative pricing is not opposed and should be approved
18 for the reasons stated in Mr. Dickman's direct testimony.
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A.
Does this conclude your rebuttal testimony?
Yes.
520 Clements, Re - 13
Rocky Mountain Power
1 (The following proceedings were had in
2 open hearing.)
3 MS. HOGLE: Mr. Clements is available for
4 cross-examination at this time.
5 COMMISSIONER KJELLANDER: Thank you.
6 Ms. Huang? Mr. Howell.
7 MR. HOWELL: Sorry to trip you up there,
8 Mr. Chairman. No questions.
9
10 Walker.
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12
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. WALKER: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Are there
13 any questions from Avista?
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MR. ANDREA: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Let's
16 see, Mr. Adams.
17
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MR. ADAMS: No questions.
COMMISSIONER KJELLANDER: Thank you, Mr. Adams.
19 Mr. Richardson.
20
21 a couple.
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MR. RICHARDSON: Thank you, Mr. Chairman, just
COMMISSIONER KJELLANDER: Please proceed.
MR. RICHARDSON: Thank you.
CSB REPORTING
[phone]
521 CLEMENTS
Rocky Mountain Power
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3 BY MR. RICHARDSON:
CROSS-EXAMINATION
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Q.
A.
Q.
Good afternoon, Mr. Clements.
Good afternoon.
So on page 3 of your direct testimony, there in
7 the middle of the page, beginning on line 8, you compare
8 the 465 megawatts of existing and proposed PURPA projects
9 in Idaho to Rocky Mountain's average load of 432
10 megawatts, but these two numbers don't have comparable
11 capacity factors, do they? One is an average and the
12 other is a nameplate number?
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Q.
A.
Q.
Yeah, that's correct.
So don't you find that a little misleading?
No, I don't. I labeled it clearly as such.
At the bottom of page 4 of your direct
17 testimony, you note that shortly after the Commission
18 lowered the eligibility cap for Idaho Power that several
19 QF developers sought to wheel their power through Rocky
20 Mountain, and then over to the top of page 5 you call
21 that arbitrage. Did you read Mr. Kalich's testimony?
22
23
A.
Q.
Yes, I did.
And do you recall where he was referring to a
24 similar situation and he referred to it as rational
25 economic behavior?
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1
2
A.
Q.
I vaguely recall that, yes.
So over to the top of page 6, you talk about
3 the Company's hedging program as a rationale for limiting
4 QF contracts, and I was wondering if you could point me
5 to where in any PURPA or FERC implementing rules or laws
6 that contract terms are tied to utility hedging programs.
7 A. I don't believe anywhere in PURPA rules or laws
8 does it speak directly to contract terms in general.
9 Q. I was talking about hedging, utility hedging,
10 programs.
11 A. Yes, the premise of your question implied that
12 FERC rules and regs had a specific contract term, and I
13 don't agree with that premise, but to answer your
14 question, I don't believe anywhere do PURPA rules or regs
15 speak to hedging.
16 Q. Thank you. On page 12 of your direct
17 testimony, you discuss the price risk associated with
18 20-year PURPA contracts. Did you read Mr. Sterling's
19 testimony in this docket?
20
21
A.
Q.
Yes, I did.
And specifically on price risk associated with
22 20-year PURPA contracts, do you agree with Mr. Sterling
23 that the price risk can go both ways; that is, it can
24 prove to be too low to the benefit of the ratepayers as
25 well as too high to the detriment of the ratepayers?
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1
2
A.
Q.
Yes.
On page 25 at line 19, you observe that the
3 Company uses a rigorous request for proposal process to
4 acquire long-term resources. Do you see that?
5
6
7
8
9 Q.
MS. HOGLE: Can you give a line number, please?
MR. RICHARDSON: Line 19.
MS. HOGLE: Thank you.
THE WITNESS: Yes.
BY MR. RICHARDSON: Did the Company put its
10 recently constructed Currant Creek plant out to bid
11 pursuant to an RFP?
12
13 the scope.
14
MS. HOGLE: Your Honor, on scope, outside of
MR. RICHARDSON: Your Honor, the witness is
15 talking about the rigorous process that their RFP's are
16 put through and I'm exploring that issue.
17 COMMISSIONER KJELLANDER: I'll allow it and
18 we'll see where it goes.
19
20
MR. RICHARDSON: I'm sorry?
COMMISSIONER KJELLANDER: Thank you, my
21 apologies. I'll allow it and we'll see where it goes.
22 Q. BY MR. RICHARDSON: So did the Company put its
23 recently constructed Currant Creek plant out to bids
24 pursuant to an RFP?
25 A. Yes, my understanding is they did. That was a
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524 CLEMENTS (X)
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1 couple of years before I joined the Company, at least
2 that's my understanding.
3 Q. Are you familiar with the jury verdict against
4 PacifiCorp for misappropriating
5
6
MS. HOGLE: Objection, Your Honor.
COMMISSIONER KJELLANDER: We have an objection
7 and the objection --
8
9
MR. RICHARDSON: Can I finish the question?
COMMISSIONER KJELLANDER: That probably would
10 be appropriate to hear the whole question.
11
12 Q.
MR. RICHARDSON: Thank you.
BY MR. RICHARDSON: Are you familiar with the
13 jury verdict against PacifiCorp for misappropriating
14 trade secrets from a potential bidder to build that
15 project?
16 COMMISSIONER KJELLANDER: And now we're ready
17 for the objection.
18 MS. HOGLE: Thank you, Your Honor. The Company
19 objects on the basis of relevance and outside the scope
20 of this proceeding.
21 MR. RICHARDSON: Mr. Chairman, it's highly
22 relevant to the rigorous RFP process the witness
23 testified to.
24 COMMISSIONER KJELLANDER: Do you want to weigh
25 in any more?
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1 MS. HOGLE: Yes, Your Honor, thank you. Your
2 Honor, that was many years ago and Mr. Clements has just
3 testified that that happened before he was a Company
4 employee.
5 COMMISSIONER KJELLANDER: Mr. Richardson, I'm
6 inclined to agree with Ms. Hogle that it is outside the
7 scope of this witness' ability to testify on any layer of
8 granularity associated with the court case that you are
9 referencing.
10 MR. RICHARDSON: Mr. Chairman, I promise not to
11 get into any granularity. I have one final question for
12 this witness.
13
14 Q.
COMMISSIONER KJELLANDER: Please continue.
BY MR. RICHARDSON: Do you think that
15 misappropriation of trade secrets could have a chilling
16 effect on possible bidders in future RFP's the Company
17 may issue?
18 MS. HOGLE: Objection, Your Honor. I believe
19 he's asking for a legal opinion and Mr. Clements is not a
20 lawyer.
21 MR. RICHARDSON: Mr. Chairman, the words
22 "chilling effect" is not a legal term.
23 MS. HOGLE: Mr. Chairman, I object to the use
24 of "misappropriation of trade secrets."
25 COMMISSIONER KJELLANDER: Mr. Richardson.
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1 MR. RICHARDSON: I think I'm finished,
2 Mr. Chairman.
3 COMMISSIONER KJELLANDER: Thank you very much.
4 We'll move to Mr. Otto.
5 MR. OTTO: Thank you, Mr. Chairman. I do have
6 a few questions.
7
8
9
10 BY MR. OTTO:
CROSS-EXAMINATION
11 Q. Mr. Clements, on your rebuttal testimony, page
12 9, you discuss -- you offer an opinion. I'm not going to
13 ask you for a legal opinion. I'm just asking for your
14 awareness of certain things on the consistency of a
15 two-year contract with PURPA regulations, and you state
16 that you're not aware of a regulation or a FERC order
17 that speaks to the issue; is that correct? Is that a
18 fair characterization?
19 A. Yeah, that speaks directly to a specific
20 contract term, yes.
21 Q. So just to be a little clearer, you're not
22 aware either way on what the length of contracts -- what
23 term of contract would comply or not with the
24 regulations?
25 A. No, I'm not aware that there is any part of
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1 PURPA rules or regs that say a contract term needs to be
2 X years in length.
3 Q. And then at the very top of page 10 you say
4 that the commissions have wide discretion to establish
5 terms that are consistent with FERC's regulations; are
6 you aware of that?
7
8
9
A.
Q.
A.
Yes.
And you stand by that?
Yes. In fact, in our service territory, we
10 have some states that have a five-year contract term, we
11 have some with 20, so yes, a wide latitude.
12 Q. So now on page 11 of your rebuttal, this is
13 just the question and answer about hedging, and you say
14 that the Company is limited to a three-year time horizon
15 for hedging; is that correct?
16
17 yes.
A. That's the current risk management policy,
18 Q. Does that cover just the fuel cost?
19 A. No, our hedging policy does not cover just fuel
20 cost. It covers other commodities as well.
21 Q. Other commodities, like what other
22 commodities?
23
24
25
A.
Q.
A.
Electricity.
Electricity, okay.
Yeah.
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1 Q. Does the hedging policy cover the power
2 generation unit that the fuel would be burned in?
3 A. If you're referring to the capital costs, no,
4 that's acquired through the IRP process.
5 Q. And when the Company acquires those resources
6 and puts them in the rate base, how long are they in rate
7 base?
8
9
A.
Q.
It depends on the resource type.
So a gas plant, how long is that in the
10 resource base?
11 A. That's a bit outside my knowledge, but I would
12 say it's greater than 20 years. Is that the answer you
13 want?
14 Q. Whatever is the truth, that's the answer I'm
15 looking for, so the Company could hedge the fuel for only
16 three years and that would protect customers from you
17 know, being able to true-up the prices over time; is that
18 correct? That's the purpose of hedging? Sorry, that's
19 the purpose of having a shorter time hedge is to be able
20 to when that time is done, you true-up and maybe you have
21 a different price and that would protect customers?
22 A. Well, there's various purposes for hedging, but
23 the primary purpose of the hedging policy is to reduce
24 volatility in the short term.
25 Q. So even if the Company wasn't buying gas or
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1 buying gas for cheaper, customers are still paying the
2 capital costs on that plant for 20 years; isn't that
3 correct?
4 A. Yes, they are subject to periodic adjustments
5 on return on equity through rate cases and other
6 regulatory proceedings.
7 Q. Now, I'm going to ask you, page 12 -- and if
8 this is more appropriate for Mr. Dickman, just let me
9 know, but you state that no party has rebutted the
10 proposal to update the pricing queue fairly frequently;
11 is that a fair characterization?
12
13
A.
Q.
Yes.
How does a project -- how does PacifiCorp
14 remove a proposed QF from the pricing queue? And, again,
15 if this is better for Mr. Dickman, I understand.
16
17
18
A. Yeah, Mr. Dickman can address that.
MR. OTTO: That's all, Mr. Commissioner.
COMMISSIONER KJELLANDER: Thank you. Let's
19 move now to Mr. Miller.
20
21
22
23
24 Olsen.
25
MR. MILLER: No, thank you.
COMMISSIONER KJELLANDER: Ms. Nunez.
MS. NUNEZ: No questions. Thank you.
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. OLSEN: No questions.
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1 COMMISSIONER KJELLANDER: Thank you, Mr. Olsen.
2 Mr. Sanger.
3
4 questions.
5
6
7
8
MR. SANGER: Yes, Chairman, I have a few
COMMISSIONER KJELLANDER: Please proceed.
CROSS-EXAMINATION
9 BY MR. SANGER:
10 Q. Earlier you renumbered your Exhibit 1 Exhibit
11 601; is that correct?
12
13
A.
Q.
Yes.
Can you tell me what Exhibit 601 is in your own
14 words?
15 A. Yes, that was -- let me get to it. At the time
16 of preparation of my direct testimony, Exhibit 601
17 represents the pricing queue for PacifiCorp's system as a
18 whole for PURPA projects.
19 Q. And how many projects are on Exhibit 601? If
20 you look at your direct testimony on page 16, I believe
21 it says 89.
22
23
24
A.
Q.
A.
That's where I was just heading --
Okay.
-- instead of counting them individually. 89
25 projects, correct.
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1 Q. How many of those projects are hydroelectric
2 projects?
3 A. To my recollection, none, other than
4 potentially one in Oregon, but I don't -- in the "other"
5 category as you'll see in Table 1 on page 16 of my direct
6 testimony, we list them by wind, solar, and other. I'm
7 aware that the other in Idaho is not a hydroelectric
8 facility. I am not aware of what the "other" in Oregon
9 is, so it may be hydroelectric and it may not.
10 Q. If you refer to your Exhibit 601, page 1 of
11 that, I believe that identifies the type of resources.
12
13
A.
Q.
The Oregon one is not hydroelectric.
So there's zero hydroelectric QFs in your
14 queue?
15
16 not.
17
A.
Q.
Currently in the large pricing queue there are
And there are how many non-wind and solar
18 projects?
19 A. I believe there is one based on the list
20 two, I apologize, one in Idaho and one in Oregon.
21 Q. Now, if the Company had no wind or solar QF
22 requests, so assume there were no wind or solar QF
23 requests and Exhibit 601 only had two projects, would the
24 Company have made a petition filing before the Idaho
25 Public Utilities Commission to reduce the contract length
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1 to three years?
2 A. I don't know.· Perhaps we would have. Really,
3 my own opinion of that has changed and it's not so much
4 the magnitude of projects that we've received as a
5 Company, it really has more to do with the planning
6 process and the risk management process that the Company
7 is undergoing, and what really changed in my mind and
8 prompted us to file some of these dockets is what
9 occurred with our 2011 integrated resource plan. In that
10 plan we had gas plants proposed for 2014, 2016, and 2019.
11 In subsequent IRPs, so just two to three years later, our
12 IRP eliminated the need for the 2016 and 2019 gas plants.
13 That caused us to step back and look at our
14 PURPA pricing, and had we executed 20-year PURPA
15 contracts based on those expected 2016 and 2019 gas
16 plants, our customers would not be held indifferent,
17 because subsequent IRPs had us remove those plants and
18 not build them, so we would be paying capacity payments
19 to QFs on plants that were actually not needed by the
20 utility and not planned to be built, and that really
21 changed our thinking on the 20-year contract, so we may
22 have filed regardless.
23 Q. So on your Exhibit 601 you have one Idaho QF
24 that is not a wind and solar project, so your testimony
25 here today is you may have filed the same petition even
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1 if you had one QF that it would apply to?
2
3
A. Yes, we may have.
MR. SANGER: Okay, thank you. No further
4 questions.
5 COMMISSIONER KJELLANDER: Thank you, Mr.
6 Sanger. Mr. Hammond.
7
8
9
10 BY MR. HAMMOND:
CROSS-EXAMINATION
11 Q. This is John Hammond. I'm an attorney with
12 Fisher Pusch. Thanks for being here today. Let's go to
13 your testimony on page 3, your direct testimony. I want
14 to understand a little bit more about the queue in Idaho.
15 My understanding is that it states on line 3, PacifiCorp
16 currently has 189.6 megawatts of existing PURPA contracts
17 in Idaho. Are those signed contracts?
18
19
A.
Q.
Yes.
And of those contracts, are any of those
20 megawatts online at this point? Is PacifiCorp receiving
21 power or Rocky Mountain Power, excuse me?
22 A. I believe, subject to check, that they are all
23 online.
24 Q. And the 275.5 megawatts on line 4 of your
25 testimony of proposed PURPA contracts in Idaho, does
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1 "proposed" mean that they haven't been executed at this
2 point?
3 A. Yes, that means that we are either providing
4 indicative pricing to them or negotiating a power
5 purchase agreement with them, and incidentally, that 275
6 has grown to 531 since the time of filing of my
7 testimony.
8 Q. Have any of those projects fallen out of the
9 queue, to your knowledge?
10
11
A.
Q.
No, not yet.
I believe you testified earlier that some had
12 dropped off. Was that statement incorrect?
13 A. No, meaning some have dropped off and, again, I
14 was mentioning the queue across PacifiCorp's six-state
15 system and some have dropped off because they have
16 removed themselves in Utah. Some of them have dropped
17 off because they actually executed agreements, and once
18 they execute power purchase agreements, they're not in
19 the pricing queue anymore. They're in the resource
20 queue, but to my knowledge, none of the Idaho projects
21 have been removed from the queue.
22 Q. Are you aware whether or not some of these
23 projects, this 275.5 megawatts, are in fact duplicate
24 projects with different design aspects; so meaning it's
25 the same project, but it may be -- has a different hourly
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1 energy profile or is it fixed versus a tracking project,
2 are you aware of any of that?
3 A. There may be some that are fixed versus
4 tracking, but I don't recall off the top of my head.
5
6
7
Q.
A.
Q.
But if there are any duplicates or not?
I don't recall.
Okay. Are you familiar with Rocky Mountain
8 Power's irrigation load control program at all?
9
10
A.
Q.
Somewhat, yes.
Are you aware of what or do you have any sense
11 of what that costs ratepayers each year?
12
13
A.
Q.
I don't.
Okay, do you have any belief or any opinion on
14 whether local distributed solar resources would be more
15 or less costly that that irrigation load control
16 program?
17
18
A.
Q.
I don't.
Are you familiar with the Company's 2015 IRP or
19 integrated resource plan?
20
21
22
23
A.
Q.
A.
Q.
Somewhat, yes.
Did you participate in its creation?
Peripherally, yes.
I believe in your 2000 -- the proposed
24 integrated resource plan, there appears to be somewhere
25 in the magnitude of 700 to 1,400 megawatts of front
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1 office transactions that are needed each year to fill
2 capacity requirements; is that something you're familiar
3 with?
4
5
A.
Q.
That sounds correct, yes.
Okay, do these front office transactions have
6 any benefits under the proposed EPA lll(d) rules that
7 you're aware of?
8 MS. HOGLE: Before you answer that question,
9 Your Honor, I just would ask for a clarification.
10 Initially, I believe, Mr. Hammond asked him about the
11 2015 IRP and in the second question he mentioned the
12 2000, I believe, IRP; maybe have the reporter read that
13 back to us. I just want to make sure we're talking about
14 the same thing.
15 COMMISSIONER KJELLANDER: That's fine or Mr.
16 Hammond if you can recall and clarify that.
17 MR. HAMMOND: I believe I'm speaking
18 specifically about the 2015 proposed IRP.
19
20
21
COMMISSIONER KJELLANDER: Does that assist?
MS. HOGLE: Thank you.
COMMISSIONER KJELLANDER: Thank you for the
22 clarification.
23
24 question.
25
MR. HAMMOND: I guess I'll just restate the
COMMISSIONER KJELLANDER: Please, thank you.
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Rocky Mountain Power
1 Q. BY MR. HAMMOND: Do you have any knowledge in
2 your experience that any of these front office
3 transactions have any proposed benefits or any benefits
4 under the proposed EPA lll(d) rules?
5
6
A.
Q.
I haven't performed that calculation.
Do you know whether Rocky Mountain Power has
7 provided or done an estimate of the carbon emitting
8 profile of these front office transactions?
9
10
A.
Q.
I don't know.
In your experience -- or maybe you can speak to
11 this, I'm not certain, but in your proposed IRP, there's
12 some proposed pricing models that contain information
13 about costs for generating a resource without lll(d)
14 requirements and costs that input those or implement what
15 those estimated lll(d) possible proposals or requirements
16 might be. Are you familiar with that at all?
17 A. Somewhat.
18 Q. Do you have any idea of what the magnitude of
19 pricing difference or the cost difference might be? I
20 suppose it's different for each resource, but do those
21 proposed lll(d) requirements, to your knowledge, would
22 they in fact add large costs to potential generating
23 resources that are currently in PacifiCorp or Rocky
24 Mountain Power's resource stack?
25 A. It depends on the resource. I haven't
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538 CLEMENTS (X)
Rocky Mountain Power
1 performed that calculation, but we have all sorts of
2 different types of resources in our resource stack.
3 Q. Do you think in your opinion, would the
4 requirements, proposed requirements, of lll(d) add cost
5 to your resources if they have to be implemented?
6 A. We haven't performed that calculation, other
7 than to note that we do have a considerable amount of
8 renewable resources already in our resource stack.
9 MR. HAMMOND: I'd like the Commission to
10 instruct the witness to actually answer the question, and
11 the question is does he have an opinion regarding wether
12 lll(d) may add cost to its current generation stack.
13 It's either a yes or no question or answer. I think it's
14 simple to answer?
15 MS. HOGLE: Your Honor, I believe that he
16 answered that question by saying that it depends. We
17 have a lot of renewable resources, meaning they may be
18 sufficient to comply with lll(d).
19 COMMISSIONER KJELLANDER: Thank you. Mr.
20 Hammond, I know you would like a yes or no answer and I
21 think what you got was it depends and I'm afraid you may
22 have to live with that answer today.
23
24 Q.
MR. HAMMOND: Thank you, Commissioner.
BY MR. HAMMOND: Do you have any -- can you
25 give me the background of why the Company has decided to
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1 propose a change from 20 to, I think it's, three years --
2 A. Three.
3 Q. -- is that correct? Is there any reason for
4 the difference between three years and two years between
5 Idaho Power and Rocky Mountain?
6 A. Yes, three years is consistent with our current
7 risk management policy for hedging. Our traders do not
8 lock in prices beyond three years. It's also consistent
9 with our integrated resource plan, action plan, so when
10 we have our integrated resource plan, it tells us what
11 resources we're going to acquire for the next 20 to 30
12 years. There's an action plan associated with that that
13 states here are the steps that you need to take over the
14 next two to four years in order to implement this
15 integrated resource plan, and so the three-year limit is
16 within that three-year hedging policy and practice that
17 we have. It's also within the IRP action plan time
18 line.
22 time period for contracts; i.e., they would have to
20 time period from 20 to three years, does the Company
21 foresee any administrative difficulties with such a short
If the Commission were to reduce the contract Q. 19
23 renegotiate those contracts much more quickly?
24 A. Yes, we would have more administrative burden
25 on contract administration. Typically contract renewals
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1 are less time-consuming than new contracts.
2 Q. Except that with these contract renewals as
3 proposed, there would be different pricing, so there
4 would be more things to negotiate than simply a contract
5 renewal; is that correct?
6 A. Well, typically when there's a new price on a
7 contract renewal, we drop the new price in the existing
8 contract and if no contract terms have changed, we move
9 along. In fact, we have multiple PURPA contracts that
10 are year to year and they're not administratively
11 burdensome for us. In fact, all of our combined heat and
12 power PURPA contracts are on short-term contracts,
13 typically one year or less. These are the oil and gas
14 manufacturers, producers who have typical combined heat
15 and power applications.
16 They have requested short-term contracts from
17 us even when long-term contracts are available to them,
18 because they don't want to take on the fixed price risk
19 of selling to us and it's not administratively burdensome
20 for those. We drop in a new price and execute a new
21 contract.
22 Q. But those projects are different fundamentally
23 than the solar and the wind projects; is that correct?
24 A. Yes, they are fundamentally different because
25 they typically do not need the contract term to procure
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1 financing, and so absent the need for the long-term
2 contract, they elect not to have a long-term contract,
3 because they don't want the fixed price risk of selling
4 to us over a long time period.
5 Q. In your testimony, you discuss Mr. Dickman's
6 proposal regarding indicative pricing; is that correct?
7
8
A.
Q.
In my testimony, yes.
Yes. Do you think the indicative pricing
9 proposal that Mr. Dickman has proposed would regulate the
10 amount of power you might see come online eliminating the
11 need for reducing the contract from 20 to three years?
12 A. No, I don't believe it will change our
13 activity. I think it will provide greater clarity and
14 certainty to proposed projects as to what their price
15 will actually be when they go to execute a contract.
16 Q. And each project that would come online we've
17 heard testimony here today would come online at a little
18 less incremental -- a slightly less -- a lower cost, I
19 should say. With the proposal that's being made by
20 PacifiCorp/Rocky Mountain Power, that price would
21 decrease even further by including those additional
22 projects into the queue; is that fair to say?
23 A. I think it's duplicative what you just said in
24 your question. If you price one project, assuming that
25 projects that entered the queue before it are included in
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1 the resource stack, then yes, it would have a lower price
2 than projects that are before it.
3 Q. Thank you. Would that in effect, the reduction
4 in price, eliminate some projects because they simply
5 would, in your opinion would, not be feasible or able to
6 provide payments on their financing or anything else?
7 A. It may. I've lost too many lunch bets, one
8 last week including, about where a PURPA project can be
9 executed and get financing, so I can't presuppose to know
10 what the limit is.
11
12
MR. HAMMOND: No further questions.
COMMISSIONER KJELLANDER: Thank you, Mr.
13 Hammond. Any questions from Mr. Arkoosh?
14
15
16
17
18
MR. ARKOOSH: Yes, Mr. Chairman, a couple.
COMMISSIONER KJELLANDER: Please proceed.
CROSS-EXAMINATION
19 BY MR. ARKOOSH:
20 Q. Mr. Clements, at page 10, starting at line 12
21 of your rebuttal testimony, please, you testify that
22 entering into contracts with these proposed projects for
23 a term of 20 years would expose customers to unreasonable
24 price risks. Do you see that, sir?
25 A. That's on page 10?
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1
2
3
Q.
A.
Q.
Yes, sir.
Okay.
The intent, of course, is to leave the customer
4 indifferent if the process works correctly; isn't that
5 correct?
6
7
A.
Q.
That's correct.
And when I say "process," at least as to
8 scheduled pricing, it's a public process where it's set
9 by the Commission with public input; isn't that
10 correct?
11
12
A.
Q.
That's correct.
And the Staff has involved itself and the
13 utilities have involved themselves to develop these
14 published prices as well as they can given the
15 information they have at the time over that 20-year
16 horizon; isn't that correct?
17
18
A.
Q.
That's correct.
It's much like the process that one goes
19 through to rate base assets when a utility comes in and
20 wants to develop new capacity?
21 MS. HOGLE: Objection, Your Honor, is there a
22 question? It seems like testimony to me.
23 COMMISSIONER KJELLANDER: Mr. Arkoosh, is there
24 a way in which you might be able to rephrase that?
25 MR. ARKOOSH: I will put an "is" in front of
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1 the question.
2 COMMISSIONER KJELLANDER: Could we hear that
3 rephrased?
4 Q. BY MR. ARKOOSH: Is it much like the same
5 public hearing process that a utility goes through to
6 rate base its capacity?
7 A. I would say no, because when the utility goes
8 through a process to acquire long-term resources, it's an
9 identified need in the integrated resource plan, and then
10 the utility goes out and gets exactly what it needs
11 through a competitive bid process. The PURPA process,
12 while it does comes before the Commission for approval
13 and it's a public process, the approval of the power
14 purchase agreements, the issue of whether there's a need
15 or not is not the same as it is through a Company
16 resource.
17 Q. I understand it's a different issue that's
18 being examined, but is the process the same? You go
19 through a public scrutiny process?
20 A. Yes, the process of receiving Commission
21 approval is generally the same absent the CPCN.
22 Q. And the focus of getting these published rates,
23 I'm not talking about the IRP process, I'm just talking
24 about the published rates, the focus of the published
25 rates is to find a price that leaves the consumer?
CSB REPORTING
[phone]
545 CLEMENTS (X)
Rocky Mountain Power
1 MS. HOGLE: I believe counsel is testifying. I
2 did not hear a question.
3
4
MR. ARKOOSH: I'm sorry --
COMMISSIONER KJELLANDER: I think I did hear a
5 question in there and so I'm going to allow the
6 question.
7
8 question?
THE WITNESS: Sorry, could you repeat the
9 Q. MR. ARKOOSH: Is, is the purpose of setting
10 these proposed schedules like Exhibit 208 for Idaho Power
11 in this case, Exhibit 208, the purpose of these hearings
12 to set these schedules is to find a price that leaves the
13 consumer indifferent?
14 A. Yes, based on the set of assumptions in place
15 at the time, yes.
16 Q. Thank you; so you've seen a lot of testimony in
17 this case from industry people, PURPA industry people,
18 that indicates that a three- or two- or five-year
19 contract may disincentivize or at least not provide
20 adequate incentive to allow PURPA projects to develop;
21 you're aware of that testimony?
22
23
A.
Q.
I am.
And do you recognize that one of the federal
24 purposes of PURPA itself is to incentivize renewable
25 resources?
CSB REPORTING
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546 CLEMENTS (X)
Rocky Mountain Power
1 A. I don't know if I'd use the word "incentivize,"
2 but yes.
3 Q. Okay. Well, to provide an incentive to.
4 Incentivize might not even be a word, but to provide an
5 incentive to the development of renewable resources?
6
7
A.
Q.
Yet, through the purchase obligation.
Okay; so when you say that it exposes customers
8 to unreasonable price risks, that's merely an opinion, is
9 it not?
10
11
A.
Q.
Yes, it's my opinion.
Okay; so if you look at all of the
12 circumstances, the federal requirement that the PURPA
13 program gives incentive to renewable resources and that
14 the customer be left indifferent, if possible, under the
15 circumstances and that in some circumstances it may be
16 true that it won't incentivize the development of
17 renewable resources with these very short contracts, at
18 least in the published rate circumstance, isn't it
19 possible that it's not an unreasonable risk, but the risk
20 that is contemplated by Congress and is indeed?
21 MS. HOGLE: Objection, Your Honor. That seemed
22 like a very long, compound question and I would ask that
23 counsel rephrase it, maybe break it up into three
24 questions.
25 MR. ARKOOSH: If it please the Chairman, it's a
CSB REPORTING
[phone]
547 CLEMENTS (X)
Rocky Mountain Power
1 hypothetical. It's not a compound question. The
2 question was given these circumstances, and there's more
3 than one circumstance in play here, is it possible that
4 this is a reasonable risk, at least in the scheduled rate
5 circumstances.
6 COMMISSIONER KJELLANDER: Does the witness
7 understand the question?
8
9
10 proceed.
11
THE WITNESS: Yes.
COMMISSIONER KJELLANDER: Okay, please
THE WITNESS: I don't believe it's unreasonable
12 and I'm glad you mentioned in your question the second
13 part of PURPA. I really see two parts of PURPA. You
14 have the incentive or the purchase obligation which
15 provides the incentive to PURPA projects and then you
16 have the ratepayer indifference standard and those are
17 often competing interests within PURPA, and I believe
18 that what we have proposed balances those two things;
19 that the risk of a 20-year PPA sways too far in the favor
20 of incenting QFs while unduly burdening customers with
21 fixed price risk. You won't maintain the ratepayer
22 indifference standard with a 20-year contract based on
23 the long-term, fixed price risk that I've explained in my
24 testimony, and it's a balancing act and the contract term
25 is one way to balance out the ratepayer indifference
CSB REPORTING
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548 CLEMENTS (X)
Rocky Mountain Power
1 requirement with the incentive requirement of PURPA.
2 Q. BY MR. ARKOOSH: If the industry people are
3 correct, the PURPA industry people are correct, that
4 there will be no development of QFs with these short-term
5 contracts, at least in the scheduled rate circumstance,
6 then we've done more than balance incentive versus
7 indifference to price; isn't that right? You've killed
8 the industry?
9 A. Well, again, I don't know what you mean when
10 you say "industry people."
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12
Q.
A.
The testimony in this case, Mr. Clements.
Sure. For renewables who require a long-term
13 contract for financing, potentially there's some
14 renewable contracts that do not, it may have an adverse
15 effect, but there are other avenues for them to sell
16 their power. On the flip side, not solar and wind and
17 other renewables, the combined heat and power, those QFs
18 who are also part of PURPA, may not require the long-term
19 contract. In fact, we recently executed an Idaho PURPA
20 contract that's two years in length, I believe, possibly
21 three. My memory is failing me at the moment, but it's
22 two to three years in length.
23 Q. And, again, the people in this record that
24 discussed it that are here indicate, you do acknowledge
25 they've indicated, it's a major disincentive?
CSB REPORTING
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549 CLEMENTS (X)
Rocky Mountain Power
1
2
A. Yes. That's what their opinion is, yes.
MR. ARKOOSH: Thank you very much, Mr.
3 Clements. Thank you, Mr. Chairman.
4 COMMISSIONER KJELLANDER: Thank you, and let's
5 see, where we're at. Ms. Howland, no questions?
6
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MS. HOWLAND: No questions.
COMMISSIONER KJELLANDER: Thank you. Any
8 questions from the Commission?
9 Any redirect?
10
11 you.
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MS. HOGLE: One question, Your Honor. Thank
COMMISSIONER KJELLANDER: Please.
DIRECT EXAMINATION
16 BY MS. HOGLE:
17 Q. Mr. Clements, earlier you were asked questions
18 about lll(d) and its relationship with the 2015 IRP.
19 Isn't it true that the 2015 IRP preferred portfolio
20 considers the draft rules for lll(d)?
21
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25 you.
A. Yes, I believe it does.
MS. HOGLE: Thank you.
COMMISSIONER KJELLANDER: Is that it?
MS. HOGLE: That concludes my redirect. Thank
CSB REPORTING
[phone]
550 CLEMENTS (Di)
Rocky Mountain Power
1 COMMISSIONER KJELLANDER: Thank you very much,
2 and thank you, Mr. Clements.
3 (The witness left the stand.)
4 COMMISSIONER KJELLANDER: It's my intent now to
5 take a 10-minute break and when we return, Ms. Hogle, you
6 can all your second and final witness, and then just for
7 purposes of prepping Mr. Otto, then we'll turn to you.
8
9
MR. OTTO: Thank you.
COMMISSIONER KJELLANDER: And with that, then,
10 let's try to be back here, if we can, within 10 minutes,
11 so we will go off the record.
12 (Recess.)
13 COMMISSIONER KJELLANDER: And we are now back
14 on the record and we are ready for Ms. Hogle from
15 PacifiCorp/Rocky Mountain Power to call her second and
16 final witness.
17 MS. HOGLE: Thank you, Your Honor. The Company
18 calls Mr. Brian Dickman.
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CSB REPORTING
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551 COLLOQUY
1 BRIAN DICKMAN,
2 produced as a witness at the instance of Rocky Mountain
3 Power, having been first duly sworn to tell the truth,
4 the whole truth, and nothing but the truth, was examined
5 and testified as follows:
6
7
8
9 BY MS. HOGLE:
DIRECT EXAMINATION
10
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12
Q.
A.
Q.
Good afternoon, Mr. Dickman.
Good afternoon.
For the record, can you please state and spell
13 your name?
14 A. Brian Dickman. Last name is spelled
15 D-i-c-k-m-a-n.
16 Q. And by whom are you employed and in what
17 capacity are you employed?
18 A. I'm employed by PacifiCorp or Rocky Mountain
19 Power as the director of net power costs.
20 Q. And are you the same Brian Dickman who prefiled
21 direct testimony in this case on March 2nd, 2015?
22
23
A.
Q.
Yes.
And do you have any additions or corrections
24 you wish to make to your prefiled direct testimony at
25 this time?
CSB REPORTING
[phone]
552 DICKMAN (Di)
Rocky Mountain Power
1
2
A.
Q.
No corrections.
So if I were to ask you the questions in your
3 testimony again here today, would your answers be the
4 same?
5
6
A. Yes.
MS. HOGLE: Mr. Chairman, I would move that the
7 prefiled direct testimony of Mr. Brian Dickman be spread
8 upon the record as if read.
9 COMMISSIONER KJELLANDER: So without objection,
10 we will spread the testimony across the record as if
11 read.
12 (The following prefiled testimony of Mr. Brian
13 Dickman is spread upon the record.)
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CSB REPORTING
[phone]
553 DICKMAN (Di)
Rocky Mountain Power
1 Q. Please state your name, business address, and
2 present position with Rocky Mountain Power ("the
3 Company"), a division of PacifiCorp.
4 A. My name is Brian S. Dickman. My business
5 address is 825 NE Multnomah Street, Suite 600, Portland,
6 Oregon 97232. My title is Director, Net Power Costs.
7 Q. Briefly describe your education and business
8 experience.
9 A. I received a Master of Business Administration
10 from the University of Utah with an emphasis in finance
11 and a Bachelor of Science degree in accounting from Utah
12 State University. Prior to joining the Company, I was
13 employed as an analyst for Duke Energy Trading and
14 Marketing. I have been employed by the Company since 2003
15 including positions in revenue requirement and regulatory
16 affairs, and I assumed my current role managing the
17 Company's net power cost group in March 2012.
18 Q. Have you testified in previous regulatory
19 proceedings?
20 A. Yes. I have filed testimony in proceedings
21 before the public utility commissions in California,
22 Idaho, Oregon, Utah, and Wyoming.
23 Purpose of Testimony
24
25
Q.
A.
What is the purpose of your testimony?
My testimony supports the Company's application
554 Dickman, Di - 1
Rocky Mountain Power
1 to modify the non-standard avoided costs in Idaho. I
2 describe a significant shortcoming of the
3 currently-approved method for calculating non-standard
4 avoided cost prices in Idaho (the "IRP Method"). In
5 particular, the IRP Method does not recognize the impact
6 of proposed qualifying facility ("QF") contracts that are
7 not yet signed but have requested indicative avoided cost
8 prices and are actively pursuing a power
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555 Dickman, Di - la
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1 purchase agreement with the Company.
2 IRP Method Background
3 Q. Please describe the IRP Method approved for
4 calculating avoided costs in Idaho.
5 A. The IRP Method was adopted by the Commission
6 December 18, 2012, in Case No. GNR-E-11-03, and is
7 applicable to wind and solar QF projects larger than 100
8 kW.1 The IRP Method focuses on identifying the
9 incremental costs that can be avoided when a QF is added
10 to a utility's system and is intended to be consistent
11 with the Company's biennial Integrated Resource Plan
12 ( "IRP") . Avoided cost prices are composed of displaceable
13 energy costs plus the capacity costs of a simple cycle
14 combustion turbine ("SCCT") beginning when the utility
15 adds a new thermal resource in its IRP. To calculate the
16 avoided energy costs, the Company's production cost
17 dispatch model ("GRID") is used to identify the highest
18 displaceable incremental cost (i.e. generation from
19 Company-owned resources or displaceable power purchases)
20 for each hour of the QF's proposed contact term.
21 Q. Is the concept embodied in the IRP Method a
22 reasonable approach to calculating avoided costs?
23 A. Yes. In concept, the IRP Method is a
24 reasonable approach to calculating avoided costs for
25 several reasons. In particular, the IRP Method relies on
556 Dickman, Di - 2
Rocky Mountain Power
1 the Company's GRID model in order to capture the impact
2 to PacifiCorp's entire system when a QF is added. The
3 GRID model is configured to recognize the attributes of
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24 1 The IRP Method is also applicable to other types of QF projects
that are lOaMW or larger.
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557 Dickman, Di - 2a
Rocky Mountain Power
1 individual QF projects - such as size, generation
2 profile, and location - as well as the Company's ability
3 to integrate the QF's output onto its system subject to
4 transmission constraints. Furthermore, the IRP Method
5 recognizes that avoided capacity costs should only be
6 included when the Company will actually avoid building
7 new resources. These concepts help maintain the customer
8 indifference between QF generation and generation or
9 purchases that the Company would otherwise require.
10 Q. Have you identified any shortcomings in the
11 Commission's methodology for implementation of the IRP
12 Method in Idaho?
13 A. Yes. The IRP Method does not recognize the
14 impact of proposed QF projects that do not yet have a
15 signed contract but are at some stage in the process of
16 receiving indicative avoided cost prices and pursuing a
17 power purchase agreement with the Company.
18 Proposed QF Projects
19 Q. Please explain what is meant by a proposed QF
20 contract.
21 A. A proposed QF contract is one that has begun
22 the process required to enter into a power purchase
23 agreement with the Company, but for which a signed
24 contract has not yet been executed. At the time a new QF
25 in Idaho submits a request to receive indicative avoided
558 Dickman, Di - 3
Rocky Mountain Power
1 cost prices, there may be dozens of other projects (in
2 Idaho or in any of the other states served by PacifiCorp)
3 that have also already requested prices and started down
4 the path of executing a power purchase agreement. Under
5 the current IRP Methodology, however, only signed
6 long-term power purchase contracts can be included in the
7 GRID model, so each new QF is priced as if it was
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559 Dickman, Di - 3a
Rocky Mountain Power
1 the only proposed QF project to request prices. All
2 other proposed QF projects are ignored even though they
3 too are seeking PURPA contracts.
4 Q. What is the impact on avoided costs due to
5 ignoring the proposed QF projects in the pricing queue
6 when calculating prices?
7 A. Avoided costs for the first QF in the queue are
8 based on displacement of the highest cost resources on
9 the Company's system. Each successive QF should displace
10 lower and lower cost resources, resulting in lower
11 avoided costs. More importantly, recognizing additional
12 QFs on the Company's system defers the need to build new
13 resources. Accumulating several QF projects may
14 completely displace planned thermal resources additions
15 and delay the payment of capacity costs to the next QF in
16 line. If the queued QFs are ignored, the IRP Method will
17 result in payments to QFs that exceed avoided costs.
18 Q. But doesn't PURPA envision imperfections in
19 avoided cost rates?
20 A. Yes. In its order implementing PURPA
21 regulations, the Federal Energy Regulatory Commission
22 ( "FERC") stated that it "believes that, in the long run,
23 'overestimations' and 'underestimations' of avoided costs
24 will balance out."2 However, ignoring other proposed QF
25 projects is an avoided cost methodology error that
560 Dickman, Di - 4
Rocky Mountain Power
1 results in a one way imperfection - overestimations that
2 will not, in fact, balance out in the long run. This is
3 in direct conflict with FERC's PURPA regulation, which
4 makes it clear that an electric utility is under no
5 circumstances required to pay more than avoided cost for
6 QF purchases.3 By contrast, the same regulations allow
7 state commissions to set a rate for purchases that is
8 lower than
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23 2 See Small Power Production and Cogeneration Facilities - Rates and
Exemptions, Order No. 69, Final Rule Regarding the Implementation of
24 Section 210 of PURPA, 45 Fed. Reg. 12214, at 12224 (1980).
3 18 C.F.R. § 292.304 (a) (2).
25
561 Dickman, Di - 4a
Rocky Mountain Power
1 avoided cost, so long as it is just, reasonable,
2 nondiscriminatory and is sufficient to encourage small
3 power production.4
4 Q. Has the Commission recognized the importance of
5 reflecting new long-term contracts in the determination
6 of avoided costs?
7 A. Yes. In Order No. 32697 the Commission
8 determined it was appropriate to update the IRP Method
9 modeling to account for new "long-term contract
10 commitments because of the potential effect that such
11 commitments have on a utility's load and resource
12 balance."5 However, the Commission limited the
13 recognition of new long-term commitments to only signed
14 contracts.
15 Q. Was the issue of reflecting proposed QFs in the
16 determination of avoided costs raised in that proceeding?
17 A. Yes. Idaho Power Company ("Idaho Power")
18 proposed that any QF with signed contracts and any
19 proposed QF that has requested pricing be included in
20 Idaho Power's resource portfolio for purposes of
21 calculating future avoided costs because they can impact
22 future avoided costs.6 For purposes of calculating
23 avoided costs, Idaho Power proposed that a QF would be
24 designated as "in the queue" upon receipt of a written
25 request from a QF for contract pricing.7
562 Dickman, Di - 5
Rocky Mountain Power
1 Q. What was Idaho Power's rationale for proposing
2 to reflect proposed QFs in the determination of avoided
3 costs?
4 A. Idaho Power explained that if proposed QFs and
5 QFs with signed contracts are
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21 4 18 C.F.R. § 292.304 (b} (3).
5 In re Review of PURPA QF Contract Provisions, Case No. GNR-E-11-03,
22 Order No. 32697 at 22 (Dec. 2012).
6 Case No. GNR-E-11-03, Idaho Power Company, Direct Testimony of Karl
23 Bokenkarnp at 28 (Jan. 31, 2012}.
7 Id.
24
25
563 Dickman, Di - Sa
Rocky Mountain Power
1 considered part of the resource portfolio, then avoided
2 cost rates for energy and capacity could change for each
3 new QF as a result of the total amount of capacity and
4 energy provided by all projects in Idaho Power's
5 portfolio - changes that are not captured if the
6 recognition of new long-term commitments is limited to
7 signed contracts.
8 Q. Would reflecting proposed QFs in the
9 determination of avoided cost rates be consistent with
10 FERC PURPA regulations?
11 A. Yes. Federal regulations governing the rates
12 for QF purchases state that, to the extent practicable,
13 the following shall be taken into account: "[t]he
14 availability of capacity or energy from a qualifying
15 facility during the system daily and seasonal peak
16 periods, including ... [t]he individual and aggregate
17 value of energy and capacity from qualifying facilities
18 on the electric utility's system."8 This language makes
19 it clear that considering QFs in the aggregate is an
20 important consideration because it may impact the
21 accuracy of avoided cost rates.9
22 Q. Would reflecting proposed QFs in the
23 determination of avoided cost rates be consistent with
24 other FERC policies?
25 A. Yes. FERC's long-standing interconnection
564 Dickman, Di - 6
Rocky Mountain Power
1 policies - policies that form the foundation for state
2 jurisdictional QF interconnections - require
3 interconnection studies to evaluate the impact of a
4 proposed interconnection by considering all
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19 8 18 C.F.R. § 292.304(e) (2) (vi) (emphasis added)
9 In its 1980 order implementing these regulations, FERC explained
20 that this provision would allow for QFs to be considered in the
aggregate for purposes of allowing a group of QFs to potentially
21 enable a purchasing utility to defer or avoid scheduled capacity
additions despite that each QF, if considered individually, would not
22 provide capacity value. See Small Power Production and Cogeneration
Facilities - Rates and Exemptions, Order No. 69, Final Rule Regarding
23 the Implementation of Section 210 of PURPA, 45 Fed. Reg. 12214, at
12224, 12227, 12236 (1980). However, it follows that considering QFs
24 in the aggregate may have other impacts on avoided cost rates as
well, and the language of the regulation does not preclude such an
25 interpretation.
565 Dickman, Di - 6a
Rocky Mountain Power
1 generating facilities that, as of the date the study is
2 commenced, have a pending, higher-queued interconnection
3 request to interconnect to the transmission system.10
4
5
Q.
A.
What is FERC's rationale for this policy?
This policy is designed to, among other things,
7 mechanism. FERC has stated that it would be unfair to
6 allow for a fair network upgrade cost allocation
8 require an interconnection customer to sign an
9 interconnection agreement before the interconnection
10 studies identify its requirements for interconnection
11 facilities and network upgrades.11 To that end, FERC
12 stated, "[w]e recognize that including all the higher
13 queued projects will require a restudy when a higher
14 queued project drops out, but it is essential to include
15 each higher queued project in the study because the
16 Interconnection Studies will be meaningless if higher
17 queued projects are not included."12
18 Q. Does the same rationale apply with regard to
19 reflecting queued QFs in the determination of avoided
20 costs?
21 A. Yes. Just as each successive QF displaces lower
22 and lower cost resources and, thus, results in lower
23 avoided costs and defers the need to build new resources,
24 the network upgrades necessary to accommodate each
25 interconnection customer's interconnection (as determined
566 Dickman, Di - 7
Rocky Mountain Power
1 in the interconnection study) impacts whether and what
2 type of network upgrades may be required to accommodate
3 the interconnection customer next in the queue and, thus,
4 that next interconnection customer's network upgrade cost
5 allocation. If, on the other hand, the higher
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22 10 FERC Pro Forma Large Generator Interconnection Procedures, Section
7.3; FERC Proforma Small Generator System Impact Study Agreement,
23 Section 8.
11 See, e.g. Standardization of Generator Interconnection Agreements
24 and Procedures, Order No. 2003-A, 106 FERC 1 61,220 at P 161 (2004).
12 Id.
25
567 Dickman, Di - 7a
Rocky Mountain Power
1 queued interconnection customers were ignored, the
2 interconnection studies would result in network upgrade
3 cost allocations that exceed what is actually required to
4 interconnect the customer, just as the payments to QFs
5 exceed avoided costs if queued QFs are ignored in the
6 determination of avoided cost rates.
7 Q. Did the Commission approve Idaho Power's
8 proposed queued QF policy?
9 A. No. Order No. 32697 adopted Commission Staff's
10 position on this issue - i.e., that only signed QF
11 contracts should be reflected in avoided cost rates -
12 without comment.13 However, Commission Staff reasoned
13 that "[t]he mere indication of interest or request for a
14 contract is too speculative to justify incorporating a
15 change in the utility's load-resource balance."14 With
16 regard to Idaho Power's queued QF policy proposal,
17 Commission Staff concluded that "[t]echnically, Idaho
18 Power's avoided costs do not change until a new QF has
19 actually been added to the resource portfolio. A QF that
20 has not signed a contract cannot yet be considered part
21 of the resource portfolio."15
22 Q. Why are you asking the Commission to revisit
23 this Commission Staff conclusion?
24 A. Since the time of this proceeding, there have
25 been two significant shifts in the PURPA landscape -
568 Dickman, Di - 8
Rocky Mountain Power
1 shifts the Commission Staff could not have anticipated.
2 First, FERC issued a series of orders clarifying that QFs
3 can, under certain circumstances, unilaterally enter into
4 a purchase obligation and lock in avoided cost rates.
5 Second, there has been a drastic increase in the number
6 of QF requests
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21 13 Case No. GNR-E-11-03, Order No. 32697 at 22.
14 Case No. GNR-E-11-03, Idaho Public Utilities Commission, Direct
22 Testimony of Rick Sterling at 24 (May 4, 2102).
15 Id.
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569 Dickman, Di - 8a
Rocky Mountain Power
1 received by the Company.
2
3
Q.
A.
Can you explain the first shift in more detail?
Yes. Historically, FERC has stated that it
4 will defer to the states regarding the date on which a
5 legally enforceable obligation ("LEO") is incurred.
6 However, FERC issued four orders in recent years that
7 curtailed state discretion on this issue.16 All four
B orders ruled that a state may not require a QF to obtain
9 a fully executed contract as a precondition to obtaining
10 a LEO, with the final order indicating that a LEO may
11 arise even before any party signs an agreement.
12 Q. Why would these FERC orders impact the
13 Commission Staff conclusion regarding whether queued QFs
14 should be reflected in avoided costs?
15 A. Commission Staff's conclusion was that the
16 indication of interest or request for a contract was too
17 speculative to justify incorporating a change in the
18 utility's load-resource balance, and that avoided costs
19 do not change until a new QF has actually been added to
20 the resource portfolio, which cannot occur until a QF has
21 signed a contract. However, the recent FERC orders on the
22 establishment of LEOs make it clear that a QF can
23 unilaterally establish a right to sell to a utility
24 before the contract is signed. Therefore, to ensure
25 ratepayers are protected against an avoided cost rate
570 Dickman, Di - 9
Rocky Mountain Power
1 methodology that results in overestimations that will not
2 balance out in the long run, proposed QFs should be
3 reflected in avoided costs.
4 Q. Can you explain the second shift in the PURPA
5 landscape related to the drastic increase in the number
6 of QF requests received by the Company?
7 A. Yes. Company witness Paul Clements describes
8 the significant increase in recent
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23 16 Grouse Creek Wind Park, LLC, 142 FERC 1 61,187 (2013); Murphy Flat
Pwr., LLC, 141 FERC i 61,145 (2012); Rainbow Ranch Wind, LLC, 139
24 FERC i 61,077 (2012); Cedar Creek Wind, LLC, 137 FERC i 61,1006
(2011).
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1 PURPA contract activity over the Company's six-state
2 system. Of particular relevance here, more than half of
3 the total PURPA MWs have online dates of 2014 or later.
4 Q. How many proposed QFs are currently in the
5 Company's queue?
6 A. Company witness Paul Clements also provides the
7 details of the current QF activity. In total, the Company
8 currently has 3,641 MW of proposed QF projects.
9 Q. Have you calculated the impact on avoided costs
10 if proposed QFs are included in the IRP Method?
11 A. Yes. The Company calculated the impact on the
12 IRP Method avoided costs of including roughly 3,000 MW of
13 proposed QFs (located in Idaho, Utah, Wyoming, Oregon)
14 prior to the next Idaho QF. Accounting for these proposed
15 QFs rather than just those QFs with signed contracts
16 reduces avoided costs for the next Idaho QF in the
17 pricing queue by approximately $18 per MWh on a 20-year
18 levelized basis - a 37 percent reduction compared to the
19 indicative price that same QF would receive if the queue
20 of proposed QFs was not considered.
21 Q. Could you not just recalculate prices for new
22 QF projects as other proposed QFs sign contracts?
23 A. No. Besides being prohibitively time consuming
24 and problematic from a contract negotiation standpoint,
25 there may be situations where multiple QFs progress
572 Dickman, Di - 10
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1 toward a LEO at the same pace, and it would be impossible
2 for the Company to update pricing as needed to reflect
3 the unilateral contract commitments that occur.
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1 Q. Do any other states served by the Company
2 recognize proposed QFs in the calculation of avoided
3 costs?
4 A. Yes. The Company includes proposed QFs in the
5 calculation of non-standard avoided cost prices in Utah.
6 Recommendation
7 Q. What action do you recommend the Commission
8 take to remedy the IRP method shortcomings identified in
9 your testimony?
10 A. The Commission should modify the IRP Method to
11 account for proposed QF projects on the Company's system
12 prior to the next Idaho QF requesting indicative prices.
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Q.
A.
Does this conclude your direct testimony?
Yes.
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1 (The following proceedings were had in
2 open hearing.)
3 MS. HOGLE: Mr. Dickman is available for
4 cross-examination. Thank you.
5 COMMISSIONER KJELLANDER: Thank you very much.
6 Let's start with Idaho Power. Mr. Walker.
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8
9
10
MR. WALKER: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Avista.
MR. ANDREA: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Let's
11 move to Mr. Howell.
12 MS. HUANG: Actually, it's Ms. Huang again. No
13 questions. Thank you, Mr. Chairman.
14
15 Adams.
16
17
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. ADAMS: No questions. Thank you.
COMMISSIONER KJELLANDER: Thank you, Mr. Adams.
18 Mr. Richardson.
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MR. RICHARDSON: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Otto.
MR. OTTO: I do have just a few questions.
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2
3 BY MR. OTTO:
CROSS-EXAMINATION
4 Q. Mr. Dickman, on page 4 of your testimony, the
5 question -- we're talking about lines 13 through 16 and
6 you're asked a question does PURPA envision imperfections
7 in avoided costs and you reply that, you know, FERC has
8 stated what it states there. What's the basis for your
9 testimony there?
10 A. I'm sorry, I'm not sure I understand the
11 question.
12 Q. How do you reach this conclusion that you
13 state?
14 A. It's my understanding of the rules and
15 regulations that set out how the avoided costs are
16 calculated that over time, they may or may not equal the
17 cost at the time of delivery from the QF.
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MR. OTTO: One second. That's actually all.
THE WITNESS: Okay.
COMMISSIONER KJELLANDER: Thank you.
21 Mr. Miller.
22
23
24 Ms. Nunez.
25
MR. MILLER: No, thank you.
COMMISSIONER KJELLANDER: Thank you.
MS. NUNEZ: No questions. Thank you.
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4 Sanger.
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COMMISSIONER KJELLANDER: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. SANGER: No questions.
COMMISSIONER KJELLANDER: Mr. Hammond.
MR. HAMMOND: I think I only have a couple.
COMMISSIONER KJELLANDER: Please proceed.
CROSS-EXAMINATION
12 BY MR. HAMMOND:
13 Q. Are you familiar at all with Rocky Mountain
14 Power's irrigation load control program in Idaho?
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A.
Q.
Generally, yes.
Do you have any idea what that may cost
17 ratepayers each year, any knowledge whatsoever?
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A.
Q.
A.
Q.
Very generally. Not specifically, no.
Okay. In general, what is your knowledge?
Several million dollars annually.
Do you any opinion on whether or not local
22 distributed solar resources would be more or less costly
23 for ratepayers than the -- to serve high demand, peak
24 power timed events in that area?
25 A. No, I wouldn't have an idea on a price
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1 comparison, but it seems to me the two products would be
2 distinct. They'd be very different. The Idaho
3 irrigation program allows us the opportunity to dispatch
4 as needed and purchasing from a solar QF does not provide
5 us that opportunity.
6
7 Thank you.
MR. HAMMOND: I have no further questions.
8 COMMISSIONER KJELLANDER: Thank you.
9 Mr. Arkoosh.
10 MR. ARKOOSH: No questions. Thank you,
11 Mr. Chairman.
12
13 Howland.
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COMMISSIONER KJELLANDER: Thank you, and Ms.
MS. HOWLAND: No questions.
COMMISSIONER KJELLANDER: Are there any
16 questions from the Commission? None. Redirect?
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MS. HOGLE: None. Thank you, Your Honor.
COMMISSIONER KJELLANDER: Thank you, and we'll
19 excuse you and thank you for your testimony.
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THE WITNESS: Thank you.
(The witness left the stand.)
COMMISSIONER KJELLANDER: All right, as
23 promised before the break, we will move now to the Idaho
24 Conservation League and Sierra Club. Mr. Otto, if you
25 would like to call your first witness.
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1
2 Wenner.
3
MR. OTTO: Yes, Mr. Commissioner, I call Adam
4 ADAM WENNER,
5 produced as a witness at the instance of the Idaho
6 Conservation League and the Sierra Club, having been
7 first duly sworn to tell the truth, the whole truth, and
8 nothing but the truth, was examined and testified as
9 follows:
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13 BY MR. OTTO:
DIRECT EXAMINATION
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Q.
A.
Q.
Hello, Mr. Wenner.
Hello.
Can you please state your name and spell your
17 last name for the record?
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A.
Q.
Adam Wenner, W-e-n-n-e-r.
And are you the same Adam Wenner who filed
20 direct and rebuttal testimony on behalf of the
21 Conservation League and Sierra Club?
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23
A.
Q.
Yes.
Do you have any corrections or alterations to
24 that testimony?
25 A. Yes, one. Page 10, line 7, the sentence should
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1 stop after "Order No. 69," strike the rest of the
2 sentence.
3
4
Q. With those corrections --
COMMISSIONER KJELLANDER: I'm sorry, before you
5 move forward, could you repeat the corrections? Was that
6 in your direct or your rebuttal?
7 THE WITNESS: Direct testimony, page 10, line
8 7, strike everything after the No. "69."
9 COMMISSIONER KJELLANDER: Okay, thank you.
10 Q. BY MR. OTTO: And with that correction, if I
11 asked you these same questions in both the direct and
12 rebuttal today, would your answers remain the same?
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14
A. Yes.
MR. OTTO: And with that, I'd ask that Mr.
15 Wenner's direct and rebuttal testimony be spread upon the
16 record.
17 COMMISSIONER KJELLANDER: And without
18 objection, we will spread the testimony across the record
19 as if read.
20 (The following prefiled direct and
21 rebuttal testimony of Mr. Adam Wenner is spread upon the
22 record.)
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1
2
Q.
A.
What is your name and background?
My name is Adam Wenner. I am a partner at
3 ORRICK's, Herrington and Sutcliffe, LLP, and Work in the
4 Washington DC office. Prior to working at Orrick, I
5 served as an attorney in the Federal Energy Regulatory
6 Commission (11FERC11) Office of the General Counsel, from
7 1976-1981. During my term at the FERC, I worked with a
8 staff team that was responsible for drafting and
9 implementing regulations under the Public Utility
1 O Regulatory Policies Act of 1978 ( 11 PURPA 11) • In that
11 capacity I am listed as one of the four staff contacts
12 for the FERC's order adopting regulations implementing
13 section 210 of PURPA, which requires electric utilities
14 to purchase electric power from and sell electric power
15 to qualifying cogeneration and small power production
16 facilities (11QFs11), and to pay rates based on the
17 utility's avoided costs. These regulations require state
18 regulatory commissions to implement the FERC regulations.
19 Since leaving FERC in 1981, I have worked as an
20 attorney in the electric power industry and have handled
21 many matters relating to PURPA.
22 Q. As a staff member, you did not vote on the
23 rules that FERC issued, correct?
24 A. That is correct. I and the other members of
25 the group working on PURPA implementation drafted
581 Wenner, Di 1
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1 proposed rules, participated in conferences around the
2 country, reviewed and analyzed comments filed in the
3 rulemaking proceeding, and drafted a recommended final
4 rule that FERC voted to adopt.
5
6
Q.
A.
What is the purpose of your testimony?
I have been asked to provide my opinion
7 regarding a proposal before the Idaho Public Utility
8 Commission ("Idaho PUC") in the above-styled docket
9 regarding the PURPA and FERC requirements for long-term
10 power purchases from QFs. In this docket the Idaho PUC
11 is
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1 considering a proposal ("Petition") by Idaho Power
2 Company ("Idaho Power") to direct that the maximum
3 required term for prospective Idaho Power PURPA energy
4 sales agreements be reduced from 20 years to two years.
5 Q. Do you have an opinion as to whether this
6 approach is consistent with PURPA and the FERC's PURPA
7 regulations and decisions?
8 A. Yes. In my view this approach does not satisfy
9 the FERC's regulations and is inconsistent with PURPA.
10 Q. Please explain the basis for your opinion.
11 A. There are two grounds for my opinion: ( 1) the
12 PURPA legislation and the FERC regulations require that
13 QFs be paid capacity payments when their commitment to
14 provide energy to a utility enables the utility to
15 replace new capacity with QF purchases. Capacity can
16 only be replaced when QF power is guaranteed to be
17 available for a term that is sufficiently long, in terms
18 of the utility planning horizon - which typically
19 involves twenty-year or longer service lives for the
20 "avoided" generating unit that is displaced by QF energy
21 and capacity; and (2) the FERC regulations provide QFs,
22 at their option, the legal right to provide energy and
23 capacity to a utility pursuant to a "legally enforceable
24 obligation", over a term specified by the QF, in which
25 the QF is paid based on projections of avoided costs,
583 Wenner, Di 2
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1 determined at the time that the obligation is incurred.
2 FERC has interpreted this regulation to mean that by
3 making a binding offer to sell its power over a specified
4 term, the QF obligates the state commission to impose a
5 legally enforceable obligation to purchase the QF's power
6 over the specified term, at rates based on projected
7 avoided costs. An Idaho PUC policy that limits legally
8 enforceable obligations to
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1 purchase from QFs to a two year period would be
2 inconsistent with and in violation of the FERC's
3 regulation.
4 Q. Please elaborate on the first reason that you
5 identify above for concluding that Idaho's proposal to
6 limit QF contracts to two years is not appropriate.
7 A. As FERC noted in Order No. 69 in a discussion
8 about whether avoided costs should include capacity
9 payments as well as energy payments, the Conference
10 Report issued by Congress, in conjunction with section
11 210 of PURPA, stated:
12 The conferees expect that the Commission in
judging whether the electric power supplied by the
13 cogenerator or small power producer will replace
future power which the utility would otherwise have
14 to generate itself either through existing capacity
or additions to capacity or purchase from other
15 sources will take into account the reliability of
the power supplied by the cogenerator or small power
16 producer by reason of any legally enforceable
obligation of such cogenerator or small power
17 producer to supply firm power to the utility.
18 Small Power Production and Cogeneration Facilities;
19 Regulations Implementing Section 210 of the Public
20 Utility Regulatory Policies Act of 1978, Order No. 69,
21 FERC Stats. & Regs. 1 30,128 (1980), 45 Fed. Reg. 12,214,
22 12,225 (Feb. 25, 1980) ("Order No. 69") (quoting
23 Conference Report on H.R. 4018, Public Utility Regulatory
24 Policies Act of 1978, H. Rep. No. 1750, 99, 95th Cong.,
25 2d. Sess. (1978)).
585 Wenner, Di 3
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1 Based on this Congressional intent of PURPA, FERC
2 observed, in Order No. 69, that:
3 In order to defer or cancel the construction of
new generating units, a utility must obtain a
4 commitment from a qualifying facility that provides
contractual or other legally enforceable assurances
5 that capacity from alternative sources will be
available sufficiently ahead of the date on which
6 the utility would otherwise have to commit itself to
the construction or purchase of new capacity. If a
7 qualifying facility provides such assurances, it is
entitled to receive rates based on the capacity
8 costs that the utility can avoid as a result of its
obtaining capacity from the qualifying facility.
9
10 45 Fed. Reg. at 12,225.
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1 Q. How does this instruction by FERC apply to an
2 Idaho QF's right to a purchase contract of more than two
3 years?
4 A. The FERC's language is straightforward. If a
5 QF enters into a contract or provides "legally
6 enforceable assurance" that it will be available on the
7 date that the utility would otherwise make a commitment
8 to construct new generating capacity, then the QF is
9 entitled to payments based on the avoided cost of
10 constructing the new generating unit. A new conventional
11 coal or gas-fired plant has a service life in excess of
12 20 years, and therefore can only be replaced by power
13 from QFs if the QFs are obligated to provide power for a
14 term at least that long. Conversely, if a QF contracts
15 or legally enforceable obligations are limited to two
16 years, that power cannot be counted on to be available
17 after two years, and so a utility could not cancel
18 planned generation based on such a short commitment. The
19 FERC's statement in Order No. 69 accordingly must be read
20 to require that sufficiently long contract terms or
21 legally enforceable obligations are available to enable
22 planned generation to be canceled, a requirement that is
23 not consistent with a two-year term.
24 Q. Are there other provisions of the FERC's
25 regulations under PURPA that shed light on this issue?
587 Wenner, Di 4
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1 A. Yes. Section 292. 304 (d) (2) of the FERC' s rules
2 states that a QF has the option to provide energy or
3 capacity on an "as-available" basis, or pursuant to a
4 "legally enforceable obligation for the delivery of
5 energy or capacity over a specified term."
6 Q. Does the QF have options with respect to the
7 determination of its avoided cost rate, if it chooses the
8 second option, namely to provide energy pursuant to a
9 "legally enforceable obligation for the delivery of
10 energy or capacity over a specified term"?
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588 Wenner, Di 4a
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1 A. Yes. Section 292. 304 ( d) ( 2) states that the QF
2 has the option to receive avoided cost rates calculated
3 at the time of delivery or at the time the obligation is
4 incurred.
5 Q. Do the FERC rules specify a specific number of
6 years or other time period for the term over which the Qr
7 which accepts a legally enforceable obligation is
8 entitled to receive avoided cost rates calculated at the
9 time the obligation is incurred?
10 A. No. However, there are many provisions of the
11 rules and of FERC's decisions applying its rules that
12 provide guidance on this topic.
13
14
Q.
A.
Please describe these provisions.
First, FERC has explained that section
15 292. 304 (d) (2) gives a QF the right to establish a fixed
16 contract price for its energy and capacity at the outset
17 of its obligation. Order No. 69, rERC Stats. & Regs.
18 <JI 30, 128 at 30, 880).
19 Q. Did rERC explain that the section 2 92. 304 ( d) ( 2)
20 right to a fixed price contract means that a QF has a
21 right to a contract or legally enforceable obligation
22 based on projected avoided costs?
23 A. Yes. Section 2 92. 304 ( d) ( 2) provides that a Qr
24 has the option to sell on an "as-available" basis, or
25 pursuant to a legally enforceable obligation, over a
589 Wenner, Di 5
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1 specified term. In the latter case, the QF has the
2 option to select rates that are calculated at the time
3 that the obligation is incurred.
4 Q. Are there instances in which FERC characterized
5 the right of a QF to a fixed-rate contract or legally
6 enforceable obligation under section 292.304(d) (2) as
7 giving a QF the right, at its option, to a long-term
8 contract?
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1 A. Yes. In its discussion in Order No. 69 of
2 "levelized avoided cost payments," FERC noted that that
3 "[a] facility which enters into a long term contract to
4 provide energy or capacity to a utility may wish to
5 receive a greater percentage of the total purchase price
6 during the beginning of the obligation." 45 Fed. Reg
7 12,224 (emphasis added).
8 Q. Has Idaho interpreted section 292.304(d) as
9 granting a QF the right, under PURPA, to a long-term
10 fixed contract?
11 A. Yes. In its 1984 decision affirming an order
12 by the Idaho PUC requiring Idaho Power Company to enter
13 into a thirty-five year contract to purchase power from a
14 QF, the Idaho Supreme Court stated that "FERC's intent
15 that (QFs], at their option, could enter into fixed-term
16 contracts is manifested by" the above-quoted language
17 from Order No. 69 regarding long-term contracts. Afton
18 Energy, Inc. v. Idaho Power Co., 107 Idaho 781, 786, 693
19 P.2d427, 432 (1984) ("Afton Energy").
20 Q. Did the Afton Energy decision indicate the
21 basis for the thirty-five year contract term proposed by
22 the QF and imposed by the Idaho PUC?
23 A. Yes. The decision states "[t]he thirty-five
24 year period corresponds to the life of Idaho Power's own
25 thermal unit that can be "avoided" by purchasing power
591 Wenner, Di 6
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1 from the [QF] ." Afton Energy, 107 Idaho at 783, 693 P.2d
2 at 429.
3 Q. Is that reasoning consistent with the concept
4 of avoided costs, as defined by FERC in Order No. 69?
5 A. Yes. The provisions that are referenced above,
6 relating to the circumstances in which a QF can receive
7 capacity payments by enabling the purchasing utility to
8 alter its capacity
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1 expansion plans based on the obligation to provide power
2 in the future, inherently contemplate that the QF's
3 legally enforceable obligation will be sufficiently long
4 to accomplish this result. This is consistent with the
5 Idaho PUC's order as affirmed by the Idaho Supreme Court
6 in Afton Energy.
7 If a state commission adopts rules under which a
8 utility is permitted to limit the purchase obligation to
9 a term that is too short to enable it to affect the
10 utility's planning, then the state commission will have
11 failed to implement the FERC's regulations permitting
12 capacity payments.
13 Q. What other provisions are relevant to this
14 issue?
15 A. Section 292.302(b) (2) requires utilities to
16 make available the utility's plans for the addition of
17 capacity, purchases of firm energy and capacity, and
18 capacity retirements for each year during the succeeding
19 ten years. The ten-year horizon is consistent with the
20 long-term planning associated with utility capacity
21 additions, and is indicative of the time frame that FERC
22 concluded was necessary in order for QFs to compute the
23 avoided costs on which their contracts or other legally
24 enforceable obligations would be calculated.
25 Q. Are there other provisions of the FERC's rules
593 Wenner, Di 7
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1 that shed light on this topic?
2 A. Yes. Section 292.304(e) identifies factors
3 which are to be taken into account in determining the
4 avoided cost rate to which a QF is entitled. One of the
5 factors listed is: "(iii) the terms of any contract or
6 other legally enforceable obligation, including the
7 duration of the obligation, termination notice
8 requirement and sanctions for non-compliance."
9 Q. Did the FERC discuss this provision in its
10 order adopting the PURPA regulations?
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1 A. Yes. FERC stated that clause (iii) (quoted
2 above) "refers to the length of time during which the
3 qualifying facility has contractually or otherwise
4 guaranteed that it will supply energy or capacity to the
5 electric utility." Order No. 69, 45 Fed. Reg. at 12,226.
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15 Id.
A utility-owned generating unit normally will
supply power for the life of the plant, or until it
is replaced by more efficient capacity. In
contrast, a cogeneration or small power production
unit might cease to produce power as a result of
changes in the industry or in the industrial
processes utilized. Accordingly, the value of the
service from the qualifying facility to the electric
utility may be affected by the degree to which the
qualifying facility ensures by contract or other
legally enforceable obligation that it will continue
to provide power. Included in this determination,
among other factors, are the term of the commitment,
the requirement for notice prior to termination of
the commitment, and any penalty provisions for
breach of the obligation.
16 Q. How is this provision relevant to the issue of
17 the term that a state commission must establish for QF
18 sales?
19 A. The rule states that the value of the QF's
20 power, and therefore its avoided cost payment, is linked
21 to the term over which it agrees, by contract or by
22 accepting a legally enforceable obligation, to provide
23 power. Implicit in the rule is that the length of the
24 term over which the QF commits to provide power is a
25 decision for the QF. Also, in discussing QFs' right to
595 Wenner, Di 8
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1 capacity payments, FERC stated, in the preamble to its
2 PURPA regulations, that "capacity payments can only be
3 required when the availability of capacity from a
4 qualifying facility or facilities actually permits the
5 purchasing utility to reduce its need to provide capacity
6 by deferring the construction of new plant or commitments
7 to firm power purchase contracts." Order No. 69, 45 Fed.
8 Reg. at 12,225-26. FERC confirmed its position that "if
9 a qualifying facility offers energy of sufficient
10 reliability and with sufficient legally enforceable
11 guarantees of deliverability to permit the purchasing
12 electric utility to avoid the need to construct a
13 generating plant, to enable it to build a smaller, less
14 expensive plant, or to purchase less firm power from
15 another utility than it would
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1 otherwise have purchased, then the rates for purchases
2 from the qualifying facility must include the avoided
3 capacity and energy costs." Id. at 12,226. A state
4 commission PURPA implementation that denies QFs the
5 ability to enter into a contract or legally enforceable
6 obligation to provide long-term value to the utility, and
7 thus to receive avoided cost payments reflecting that
8 value, is inconsistent with section 292.304(e) (iii).
9 Q. Are you aware of orders by the Idaho PUC that
10 discuss its view of the requirements of PURPA and FERC's
11 regulations regarding contract length?
12 A. Yes. I have reviewed Idaho PUC Order No.
13 33253, issued March 18, 2015. Citing Afton Energy, 107
14 Idaho at 785-86, 693 P.2d at 431-32 and Idaho Power v.
15 Idaho PUC, 155 Idaho 780, 782, 316 P.3d 1278, 1280 (2013)
16 ("Idaho Power") , that order states that "PURPA, and
17 regulations implementing the Act, are silent as to
18 contract length; consequently, the issue is in the [Idaho
19 PUC's] discretion." Idaho PUC Order No. 33253 at 2.
20 Q. Do the references to Afton Energy and Idaho
21 Power state that the issue of contract length is in the
22 Idaho PUC's discretion?
23 A. They do not. In Afton Energy, the Idaho
24 Supreme Court stated that the Idaho PUC "did not abuse
25 its discretion in implementing the mandates of PURPA by
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1 requiring Idaho Power to contract with Afton for the
2 purchase of its power over a thirty-five year period."
3 Afton Energy, 107 Idaho at 786, 693 P.2d at 432. In
4 Idaho Power, the Idaho Supreme Court simply noted that "a
5 state regulatory authority has discretion in determining
6 the manner in which the rules will be implemented, and
7 may comply by issuing regulations, by resolving disputes
8 on a case-by-case basis, or by other action reasonably
9 designed to give effect to FERC's rules." Idaho Power,
10 155 Idaho at 782, 316 P.3d at 1280 (citing FERC v.
11 Mississippi, 456 U.S. 742, 751 (1982)), and that the
12 Idaho PUC has "broad discretion ... in implementing FERC's
13 rules and in determining the
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1 requirements for a legally enforceable obligation." Id.,
2 155 Idaho at 787, 316 P.3d at 1285. Neither decision
3 gives the Idaho PUC discretion to establish maximum QF
4 contract terms that are inconsistent with PURPA or the
5 FERC's regulations thereunder.
6 Neither decision holds that the Idaho PUC has
7 discretion to implement PURPA or the FERC's regulations
8 thereunder by establishing a maximum contract length for
9 QF that, by any industry standard, does not enable the QF
10 to receive "long-term avoided cost contract or other
11 legally enforceable obligation," as mandated by Order No.
12 69.
13 Q. Does Idaho Power express a position on this
14 issue in its Petition?
15 A. Yes. Idaho Power's Petition states, at page
16 10, that "[d]etermination of the proper terms and
17 conditions of a required PURPA energy sales agreement,
18 including the authority to determine the proper price,
19 the proper term, and the authority to approve or
20 disapprove the contract itself is soundly, and
21 completely, within the authority and discretion of the
22 [Idaho PUC." (emphasis added). It also states, at page
23 35, that the require term for such a purchase "is within
24 the authority and discretion of the [Idaho PUC] to
25 determine and set."
599 Wenner, Di 10
ICL & SC
1 Q. In your opinion would an Idaho PUC order
2 establishing a maximum required term of two years for
3 Idaho QF PURPA contracts be consistent with PURPA and the
4 FERC's regulations under PURPA?
5 A. Such an order would not be consistent with
6 PURPA or the FERC's regulations thereunder. As explained
7 above, PURPA and the FERC regulations grant QFs the right
8 to a contract or legally enforceable obligation to sell
9 energy and capacity at long-term avoided costs. In the
10 electric utility industry, and as discussed in my
11 testimony, a two-year term fails to permit a QF to
12 estimate, with reasonable certainty, the expected return
13 on its potential investment in a
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600 Wenner, Di lOa
ICL & SC
1 QF, and would frustrate the requirement of section 210 of
2 PURPA that FERC's rules, as implemented by state
3 commissions, encourage cogeneration and small power
4 production.
5
6
7
8
9
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21
22
23
24
25
Q.
A.
Does this conclude your testimony?
Yes.
601 Wenner, Di 11
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1 Q. Are you the same Adam Wenner who filed Direct
2 Testimony in this case on behalf of the Idaho
3 Conservation League and the Sierra Club on April 23,
4 2015?
5
6
7
A.
Q.
A.
Yes.
What is the purpose of your rebuttal testimony?
I have been asked to respond to Idaho PUC Staff
8 Witness Sterling's testimony on two subjects. First, I
9 offer an opinion regarding the legality of adjustable
10 rate contracts under PURPA and FERC's implementing
11 regulations. Mr. Sterling testifies on page 20, lines
12 11-16:
13 FERC rules do not specifically address whether
adjustable rate contracts are acceptable in
14 instances in which the contracting parties
agree in advance to an adjustment method and
15 frequency. Consequently, I am uncertain as to
whether FERC would find adjustment mechanisms
16 acceptable.
17 Second, I offer an opinion of the intent of PURPA to
18 stimulate the market for utility-scale renewable energy
19 up to 80 megawatts in size. Mr. Sterling testifies on
20 page 24, lines 15-20:
21 I believe PURPA was intended to permit
relatively small, non-utility-owned projects to
22 be developed and to compete on an equal footing
with utility owned facilities. I do not
23 believe PURPA was ever intended to serve as the
primary, or even a major, mechanism for utility
24 acquisition of new resources.
25 Q. Are adjustable rate contracts consistent with
602 Wenner, Rebuttal 1
ICL & SC
1 PURPA and the FERC's PURPA regulations and decisions?
2 A. In my view they can be. First, in Order No.
3 69, FERC stated, with respect to state commission
4 implementation of the FERC PURPA rules: "These rules
5 afford the State regulatory authorities and nonregulated
6 electric utilities great latitude in determining the
7 manner of implementation of the Commission's rules,
8 provided that the manner chosen is reasonably designed to
9 implement the requirements of Subpart C [which includes
10 establishing avoided cost
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25
603 Wenner, Rebuttal la
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1 purchase rates] ."1 For example, my understanding is that
2 the California Public Utilities Commission, which was a
3 leader in encouraging cogeneration and small power
4 production development under PURPA, adopted standard
5 offer contracts, with terms of 15 to 30 years that
6 included an adjustable energy component. One standard
7 offer contract, Standard Offer No. 2, provided a fixed
8 capacity price for the term of the contract, while the
9 energy price was linked to the price of fossil fuels used
10 by California utilities. Standard Offer No. 4 contained
11 fixed capacity price for the entire term; energy prices
12 were fixed for the first ten years; after that, the
13 energy price followed the price of fossil fuels used by
14 California utilities.
15 These approaches, in my view, were reasonably
16 designed to implement the FERC's rules, by including
17 sufficiently lengthy terms and fixed payments that
18 developers and their financing parties could rely on for
19 a portion of the payment, and thus providing an assured
20 revenue stream sufficient to justify the financial
21 commitments required for development of cogeneration and
22 small power projects.
23 Q. In your opinion, was PURPA not intended to
24 serve as the primary, or even a major, mechanism for
25 utility acquisition of new resources?
604 Wenner, Rebuttal 2
ICL & SC
1 A. I do not agree. First, note that in addition
2 to small power production facilities projects, which are
3 limited by statute to 80 MW, the same PURPA rules apply
4 to cogeneration facilities - and there is no size limit
5 for cogeneration projects that qualify under PURPA. I am
6 familiar and have worked with cogeneration projects with
7 a capacity of up to 800 MW. As to whether PURPA was
8 intended to serve as the primary, or even a major,
9 mechanism for utility acquisition of new resources, the
10 answer is that the PURPA program was intended to
11 "encourage"
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22
23 1 Small Power Production and Cogeneration Facilities; Regulations
Implementing Section 210 of the Public Utility Regulatory Policies
24 Act of 1978, Order No. 69, FERC Stats. & Regs 130,128 (1980) 45 Fed.
Reg. 12,214, 12,230-31 (Feb. 25, 1980).
25
605 Wenner, Rebuttal 2a
ICL & SC
1 cogeneration and small power production, because at the
2 time the nation was in a severe energy crisis. Since
3 these technologies reduced conventional fuel use for
4 power generation, the intent was to develop as much
5 cogeneration and small power production generation as
6 possible, without paying more than avoided costs, so that
7 ratepayers did not pay more than they otherwise would.
8 So, to the extent that cogeneration and small power
9 production could serve as the primary acquisition vehicle
10 for new utility resources while being rates that do not
13
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25
Q.
A.
Does this conclude your rebuttal testimony?
Yes.
12 legislation.
11 exceed avoided costs, that result was intended by the
606 Wenner, Di 3
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1 (The following proceedings were had in
2 open hearing.)
3
4
MR. OTTO: Mr. Wenner is available for cross.
COMMISSIONER KJELLANDER: Thank you. Let's
5 begin with Mr. Walker.
6 MR. WALKER: Thank you, Mr. Chairman. Idaho
7 Power reiterates its previous objection to the -- to this
8 testimony as being improper and respects and understands
9 the Commission's earlier ruling and understands that the
10 Commission will give this testimony its due weight, and I
11 have no other questions for Mr. Wenner.
12 COMMISSIONER KJELLANDER: Thank you, Mr.
13 Walker. Let's go to Avista.
14
15 Wenner.
16
17
18
MR. ANDREA: Just a couple of questions, Mr.
CROSS-EXAMINATION
19 BY MR. ANDREA:
20 Q. On page 6 of your direct testimony at lines 8
21 through 13, you cite the Afton Energy case, which is an
22 Idaho Supreme Court case as interpreting Section
23 292.304(d) as granting QFs the right under PURPA to a
24 long-term, fixed contract; is that correct?
25 A. Well, it doesn't say it quite that way. It
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607 WENNER (X)
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1 says -- it quotes from the decision and says that the
2 35-year period established in that case by the --
3 approved by the Idaho Supreme Court was consistent with
4 the avoided cost concept.
5 Q. I'm not sure I understand your answer, so
6 basically what you say here is that the Idaho Supreme
7 Court stated that FERC's intent that QFs, at their
8 option, could enter into fixed-term contracts is
9 manifested by the above-quoted language from Order 69
10 regarding long-term contracts.
11 A. Excuse me one second, which line are you
12 reading from?
13 Q. So I'm on page 6 starting at line 8 and reading
14 through -- really 10 through 13.
15
16
A. Okay.
MR. OTTO: Mr. Commissioner, I didn't hear a
17 question there.
18 MR. ANDREA: I'm just making sure that we're
19 looking at the same testimony.
20
21
22
Q.
A.
Q.
BY MR. ANDREA: So are you at that point?
Yes, I'm with you.
So isn't it true that the court in Afton only
23 held that Section 292.304(d) granted the QF the option to
24 enter into a contract for a specified term; isn't that
25 true?
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608 WENNER (X)
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1 A. I'd have to pull up the decision. My
2 recollection, that I looked at the decision when I was
3 writing the testimony, was that it was a 35-year
4 contract.
5 Q. Right, it was a 35-year contract at issue and
6 the court held that the Commission didn't abuse its
7 discretion by requiring a 35-year contract, but
8 292.304(d) doesn't require any particular term; isn't
9 that correct?
10
11
12
A. That's correct.
MR. ANDREA: Thank you.
COMMISSIONER KJELLANDER: That concludes your
13 cross?
14
15 thank you.
16
MR. ANDREA: It does. No further questions,
COMMISSIONER KJELLANDER: Thank you.
17 Ms. Hogle.
18
19 Honor.
MS. HOGLE: I have none. Thank you, Your
20 COMMISSIONER KJELLANDER: Thank you. Mr.
21 Howell? Ms. Huang.
22 MS. HUANG: Thank you, Mr. Chair, actually just
23 very briefly.
24
25
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609 WENNER (X)
ICL & SC
1
2
3 BY MS. HUANG:
CROSS-EXAMINATION
4 Q. Mr. Wenner, you are not licensed to practice
5 law in Idaho; is that correct?
6
7
A. That is correct.
MR. OTTO: Commissioners, I object. As we
8 covered in our motion, Mr. Wenner is not practicing law
9 in Idaho. He's not holding himself out to the public.
10 He hasn't signed a brief.
11 COMMISSIONER KJELLANDER: I think at this point
12 the question has been asked, it's been answered. It
13 seemed pretty straightforward. We'll see where it goes
14 from there.
15
16 Q.
MS. HUANG: Thank you, Mr. Chair.
BY MS. HUANG: And Mr. Wenner, have you ever
17 practiced law in Idaho?
18
19
A. No.
MS. HUANG: Thank you. I have no further
20 questions.
21
22 Adams.
23
24
25
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. ADAMS: No questions. Thank you.
COMMISSIONER KJELLANDER: Mr. Richardson.
MR. RICHARDSON: No questions, Mr. Chair.
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610 WENNER (X)
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1 COMMISSIONER KJELLANDER: Thank you.
2 Mr. Miller.
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MR. MILLER: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Ms. Nunez.
MS. NUNEZ: No questions. Thank you.
COMMISSIONER KJELLANDER: Mr. Olsen.
MR. OLSEN: No questions, Mr. Chair.
COMMISSIONER KJELLANDER: Mr. Sanger.
MR. SANGER: No questions.
COMMISSIONER KJELLANDER: Mr. Hammond.
MR. HAMMOND: No questions.
COMMISSIONER KJELLANDER: Thank you, Mr.
13 Hammond. Mr. Arkoosh.
14 MR. ARKOOSH: No questions. Thank you,
15 Mr. Chairman.
16
17
18
COMMISSIONER KJELLANDER: Ms. Howland?
MS. HOWLAND: No questions.
COMMISSIONER KJELLANDER: And any questions
19 from members of the Commission? It appears that there is
20 an opportunity for some very brief, but limited,
21 redirect.
22
23
24
25
MR. OTTO: Yes, I have one question.
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611 WENNER (X)
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1
2
3 BY MR. OTTO:
REDIRECT EXAMINATION
4 Q. Mr. Andrea asked you about just one regulation
5 under PURPA. In your opinion, should the Commission
6 consider a regulation in isolation or should the
7 Commission look at the statute as a whole?
8 COMMISSIONER KJELLANDER: Might I inquire?
9 Since this is redirect, whose testimony are you raising
10 that question from or whose cross-examination does that
11 come from, just out of clarification?
12 MR. OTTO: It comes from Mr. Andrea's
13 cross-examination.
14 COMMISSIONER KJELLANDER: Great, thank you, and
15 if you could maybe reference that, too, that would make
16 it easier for me to follow.
17
18
19
MR. OTTO: I will.
COMMISSIONER KJELLANDER: Thank you.
THE WITNESS: In my view, one should interpret
20 the provisions of a regulation in the context of the
21 entire entirety of the regulations issued under one
22 order, in this case it was FERC Order No. 69, and in the
23 context of the Congressionally-enacted legislation, the
24 Public Utility Regulatory Policies Act of 1978,
25 specifically Section 210 thereof.
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612 WENNER {Di)
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1
2
MR. OTTO: Thank you. That's all.
COMMISSIONER KJELLANDER: Thank you, and we
3 appreciate your presence today. Thank you for being
4 here.
5 MR. OTTO: I ask that Mr. Wenner be excused
6 from the remainder of the proceeding.
7 COMMISSIONER KJELLANDER: And without any
8 objection, so ordered. Thank you again.
9
10
(The witness left the stand.)
COMMISSIONER KJELLANDER: And Mr. Otto, if you
11 would like to call your next witness.
12
13
MR. OTTO: Yes, I call Mr. Tom Beach.
14 R. THOMAS BEACH,
15 produced as a witness at the instance of the Idaho
16 Conservation League and the Sierra Club, having been
17 first duly sworn to tell the truth, the whole truth, and
18 nothing but the truth, was examined and testified as
19 follows:
20
21
22
23 BY MR. OTTO:
DIRECT EXAMINATION
24
25
Q.
A.
Hello, Mr. Beach.
Good afternoon.
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613 BEACH (Di)
ICL & SC
1 Q. Could you please state your name and spell your
2 last name for the record?
3 A. My name is Tom Beach. The last name is spelled
4 B-e-a-c-h.
5 Q. Are you the same Tom Beach that filed direct
6 and rebuttal testimony on behalf of the Conservation
7 League and the Sierra Club?
8
9
A.
Q.
Yes, I am.
Do you have any corrections or alterations to
10 that testimony?
11 A. Yes, I do. It has come to my attention that
12 the table of contents of my direct testimony was not --
13 the page numbers were not updated in the final version.
14 Rather than read a list of 12 new page numbers, I do have
15 a list here which I would be happy to give the court
16 reporter of the corrected page numbers. All right, well,
17 I can read them in.
18 COMMISSIONER KJELLANDER: I think we'll be fine
19 and we appreciate that.
20
21
THE WITNESS: Thank you.
MR. OTTO: That was just an abundance of
22 caution on my part.
23
24 continue.
COMMISSIONER KJELLANDER: That's fine. Please
25 Q. MR. OTTO: Mr. Beach, if I asked you the same
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614 BEACH (Di)
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1 questions in the direct and rebuttal testimony today,
2 would your answers remain the same?
3
4
A. Yes, they would.
MR. OTTO: And with that, I ask that Mr.
5 Beach's direct and rebuttal testimony be spread upon the
6 record.
7 COMMISSIONER KJELLANDER: Thank you. Without
8 objection, we will spread the direct and rebuttal
9 testimony across the record as if read and mark and
10 identify the exhibits.
11 MR. OTTO: Yes, those would be Exhibits 301,
12 '2, and '3.
13
14
15
COMMISSIONER KJELLANDER: And 304?
MR. OTTO: Yes.
COMMISSIONER KJELLANDER: Thank you, okay; so
16 that's where we are and are you tendering your witness
17 now for cross-examination?
18 MR. OTTO: Just to be clear, 304, Exhibit 304,
19 was one I brought in on the cross-examining of Ms. Grow.
20 It wasn't actually submitted by Mr. Beach.
21 COMMISSIONER KJELLANDER: Okay, fair enough;
22 duly noted.
23 (The following prefiled direct and rebuttal
24 testimony of Mr. R. Thomas Beach is spread upon the
25 record.)
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615 BEACH (Di)
ICL & SC
1
2
I.
Q.
INTRODUCTION
Please state your name, address, and business
3 affiliation.
4 A. My name is R. Thomas Beach. I am principal
5 consultant of the consulting firm Crossborder Energy. My
6 business address is 2560 Ninth Street, Suite 213A,
7 Berkeley, California 94710.
8 Q. Please describe your experience and
9 qualifications.
10 A. I have over 30 years of experience in utility
11 analysis, resource planning, and rate design. I began my
12 career at the California Public Utilities Commission,
13 working from 1981-1984 on the initial implementation in
14 California of the Public Utilities Regulatory Policies
15 Act (PURPA) of 1978. I then served for five years as an
16 advisor to three CPUC commissioners. Since entering
17 private practice as a consultant in 1989, I have served
18 as an expert witness in a wide range of utility
19 proceedings before many state utility commissions. This
20 includes sponsoring testimony on PURPA-related issues in
21 state regulatory proceedings in California, Oregon,
22 Nevada, North Carolina, and Vermont. Prior to this
23 experience, I earned degrees in English and Physics from
24 Dartmouth College and a Masters in Mechanical Engineering
25 from the University of California, Berkeley. My
616 BEACH, Di 1
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1 curriculum vita is attached to this testimony as Exhibit
2 ICL/SC-301.
3 Q. On whose behalf are you testifying in this
4 proceeding?
5 A. I am appearing on behalf of the Idaho
6 Conservation League (ICL) and the Sierra Club.
7 ICL intervened in this case due to ICL's continuing
8 interest in the development of clean, indigenous energy
9 resources in Idaho through various means, including
10 energy sales agreements between independent developers
11 and electric utilities under PURPA. Such development can
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25
617 BEACH, Di la
ICL & SC
1 ensure that Idaho's electric system provides reliable,
2 fair-priced service that protects the clean air, clean
3 water, and stable climate that are foundational public
4 values for Idahoans. Accordingly, ICL has a strong
5 interest in the major change the Idaho utilities propose
6 in the terms of their PURPA agreements.
7 The Sierra Club is a national, non-profit
8 environmental and conservation organization dedicated to
9 the protection of public health and the environment.
10 Sierra Club has joined with ICL in this case on behalf of
11 itself and nearly 2,400 Sierra Club members who live and
12 purchase utility services in Idaho. Sierra Club's Idaho
13 members have a direct and substantial interest in this
14 proceeding as a result of its potential impact on
15 additional solar deployment in Idaho and on the
16 environmental, health and economic benefits that would
17 result from the addition of this renewable generation to
18 the Idaho electric system.
19 Q. Have you previously testified or appeared as a
20 witness before the Idaho Public Utility Commission?
21 A. Yes, I have. I testified on behalf of ICL in
22 Case No, IPC-E-12-27 concerning proposed changes to Idaho
23 Power's net metering service.
24
25
Q.
A.
Do you have any exhibits?
Yes. Exhibit ICL/SC-301 is my curriculum vitae.
618 BEACH, Di 2
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1 Exhibit ICL/SC-302 are certain discovery responses from
2 Idaho Power. Exhibit ICL/SC-303 is a fact sheet about the
3 new Energy Imbalance Market involving PacifiCorp, the
4 California Independent System Operator (CAISO), Puget
5 Sound Electric, and NV Energy.
6
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I I . BACKGROUND ON PURPA
619 BEACH, Di 2a
ICL & SC
1 Q. Idaho Power's Petition generally describes the
2 requirements of PURPA. Do you have anything to add to
3 this background?
4 A. Yes. ICL Witness Adam Wenner provides a more
5 detailed legal analysis. As a consultant with over 35
6 years of experience in this field, I offer the following
7 economic perspective. Congress enacted PURPA to encourage
8 a new, free market for the independent development of
9 generation from resources that would reduce our nation's
10 dependence on fossil fuels, with the goal of increasing
11 the energy security and independence of the U.S. PURPA
12 required public utilities, who enjoyed a state-sponsored
13 monopoly in the generation market, to purchase power from
14 cogeneration and small renewable power producers,
15 collectively called "qualifying facilities" or QFs, at
16 prices that could not exceed the utilities' "avoided
17 cost." In the words of the statute, avoided costs are
18 "the cost to the electric utility of the electric energy
19 which, but for the purchase from such cogenerator or
20 small power producer, such utility would generate or
21 purchase from another source."1 PURPA's must-take
22 requirement at an avoided cost price was intended to
23 offset the monopsony power of the utility as the sole
24 buyer of generation in its service territory. Congress
25 limited purchase price to the utility's avoided cost in
620 BEACH, Di 3
ICL & SC
1 order to achieve a balance between the interests of
2 ratepayers and PURPA generators, so that the price would
3 be both "just and reasonable to the electric consumers of
4 the electric utility and in the public interest" and "not
5 discriminate against qualifying cogenerators or
6 qualifying small power producers" in comparison to the
7 utility's other supply options. The FERC and the courts
8 have found that a price set at 100% of the utility's
9 avoided cost satisfies this dual standard and the intent
10 of PURPA to encourage QF development.2 In essence, the
11 economic design of PURPA was to simulate the outcome of a
12 free
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20
21
22
23 1 Section 210(d) of PURPA (92 Stat. 3117, 16 U.S.C. § 2601).
2 18 C.F.R. § 292.304(b) (2); American Paper Inst., Inc. v. American
24 Elec. Power Serv. Corp., 103 S. Ct. 1921 (1983).
25
621 BEACH, Di 3a
ICL & SC
1 and open market that would encourage QF development, if
2 QFs could offer generation at a competitive cost equal to
3 or less than the incremental cost to the utility of
4 procuring power from other sources. PURPA generation
5 purchased at the avoided cost price would be reasonable
6 for the consumer because it would be no more expensive
7 than if the monopoly utility had generated the power
8 itself or purchased it from another source.
9 Q. PURPA was enacted almost four decades ago.
10 Have Congress and the FERC enacted significant changes to
11 PURPA since then?
12 A. Yes. PURPA was the key first step in the
13 development of independent power generation in the U.S.
14 The success of this new industry in many states under the
15 PURPA framework enabled the creation, in the 1990s and
16 early 2000s, of viable and less-regulated markets for
17 electric generation in many regions of the U.S. Over
18 time, these markets have expanded to include, in some
19 states, competition in generation at both retail and
20 wholesale levels, as well as non-discriminatory access to
21 electric transmission through regional transmission
22 organizations (RTOs) with independent system operators of
23 the transmission grid. In addition, many states have
24 enacted renewable portfolio standard (RPS) programs,
25 based on states' traditional authority over utility
622 BEACH, Di 4
ICL & SC
1 procurement, designed to provide long-term markets for
2 the new renewable generation that previously had been
3 developed principally through PURPA. Responding to these
4 developments, Congress enacted the Energy Policy Act of
5 2005 (EPAct), which implemented a new Section 210(m) of
6 PURPA. This section allowed a utility to petition the
7 FERC for relief from the "must purchase" requirement of
8 PURPA if FERC found that QFs in that utility's territory
9 have access to sufficiently competitive wholesale markets
10 for long-term sales of capacity and electric energy.
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623 BEACH, Di 4a
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1 Q. Have utilities in other states and regions
2 successfully petitioned the FERC under Section 210(m) of
3 PURPA to end the PURPA must-purchase obligation?
4 A. Yes. However, this has occurred in states that
5 have opened their generation market to substantial
6 competition at the wholesale level. For example, when the
7 major California investor-owned utilities (IOUs)
8 successfully petitioned the FERC for relief from the
9 PURPA must-purchase obligation for QFs larger than 20 MW,
10 they were able to show that California had taken the
11 following steps to provide viable long-term wholesale
12 markets for QF generation:
13 A CPUC-approved program for the IOUs to conduct
14 competitive solicitations for long-term
15 contracts with at least 3,000 MW of existing or
16 new cogeneration QFs;
17 A state-enacted RPS that required the
18 California IOUs to purchase 20% (now 33%) of
19 their generation from RPS-eligible renewable
20 generators by 2020, implemented through regular
21 competitive solicitations to procure RPS
22 generation under long-term contracts of up to
23 25 years;
24 A resource adequacy program requiring the IOUs
25 to purchase capacity from QFs and merchant
624 BEACH, Di 5
ICL & SC
1 generators to meet near-term resource adequacy
2 requirements; and
3 Non-discriminatory access to the transmission
4 system and to an auction-based, day-ahead
5 wholesale energy market operated by a
6 FERC-regulated RTO, the California Independent
7 System Operator (CAISO) .3
8 It is important to note that the PURPA must-purchase
9 obligation remains in place in California (and in most
10 other RTO/ISO footprints) for QFs up to 20 MW in size,
11 and that the must-
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21
22
23
24 3 Pacific Gas & Electric et al, 135 FERC 61,234 (issued June 16,
2011).
25
625 BEACH, Di Sa
ICL & SC
1 purchase obligation can be re-instated if the FERC finds
2 that long-term wholesale markets are no longer available
3 to QFs.
4 Q. Idaho Power's Petition, at page 33, asserts
5 that the RTOs in which the PURPA must-purchase obligation
6 has ended do not provide markets for wholesale sales
7 longer than three years, citing the testimony of William
8 H. Hieronymous from Case No. GNR-E-11-03, which is
9 attached to Idaho Power's Petition. Do you agree with
10 this argument?
11 A. No. The flaw in this argument is that the key
12 feature necessary to end the PURPA must-purchase
13 obligation is that renewable and cogeneration resources
14 must have access to long-term power purchase agreements.
15 These new long-term markets are based on procurement
16 programs, principally RPS programs, sponsored by the
17 states under their authority over utility procurement,
18 not through the RTOs. Again, the California RPS program
19 noted above is an example of such a state-sponsored RPS
20 program that provides long-term contracting opportunities
21 for renewable QFs in California. 29 states have RPS
22 programs, and an additional 8 states have less stringent
23 renewable portfolio goals; these 37 states include
24 virtually all of the states whose utilities operate
25 within RTOs and have deregulated wholesale markets.4
626 BEACH, Di 6
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1 Q. Has the state of Idaho or electric utilities
2 serving Idaho taken steps that might allow it to petition
3 for relief from the PURPA must-purchase requirements.
4 A. I am not aware of any such steps that have been
5 taken in Idaho; instead, in this docket the utilities are
6 asking the Commission to make changes that would clearly
7 frustrate the intent of the state's PURPA program. The
8 Petition and Ms. Grow's testimony both mention the
9 possibility of petitioning FERC for relief from the
10 must-purchase obligation under Section 210(m), as well as
11 a
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1 range of other changes to Idaho's PURPA program modeled
2 on changes that have been made in California and Texas.5
3 However, Idaho Power is not suggesting the pursuit of any
4 of those options at this time.6
5 In my judgement, most of these steps to
6 substantially change the PURPA program in Idaho would
7 require the state to adopt a successor program, such as
8 an RPS, to provide a viable long-term wholesale market
9 for QF generation, and also could require broader changes
10 in the wholesale markets in Idaho and perhaps in the
11 region. Furthermore, even if some of these changes to
12 PURPA were judged to be desirable - for example, even if
13 Idaho enacted an RPS in order to provide more
14 predictable, state-regulated development of renewable
15 resources in Idaho - the competitive market conditions
16 necessary for their approval by the FERC do not yet exist
17 in Idaho. As a result, the longstanding PURPA framework,
18 including the must purchase requirement, will be a
19 feature of the energy landscape in Idaho for the
20 foreseeable future.
21 III. THE TERM OF PURPA CONTRACTS
22 Q. What is your recommendation on the utilities'
23 proposal to reduce from 20 years to two years the maximum
24 term for prospective PURPA contracts for QF projects
25 whose size exceeds the cap for eligibility for the
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1 published PURPA rate?
2 A. The proposed reduction in the maximum term for
3 these QF contracts should be rejected, for the reasons
4 presented below.
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24 5 Petition, at pp. 4-5: Grow Testimony, at pp. 14-15.
6 Petition, at p. 5: Grow Testimony, at pp. 15-16.
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1 Q. What is the first reason why Idaho utilities
2 should continue to make a 20-year contract available to
3 QFs?
4 A. As ICL Witness Adam Wenner explains, and I
5 agree, a contract term of this length is necessary to
6 realize PURPA's policy goal of supporting QF development.
7 I also fully agree with Idaho Power's statement on page 8
8 of the Petition that "the maximum contractual term for a
9 mandatory purchase under PURPA is an extremely important
10 term and condition of the contract and sale." In fact,
11 it is decisive - in my experience, states have
12 successfully encouraged the development of QFs when they
13 have offered long-term (15-year to 35-year) contracts at
14 known avoided cost prices. In contrast, when only
15 short-term (5 years or less) contracts have been
16 available, very few QFs are developed. As I will discuss
17 below, the history of QF development in Idaho and other
18 states supports this conclusion. Developers of solar
19 projects and other renewable QFs will not be able to
20 obtain financing for their projects if all that they can
21 show the lender is that they have a customer for the
22 power for just the first two years of a 25-year project
23 life. In addition, the current indicative pricing for
24 levelized avoided costs for a two-year solar contract are
25 about $29 per MWh, more than 50% below the $60 to $64 per
630 BEACH, Di 8
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1 MWh range of avoided costs for the recently-approved
2 20-year solar contracts.7 As a result, removing the
3 availability of a long-term contract at avoided cost
4 prices appears likely to make uneconomic QFs that could
5 be developed at avoided cost prices with a long-term
6 agreement. Without an RPS or other state-sponsored
7 procurement program for renewable QFs, it becomes
8 questionable whether Idaho Power's proposed two-year
9 maximum term for PURPA contracts adequately supports QF
10 development in its service territory, as PURPA requires.
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24 7 Based on data in Idaho Power Response to J.R. Simplot Production
Request Question No. 3.
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1 Q. The Petition and the testimonies of Idaho
2 Power's witnesses Ms. Grow and Mr. Allphin present
3 information on the long history of the development of
4 PURPA projects in Idaho. What do you observe about this
5 history?
6 A. Virtually all of the QF projects successfully
7 developed in Idaho have done so under power purchase
8 contracts with terms of at least 20 years. This includes
9 the small hydro projects developed in the 1980s and
10 1990s, the wind projects developed in 2010-2012, and the
11 461 MW of solar projects that the Commission approved in
12 2014-2015. Figure 1 illustrates this history, showing the
13
18 400
�
19 �
300
20
200
21
22 100
23 0
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Figure 1: Idaho Power Renewable QFs by Contract Term
10
0
70
60
47 so "' - u I! - 40 c 8 - 0 ... 30 J
E � z 20
- 06
IS I 78 2 I
• Capacity MW • Number of Contracts
626 2
38
45.1
1980 - 1986 1987 - 1995 1996 - 2001 2002 - 2015
(35 year contracts) (20 year contracts) (5 year contracts) (20 year contracts)
700
600
500
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1 The history shown in Figure 1 is not surprising -
2 renewable energy projects have no fuel costs (except for
3 biomass) but are capital-intensive, and, in my decades of
4 experience I have observed
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1 that long-term contracts are essential to access
2 financing on reasonable terms. This need for long-term
3 assurance of capital recovery is the same for QFs as it
4 is for a utility that proposes to build a new power plant
5 and seeks Commission approval for long-term recovery of
6 the plant's costs by including them in rate base. This
7 history suggests that, without long-term, 20-year
8 contracts, QFs will not be developed in Idaho.
9
10
Q.
A.
What other states provide similar histories?
California offered 20- to 30-year PURPA
11 contracts in the 1980s, with renewable QFs provided fixed
12 energy and capacity prices for up to the initial ten
13 years of the contract. About 5,000 MW of renewable QF
14 generation was developed in the state in the late 1980s;
15 most of this capacity is still operating today and now is
16 the lowest cost generation available to the state's RPS
17 program. This development ceased when the long-term
18 contracts were suspended in the late 1980s, and did not
19 revive until after the enactment of the California RPS
20 program in 2004, which again made available long-term
21 contracts of up to 25 years. As another example, the
22 recent active development of solar QFs in North Carolina
23 is founded upon the availability of 15-year contracts at
24 known, fixed prices.
25 Q. Can you cite a recent example where another
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1 state commission has dealt with utility requests to
2 reduce the term of PURPA contracts?
3 A. Yes. Recently, the utilities in North Carolina
4 asked the commission in that state to shorten the term of
5 PURPA contracts to a maximum of 10 years, a reduction of
6 5 years from the maximum of 15-year term that in recent
7 years has resulted in significant development of solar
8 QFs in that state. The North Carolina Utilities
9 Commission rejected this request, finding that the term
10 of QF contracts should be long enough to enable QF
11 projects to be financed.
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1 While the Commission initiated this docket to investigate
2 the need to alter avoided costs determinations, the
3 evidence presented by the buyers and sellers of QF power
4 fail to justify altering the Commission's earlier
5 decisions on term length and related provisions. As
6 discussed earlier, a QF's legal right to long-term fixed
7 rates under Section 210 of PURPA is well established as a
8 result of the FERC's J.D. Wind Orders. The FERC has made
9 clear that its intention in Order No. 69 was to enable a
10 QF to establish a fixed contract price for its energy and
11 capacity at the outset of its obligation because fixed
12 prices were necessary for an investor to be able to
13 estimate with reasonable certainty the expected return on
14 a potential investment, and therefore its financial
15 feasibility, before beginning the construction of a
16 facility. In her responses to cross-examination
17 questions about various Duke Energy Renewables projects,
18 DEC/DEP witness Bowman acknowledged the foregoing by
19 stating that PURPA does not require the best financing,
20 just the ability to secure it.8
21 The circumstances that North Carolina faced - with the
22 utilities strenuously claiming to be overwhelmed by solar
23 QF development - are very similar to those in Idaho
24 today, so this decision is directly relevant to this
25 case.
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1 Q. Idaho Power's testimony highlights that it is
2 allegedly not allowed to consider "NEED" in acquiring
3 PURPA resources.9 Instead of the draconian step of
4 shortening the term of QF contracts, what other steps
5 could Idaho take in order to allow the state greater
6 control over its acquisition of renewable resources?
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23 8 North Carolina Utilities Commission, Order Setting Avoided Cost
Input Parameters (Docket No. E-100 Sub-140, issued December 31,
24 2014), at pp. 19-20. Hereafter, "North Carolina Avoided Cost Order".
9 Petition, at p. 27.
25
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1 A. The Idaho Legislature could enable the state to
2 exert more control of renewable development by enacting
3 an RPS for Idaho. This would allow Idaho utilities to
4 show the FERC that the state has created a long-term
5 wholesale market for additional renewable generation to
6 serve consumers in the state. This showing would be
7 important if the state's utilities were to petition the
8 FERC for relief from the PURPA must-take requirement
9 under Section 210(m), as it was for the California
10 utilities. More generally, an RPS would provide an
11 outlet for renewable development that is under direct
12 state control by the Legislature and the Commission. In
13 states that have RPS programs, when the RPS goal in
14 reached, renewable developers and proponents need to ask
15 the state legislature or regulatory commission to
16 increase the program target. For example, this has
17 already occurred several times in California, as
18 successive RPS goals have been reached.10 Control over
19 renewable development largely passes to the state, and
20 away from the federal PURPA requirements. Although a
21 state RPS does not automatically allow a utility in that
22 state to avoid the PURPA must-purchase obligation, it
23 would make it more difficult for a would-be QF to assert
24 to the FERC that the utility has not done enough to
25 promote QF development, if the utility was in compliance
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1 with the state's RPS program. Further, as noted above,
2 an RPS can be an integral part of a showing under Section
3 201(m) to end the must-purchase obligation.
4 Finally, an RPS would allow Idaho consumers to
5 benefit directly from the extensive renewable development
6 that has already occurred in the state, and that could
7 continue in the future. Because Idaho has no RPS, and
8 because Idaho Power either does not acquire or sells the
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20 10 California's initial RPS goal, enacted in 2004, had a goal of 20%
renewable generation by 2017. This goal was later advanced to 20% by
21 2010, and then increased to the current 33% by 2020. Legislation has
been introduced this year for a further increase to 50% by 2030.
22 California's investor-owned utilities acquire RPS resources through
regular competitive solicitations in which new renewables are
23 procured under the dual standards of (1) least-cost and (2) best-fit
to the needs of the utility. Each utility's need for RPS generation
24 is subject to an extensive planning process overseen by the
California Commission, similar to Idaho's !RP process.
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1 renewable energy credits (RECs) associated with the
2 renewable resources that it purchases, Idaho Power cannot
3 and does not claim that it serves its customers with this
4 renewable generation.11 The utility's Petition compares
5 the amount of renewables on its system to the RPS
6 requirements in other western states that have RPS
7 programs, but these comparisons are meaningless because
8 the RECs associated with this generation are not retired.
9 As a result, renewable development in Idaho supports the
10 RPS programs in other states but does not provide new,
11 clean generation to Idahoans or add to the amount of
12 renewable generation in the region as a whole.
13
14
IV. THE COMMISSION'S IRP METHOD IS WORKING WELL
Q. Do you agree with the Commission's conclusions
15 in its recent orders approving solar contracts that the
16 IRP method of setting avoided cost prices for these
17 contracts is working well?
18 A. Generally, yes. The IRP method allows the fuel
19 price and load forecasts used in calculating avoided cost
20 prices to be updated every year. The Company also is
21 able to include previously-approved QF contracts in these
22 updates.12 The result of such updates is that the price
23 in solar contracts has declined as fuel and load updates
24 have occurred and as additional contracts have been
25 added, as shown in Table 3. The table reflects that the
640 BEACH, Di 13
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1 initial solar contracts used a July 2013 capacity
2 sufficiency year,13 while in the contracts submitted in
3 October 2014, the date of sufficiency had been pushed out
4 to July 2021.14
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20 11 The utility's Application and testimony discusses at length the
substantial renewable development that has occurred in Idaho under
21 PURPA, but the utility carefully footnotes its text and figures with
the revealing disclaimer that "Idaho Power cannot represent to
22 customers that they are receiving renewable energy from the QFs." See
Allphin Testimony, at p. 8, footnote l; also, Petition, footnote to
23 the figure on p. 11.
12 See Order No. 32697 at p. 22.
24 13 See Order No. 33016.
14 See Order No. 33159.
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Table 3: Idaho Power Solar Contract Prices 15
Contract Date Application Submitted 20-year Price {$/MWh)
Approved Contracts
Grand View PV Solar Two 7/25/2014 73.41
Boise City Solar 7/25/2011 72.15
Simco Solar 10/20/2014 63.94
Murphy Flat Power 10/20/2014 63.80
American Falls Solar 10/20/2014 63.61
American Falls Solar II 10/20/2014 62.66
Orchard Ranch Solar 10/20/2014 62.21
Mountain Home Solar 10/17/2014 61.43
Pocatello Solar I 10/17/2014 61.33
Clark Solar 2 10/17/2014 61.03
Clark Solar 4 10/17/2014 60.87
Clark Solar 3 10/17/2014 60.67
Clark Solar 1 10/17/2014 59.97
Potential Contracts
Project Al 52.83
Project A2 54.10
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23
24 The even lower indicative prices for the potential solar
25 contracts Al and A2 indicates that Idaho Power may be
642 BEACH, Di 14
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1 contracts Al and A2 indicates that Idaho Power may be
2 using a capacity sufficiency date that is even further in
3 the future. It is my
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24 15 Data on approved contracts are from Idaho Power Response to Idaho
Irrigation Pumpers Association Production Request No. 11. Data on the
25 potential contracts are from Idaho Power Response to Staff Production
Request No. 9.
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1 understanding that the !RP methodology prices will be
2 further revised when Idaho Power files its 2015 !RP on
3 June 30, 2015. Given that indicative solar contract
4 prices are approaching $50 per MWh, which is at the low
5 end of solar PPA prices as reported by the Lawrence
6 Berkeley National Lab (LBNL),16 it is not clear to me
7 that all of the 885 MW of projects will be able to be
8 developed successfully at these prices. In fact, I
9 reviewed Idaho Power's response to Simplot discovery
10 Question 4 and observe that, of the 885 MW of possible
11 solar projects, consisting of 48 projects, the Company
12 can cite only 14 projects that have progressed far enough
13 to receive indicative prices and only 1 project that has
14 a draft sales agreement.
15 In my judgement, the Commission should be pleased
16 that the !RP method is working as intended. As more
17 solar capacity has been added, the avoided cost price has
18 fallen based on Idaho Power's capacity position and
19 future need. It is simply not true that the Commission's
20 avoided cost methodology fails to consider the future
21 need for new capacity - as the need for capacity is
22 pushed further out into the future, the avoided cost
23 price falls. It is basic economic principle that, as
24 prices fall, fewer projects will be built. And it is
25 also true that if additional solar can be developed at
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1 the new, lower prices that reflect the utility's current
2 need, then Idaho's consumers will benefit from additional
3 renewable generation at even lower costs. As I will
4 discuss in detail below, there are many benefits of this
5 new renewable generation that are not included in the
6 avoided cost price. The Commission should reject Idaho
7 Power's proposal to turn its back on these benefits by
8 reducing the term of these PURPA contracts, a step that
9 essentially would relieve the utility from its PURPA
10 obligations. I share the perspective of Commission staff
11 that was cited in Order 32697:
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23 16 Bolinger, Mark and Weaver, Samantha, Utility-scale Solar 2013: an
Empirical Estimate of Project Cost, Performance, and Pricing Trends
24 in the U.S. at pp. 26-31 and Figure 16, (LBNL, September 2014)
(Hereafter "LBNL Solar Cost Report").
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1 "[t]he proper mechanism for accounting for utility need
2 is not to relieve utilities of their obligation to
3 purchase, but instead to establish prices for capacity
4 and energy that properly recognize the utilities' need,
5 or lack of need, for capacity and energy."17
6 v. RATEPAYER BENEFITS FROM FIXED-PRICE PURPA GENERATION
7 Q. Idaho Power alleges that the continued
8 availability of long-term contracts "inflates the power
9 supply costs borne by customers."18 Do you agree with
10 this contention?
11 A. No. Not only does Idaho's !RP methodology
12 produce reasonable avoided costs that reflect the
13 utilities' needs, as I will explain below, Idaho Power's
14 customers will realize significant additional net
15 benefits from the utility's purchase of renewable
16 generation under PURPA - benefits that are not included
17 in the avoided cost price. These include:
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1.
2.
3.
4 .
5.
REC sales revenues, or avoided costs for
reducing carbon emissions
Hedging benefits
Market price mitigation benefits
Capacity optionality
Local economic benefits
24 Further, Idaho Power's assertions that QF generation will
25 displace less expensive generation are simply not
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1 credible.
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24 17 Order No. 32697 at p. 19, citing Tr. at 1090.
18 Petition, at p. 21, also, generally, pp. 20-25.
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1 Generally, it is important to remember that the
2 prices in these contracts are set based on the best
3 available estimate of the utility's avoided costs, that
4 is, the costs which the utility would incur if it did not
5 buy from the QF, but instead generated the power itself
6 or purchased it from another source. Assuming that these
7 estimates are as accurate as possible (which we will
8 discuss below), then by definition these contracts will
9 not have an adverse impact on Idaho Power's customers,
10 because the utility's costs will be no different than if
11 they had not purchased this generation. Idaho Power's
12 Petition and testimony present numerous figures and
13 tables showing how the utility's PURPA expenses are
14 increasing significantly and would be even higher with
15 the 885 MW of proposed solar contracts.19 This data is
16 irrelevant assuming that the proposed contracts are
17 priced at the utility's avoided costs, because the
18 increased PURPA expenses will be offset by corresponding
19 reductions in Idaho Power's costs for the other resources
20 that the new PURPA generation will replace. Customers
21 will be at least indifferent to the purchase of the PURPA
22 generation, which is the basic tenet of PURPA.
23 Q. Please respond to Idaho Power's assertion that
24 this additional PURPA generation will displace less
25 expensive generation, such that "the Company's overall
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1 net power supply expense, on a dollars per MWh basis,
2 would increase, adversely impacting customers."20
3 A. Significantly, when asked for the impact of
4 these PURPA contracts on future retail electric rates,
5 the utility conceded that it had not done that
6 analysis.21
7 Further, the utility's allegation of adverse
8 ratepayer impacts is not true, because the utility is
9 making apples-to-oranges comparisons among its generation
10 costs. The cost of PURPA
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23 19 Petition, at pp. 22-23; Allphin Testimony, Exhibit No. 7.
20 Petition, at pp. 23-25.
24 21 Idaho Power Response to Staff Production Request No. 2, included
in Exhibit IPC/SC-302.
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1 generation is an all-in, long-term cost that includes
2 both the energy and capacity provided by this generation.
3 Moreover, the QF power is delivered to Idaho Power within
4 its service territory, without incurring the cost of
5 transmission from out-of-state locations or regional
6 markets. For example, the Company compares its PURPA
7 generation costs to Mid-Columbia (Mid-C) market prices.22
8 The Mid-C prices do not include the costs of the
9 transmission capacity (including, in the future,
10 Boardman-to-Hemingway) necessary to deliver Mid-C power
11 to Idaho. In addition, the comparison to general Mid-C
12 prices does not consider that, in some peak hours, this
13 power is not deliverable to Idaho due to transmission
14 constraints; in these hours, PURPA generation can
15 displace internal Idaho Power gas-fired peaking resources
16 that are more expensive than Mid-C prices.
17 Similar problems exist with the comparisons to the
18 Company's coal, natural gas, and non-PURPA purchased
19 power expenses.23 In response to ICL's discovery, Idaho
20 Power responded they provided only the fuel costs for
21 coal and gas.24 Idaho Power's comparison between PURPA
22 prices and coal costs do not include the incremental
23 capital or O&M expenses associated with the utility's
24 coal generation, or with the transmission costs to move
25 this power into Idaho. Likewise, the natural gas
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1 expenses do not include the incremental capital, natural
2 gas pipeline reservation costs, or O&M expenses
3 associated with the utility's gas generation. Moreover,
4 the PURPA contract costs for the solar contracts will be
5 fixed for the 20-year contract term, while the variable
6 costs of coal, gas, and other purchased power will
7 increase significantly over the next 20 years. When costs
8 are compared on an apples-to-apples basis and measured
9 over the full expected life of these contracts, the PURPA
10 generation is no more expensive than the
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23 22 Petition, at pp. 23-24; also Allphin Testimony, Exhibit 10.
23 Petition, at p. 24; also Allphin Testimony, Exhibit 8.
24 24 Idaho Power Response to ICL Production Request No 5, included in
Exhibit IPC/SC-302.
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1 marginal or avoided cost of the generation that it will
2 displace, as required by the Corrunission's !RP method of
3 setting avoided cost prices. In fact, for the reasons
4 discussed below, the solar contracts will offer benefits
5 that will result in lower power supply costs for Idaho
6 Power's customers.
7
8
i.
Q.
REC revenues/avoided carbon mitigation costs
What other benefits do Idaho Power's customers
9 realize from PURPA generation?
10 A. In the absence of an RPS, Idaho Power sells the
11 renewable energy credits (RECs) associated with the
12 renewable resources that it purchases, and the revenues
13 from these sales are a benefit for ratepayers. Pursuant
14 to Corrunission Order No. 32697, QFs who sign long-term
15 contracts with pricing under the !RP method must supply
16 50% of the associated RECs to Idaho Power. And it is my
17 understanding that Idaho Power sells any RECs the Company
18 holds and returns to revenue to customers. If the
19 Commission reduces the maximum contract length so that
20 future QFs have no opportunity to access project
21 financing, then it is my understanding Idaho consumers
22 would not enjoy additional revenue from future QFs.
23 Q. Does Idaho Power receive significant revenue
24 from these REC sales that benefit its ratepayers?
25 A. Yes. These revenues for 2010-2014 are shown in
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1 the following table:
2
3 Table 1: Idaho Power REC Sales
4 Year REC Sales (MWh} Revenues ($ M} REC Price ($/MWh}
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2010 808,862 4,485,724 $5.55
2011 596,225 6,517,833 $10.93
2012 445,687 3,592,782 $8.06
2013 251,774 564,378 $2.24
2014 598,736 3,218,529 $5.38
Average 540,257 3,675,849 $6. 80
7
8 I expect that the purchasers of these RECs use them to
9 meet RPS compliance obligations in neighboring states in
10 the West. All of the other states in the WECC have RPS
11 programs or goals, except for Wyoming.
12 It is my understanding that 95% of the
13 Idaho-jurisdictional revenues from these REC sales is
14 returned to consumers in Idaho. Based on this track
15 record, the 885 MW of additional solar contracts could
16 add $7.8 million per year in additional REC revenues to
17 the benefit of Idaho Power customers.
18 Q. Will Idaho Power benefit if it retains the RECs
19 associated with this generation?
20 A. Yes. If the RECs are retained and retired, then
21 Idaho Power can claim a share of the carbon emission
22 reductions associated with this power. Assuming that the
23 885 MW of potential solar contracts displace gas-fired
24 generation at a heat rate of 8.0 MMBtu per MWh, and using
25 the carbon emission costs that Idaho Power assumed in its
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1 last IRP ($14.64 per ton in 2018, escalating at 3% per
2 year), the value of Idaho Power's 50% share of these
3 reductions in carbon
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1 emissions is about $7.2 million per year over the life of
2 these resources, or about $4 per MWh.25 In the High
3 Carbon case in the IRP ($35 per ton in 2018, escalating
4 at 9% per year), the value of these carbon reductions is
5 $28 million per year or $15 per MWh. I am not aware of
6 what steps Idaho Power may take to comply with the
7 proposed federal carbon emission regulations under
8 Section lll(d) of the Clean Air Act, but these benefits
9 can be considered a proxy for the future compliance costs
10 that the utility may avoid by increasing its purchases of
11 renewable generation.
12
13 Q.
ii. Hedging benefits
Idaho Power argues that "at a time of
14 unprecedented changes in the technological, economic, and
15 regulatory landscapes faced by the electric industry
18 A. No. Based on my 35 years' experience in the
17 fixed-price contracts. Do you agree?
16 today," it is risky for consumers to commit to long-term
19 energy industry in the western U.S., the "landscape" has
20 always been changing, and it is difficult to tell whether
21 the changes on the horizon today are more unprecedented
22 than they have been in the past. With any fixed-price
23 power purchase contract - and with any significant
24 capital investment by the utility in generation or
25 transmission - there is always a risk that the
656 BEACH, Di 21
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1 alternatives will prove to be less expensive over the
2 long-term. This is a risk that consumers bear with PURPA
3 contracts, with other purchases in wholesale markets, and
4 with the alternative of utility-owned fossil-fuel plants
5 whose capital costs are largely fixed once they are
6 approved for cost recovery through rate base and whose
7 fuel costs are subject to significant market risk. Idaho
8 Power complains that the prices or terms of QF contracts
9 cannot be modified once they are signed, yet it is also
10 difficult to modify the costs for
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23 25 To be fair, any new sources of renewable or low-variable-cost
generation will produce such benefits, including Idaho Power's hydro
24 repowering mentioned in the Application.
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657 BEACH, Di 2la
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1 utility owned generation included in the rate base once
2 they have been authorized. If it is too uncertain and
3 too risky to forecast avoided cost prices for 20 years,
4 then it is also too risky to evaluate the merits of a new
5 utility-owned resource (such as the planned
6 Boardman-to-Hemingway transmission line), or even to make
7 decisions based on the long-term projections in an
8 Integrated Resource Plan.
9 The North Carolina commission recognized this in its
10 recent avoided cost order, concluding that the
11 uncertainties in future energy markets will impact
12 ratepayers regardless of whether the utility contracts
13 with QFs at avoided cost or builds its own resources:
14 Failure to calculate accurately a utility's avoided
15 cost means ratepayers will pay for the additional
16 energy and capacity whether the utility builds the
17 plant and places it in rate base or the utility pays
18
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23
24
25
QFs avoided cost rates. The Commission concludes
that establishing avoided cost rates based upon the
best information available at the time and making
such rates available in long-term fixed contracts,
as required by Section 201 of PURPA should leave the
utilities' ratepayers financially indifferent
between purchases of QF power versus the
construction and rate basing of utility-built
658 BEACH, Di 22
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1 resources.26
2 Q. Do fixed-price contracts for renewable
3 generation provide a benefit to consumers as a hedge
4 against future uncertainty and volatility in energy and
5 fossil fuel markets?
6 A. Yes. The alternative to the PURPA contracts is
7 reliance on marginal utility fossil generation (mostly
8 natural gas-fired) and/or market purchases, whose prices
9 also are influenced heavily by gas prices. The value for
10 ratepayers of hedging this exposure is simple:
11 fixed-price
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24 26 Supra n. 8, North Carolina Avoided Cost Order, at p. 21.
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659 BEACH, Di 22a
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., I
16.00
-April 1, 2015
November 3. 2014
-July 3, 2008
-Monthly Average
-June 1. 2011
-November 2. 2009
-June 3. 2013
- -------------
2 .. 00
4.00
6.00
8.00
Figure 1: Henry Hub Market Prices
Monthly Average and Selected 10-Year Forward Market Prices
U.00
14.00
10.00
Fixed prices also hedge against market dislocations or
benchmark Henry Hub gas prices in Figure 2 below.27
last several decades, as shown in the plot of historical
gas prices. Such spikes have occurred regularly over the
generation protects against periodic spikes in natural
generation scarcity such as was experienced throughout
the West during the California energy crisis of 2000-2001
or as is occurring today with the extreme drought in
California and long-term, drier-than-normal conditions
1
2
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13 � � ... .,
14 0.. �
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660 BEACH, Di 23
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1 elsewhere in the West. In 2014, the rapidly increasing
2 output of solar projects in California made up for
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24 27 Figure 2 based on Chicago Mercantile Exchange data.
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661 BEACH, Di 23a
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1 83% of the reduction in hydroelectric output in the state
2 due to the multi-year drought.28 Obviously, there is a
3 risk that consumers may not benefit if future prices turn
4 out to be lower than anticipated, but, if that happens,
5 there is the compensation that consumers will enjoy the
6 low prices for the portion of their needs that is not
7 hedged. Despite this risk, hedging in a commonly accepted
8 practice in utility operations and regulation.
9 The economic literature generally finds that the
10 fixed-price, zero-fuel-cost nature of renewable
11 generation provides a positive value as a hedge against
12 future increases in fossil fuel prices. For example, in a
13 recent study the Lawrence Berkeley National Lab (LBNL)
14 compared fixed-price, long-term wind contracts to the
15 range of expected prices for gas-fired generation, based
16 on the range of recent Energy Information Administration
17 (EIA) gas cost forecasts.29 LBNL concluded that current
18 wind PPA prices in the range of $50 per MWh offer
19 significant benefit as a hedge against the expected range
20 of future fossil fuel prices, even in today's low-price
21 environment for natural gas as a result of the shale gas
22 revolution. Here is the key figure from the LBNL study:
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20 28 Based on Energy Information Administration data for 2014, as
reported in Stephen Lacey, As California Loses Hydro Resources to
21 Drought, Large-Scale Solar Fills in the Gap: New solar generation
made up for four-fifths of California's lost hydro production in 2014
22 (Greentech Media, March 31, 2015). Available at
http://www.greentechmedia.com/articles/read/solar-becomes-the-second-
23 biggest-renewable-energy-provider-in-california.
29 Bolinger, Mark, Revisiting the Long-term Hedge Value of Wind Power
24 in an Era of Low Natural Gas Prices, LBNL-6103E, (March 2013).
Available at http://emp.lbl.gov/sites/all/files/lbnl-6103e.pdf
25
663 BEACH, Di 24a
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Wind PPA sample includes only those signed in 2011 or 2012: 36 PPAs totaling 3,678 MW
Range of recent EIA ps scenarios-·----·---------------- _ zzz: AE011 reference gas
- AE012 reference gas __ -·-- ---------- _
- - AE013 reference gas � Historical gas _ - �-Wind PPAsample . -
- • Wind PPA sample (no PTC) ------- --- ------- - - - - - - -. - -- .,, t _..,.... _,,. _.... -- ..... - .- ·- - if-oo P� . --·- -- ----- ..... -
� m � � rl m � � rl m � � rl m � � � m � � 8 8 8 8 8 rl rl � � rl N N N N N m m m m m � � � � O O O O O O O O O O O O O O O O O O � N N N N N N N N N N N N N N N N N N N N N N N
1
2
3 140
4 120
5
� 100
6 � <, 80 �
7 n, c: 60 ·e
8 0 z 40
9 20
10 0
11
12 Figure 9. Compartson of Recent "·ind PPA Sub-Sample to Projected Range of �atural
Gas Prices
13
14
15 A number of studies have quantified these hedging
16 benefits. In the West, Public Service of Colorado has
17 estimated that the long-term (20-year) hedging benefits
18 of distributed solar resources on its system are $6.60
19 per MWh. 30
20 In light of this well established economic theory
21 backed up by empirical studies, it is remarkable that
22 Idaho Power, when asked in discovery whether "long-term,
23 locked-in price estimates [in PPAs] could potentially
24 benefit Idaho Power in some circumstances," the utility's
25 response was a flat "no.1131
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iii. Market Price Mitigation
21 30 Xcel Energy Services, Costs and Benefits of Distributed Solar
Generation on the Public Service Company of Colorado System: Study
22 Report in Response to Colorado Public Utilities Commission Decision
No. C09-1223 (May 2013), at pp. 6 and 43, and Table 1. This study
23 used the cost of options contracts in the gas futures market to
calculate the hedging benefit. Similar methods have been used in many
24 other solar valuation studies in other regions of the U.S.
31 Idaho Power response to Staff Production Request 18, included in
25 Exhibit IPC/SC-302.
665 BEACH, Di 25a
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1 Q. Will an increasing penetration of new renewable
2 generation in Idaho and the West have an impact on energy
3 market prices?
4 A. Yes. This new solar generation will increase
5 the electricity supplies available to Idaho Power.
6 Because this generation is must-take (and has zero
7 variable costs), it will displace the most expensive
8 fossil-fired or market resources that Idaho Power would
9 otherwise have generated or purchased. The addition of
10 this local generation will reduce the demand which Idaho
11 Power places on the regional markets for electricity and
12 natural gas. With this reduction in demand, there is a
13 corresponding reduction in the price in these markets,
14 which benefits Idaho Power when it does buy power or
15 natural gas in these markets. This ''market price
16 mitigation" benefit of renewable generation is widely
17 acknowledged, and has become highly visible in markets
18 that now have high penetrations of wind and solar
19 resources. The magnitude of these benefits will depend
20 on the overall amount of renewables on the western grid.
21 Q. Are you aware of any modeling of this benefit
22 in the West?
23 A. Yes. The National Renewable Energy Laboratory
24 (NREL) and GE Consulting have undertaken the Western Wind
25 and Solar Integration Study (WWSIS), a major, multi-phase
666 BEACH, Di 26
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1 modeling effort to analyze much higher penetrations of
2 wind and solar resources in the western U.S.32 Although
3 this work focused on the West Connect area (basically,
4 Arizona, Colorado, New Mexico, Nevada, and Wyoming), the
5 modeling has included the entire WECC grid in the U.S.,
6 including Idaho. For example, the WWSIS study of high
7 penetrations of solar (25% penetration in West Connect)
8 also included 15% solar penetration in nearby states,
9 including 1,000 MW of
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22 32 The high penetration solar results from the WWSIS are reported in
NREL and GE Consulting, Impact of High Solar Penetration in the
23 Western Interconnection, at p. 8 and Figure 19 (December 2010). This
report, as well as all reports from the WWSIS, are available on the
24 NREL website at:
http://www.nrel.gov/electricity/transmission/western wind.html.
25
667 BEACH, Di 26a
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1 solar in Idaho. This modeling included analysis of the
2 impact of increasing solar penetration on market prices
3 in the West; the results for spot prices in Arizona are
4 shown in the figure below. Generally, the high
5 penetration solar cases (15% to 25% penetration) result
6 in 10% to 20% reductions in spot market prices. Note
7 that the largest reductions in market prices from a 5%
8 increase in penetration occurs at the low penetrations of
9 solar, which is where the West is today. Only in
10 California is on-line solar penetration approaching even
11 5% today.
12
1000 2000 3000 .«JOO 5000 6CIOO 7000 8000
Hours
...-----------------,1-No Solar
. � Solar
_..,,. Soler -------------------,1 �� -m Solar +-- .... ��:--=--...::------------1_ � Solar
200
180
160
I 140
120 i! 100 I 80 I 60 • 20
0
0
13
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18
16
19
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20
21 Figure 19 - Arizona Spot Price Duration Curves.
22
23 The same market mitigation benefits exist on the natural
24 gas side. Renewable generation reduces marginal gas-fired
25 generation, thus lowering the demand for natural gas. A
668 BEACH, Di 27
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1 study by LBNL has estimated that the gas-related market
2 mitigation benefits of renewable energy range from $7.50
3 to $20 per MWh of renewable output.33
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22 33 See Wiser, Ryan; Bolinger, Mark; and St. Clair, Matt, Easing the
Natural Gas Crisis: Reducing Natural Gas Prices through Increased
23 Deployment of Renewable Energy and Energy Efficiency, at ix (January
2005), Available at:
24 http://eetd.lbl.gov/sites/all/files/publications/report-lbnl-
56756.pdf
25
669 BEACH, Di 27a
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1 As context for how these market price reductions might
2 benefit Idaho consumers, the utility's net electric
3 market purchase expenses in 2015-2016 are forecasted to
4 be $9.3 million; its natural gas expenses are
5 anticipated to be $57.2 million.34
6 Q. Are the fuel hedging and market price
7 mitigation benefits that you have calculated related?
8 A. They are related in that both involve energy
9 market prices for electricity and natural gas. The fuel
10 hedging benefit for consumers results from a reduction in
11 the volatility of these market prices - in other words,
12 in a reduced risk of periodic price spikes in these
13 commodity markets. The market price mitigation benefit
14 is from an overall reduction in the levels of these
15 market prices. Thus, these benefits are related but do
16 not necessarily overlap.
17
19
Q.
A.
Will some of Idaho Power's other potential
Yes. To be fair, any new sources of renewable
18 future resource options also realize such benefits?
20 or low-variable-cost generation will produce such
21 benefits, including Idaho Power's hydro repowering
22 mentioned in the Petition. However, historically PURPA,
23 and the long-term contract Idaho allows, has been a major
24 source of new generation that provides these benefits.
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iv. Capacity optionality
23 34 Direct Testimony of Scott Wrighc, !PC 2015-2016 PCA, Case No.
IPC-E-15-14, at Tables 1 and 2. Net electric market costs are the
24 sum of Accounts 555 (Purchased Power Non-PURPA) and 447 (Surplus
Sales). Gas costs are from Account 547 (Other Fuel).
25
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1 Q. Will these additional solar resources provide
2 new generating capacity in Idaho Power's service
3 territory?
4 A. Yes. In developing the 2015 IRP Idaho Power
5 assumes that solar generation will provide annual
6 capacity equal to about 20 - 30%, and peak hour capacity
7 up to 51% of its nameplate capacity.35 This is based on
8 a very conservative 90% exceedance method. In contrast,
9 other RTOs and control areas in the U.S. use 70% or 50%
10 exceedance methods to assess the capacity value of solar.
11 Thus, the additional 885 MW of solar resources would add
12 at least 280 MW36 and as much as 440 MW37 of capacity.
13 All of this capacity would be internal to Idaho Power's
14 system, and will not require additional out-of-state
15 transmission capacity to be deliverable to Idaho Power's
16 customers.
17 Q. Initial results from Idaho Power's 2015 IRP
18 show the next need for capacity is not until 2025, when
19 the 461 MW of approved solar contracts is included in the
20 resource stack.38 Is there a potential benefit even if
21 the additional 885 MW of solar capacity comes on-line
22 before it is expected to be needed under the utility's
23 current IRP?
24 A. Yes. Idaho Power has no immediate need for
25 capacity based on its current IRP, and this lack of need
672 BEACH, Di 29
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1 is priced into the solar contracts, both those that the
2 utility has signed recently and those that it might sign
3 in the near future. This assumed lack of need results in
4 lower prices in these contracts. However, events may
5 occur that accelerate Idaho Power's need for capacity.
6 One example is the recent short-term cutback in Idaho
7 Power's demand response programs, which
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21 35 Idaho Power presentation to the IRP Advisory Committee on October
2, 2014 at page 4. Available at:
22 https://www.idahopower.com/pdfs/AboutUs/PlanningForFuture/irp/2015/
presentationl00214.pdf
23 36 The 90% exceedance value.
37 50% of nameplate based on the on-peak capacity factor.
24 38 Idaho Power presentation to the IRP Advisory Committee on February
5, 2015 at pages 29 - 30. Available at: https://www.idahopower.com/
25 pdfs/AboutUs/PlanningForFuture/irp/2015/presentation020515.pdf
673 BEACH, Di 29a
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1
2 resulted in a significant short-term acceleration of date
3 of the utility's first need until the funding for that
4 program was restored.39 Another possible factor that
5 could accelerate Idaho Power's need is the retirement by
6 2020 of a portion of the utility's coal capacity, which
7 could occur for a variety of reasons, including the cost
8 of additional emission controls, decisions made by Idaho
9 Power's partners to terminate their involvement in these
10 plants, or compliance needs related to the federal
11 government's Clean Power Plan.
12 As a result, the possible renewable contracts
13 provide Idaho Power essentially with a free option to
14 replace from 280 MW to 440 MW of existing capacity prior
15 to the current date when capacity otherwise is expected
16 to be needed. In other words, customers in Idaho will
17 gain insurance, at no cost, against events, which might
18 threaten reliability by suddenly accelerating the need
19 for capacity. Based on the capacity costs that appear to
20 be included in Idaho Power's !RP-based indicative prices
21 for the potential solar contracts, the value of this
22 option is $9 million to $14 million per year assuming
23 that the capacity is needed in a year before 2022.
24 v. Local economic benefits
25 Q. Will there be economic benefits from Idaho from
674 BEACH, Di 30
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1 additional development of the state's indigenous
2 resources?
3 A. Yes. The construction of an additional 885 MW
4 of solar generation in Idaho will represent an investment
5 of $2.7 billion in Idaho, assuming a capital cost of
6 $3,000 per kW.40 Not all of this money will be spent in
7 Idaho, of course, but there will be significant
8 short-term
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24 39 See Order No. 33016 at pp. 1-2, and Order No. 33084 at p. 5.
Supra n. 16, LBNL Solar Cost Report, at pp. 11-14.
25 40 Supra n. 16, LBNL Solar Cost Report, at pp. 11-14.
675 BEACH, Di 30a
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1 employment benefits during construction as well as
2 permanent employment operating and maintaining these
3 facilities, as well as royalties to landowners and
4 property taxes to local communities. Significantly,
5 these facilities will be located in Idaho, so the
6 economic benefits are more likely to accrue to Idahoans
7 than if these were out-of-state power plants, power
8 purchases from regional markets, or transmission lines
9 that only terminate in Idaho (such as
10 Boardman-to-Hemingway).
11 vi. A window of opportunity to procure low-cost solar
12 Q. Idaho Power asserts that the PURPA contracting
13 process generally means that QFs will request long-term
14 contracts at times when forecasts of future avoided cost
15 prices are high. Is this concern present today?
16 A. No. Natural gas prices today are quite low in
17 historical terms, particularly for longer-term forward
18 contracts. Figure 2, above on page 18 also shows several
19 examples of the 10-year forward price for natural gas at
20 the Henry Hub in recent years. This shows that today's
21 avoided costs are relatively low. New sources of clean
22 energy are competitive with this price. Put simply, if
23 today's independent QF developers can meet or beat this
24 avoided cost, then it will be a good deal for ratepayers.
25 Q. Is this a good time to contract for new solar
676 BEACH, Di 31
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1 generation, in terms of the price for this renewable
2 generation?
3 A. Absolutely. Idahoans need energy every day and
4 the PURPA contracts supply this energy at or below the
5 utilities' avoided costs. It is critical to recognize
6 that the 30% federal investment tax credit (ITC) expires
7 at the end of 2016, after which it will drop to 10%. As
8 a result, the
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1 levelized cost of solar generation is expected to rise
2 significantly for several years beginning in 2017, until
3 cost reductions for this technology can offset the loss
4 of this significant incentive. Using a generation cost
5 tool developed for the WECC, the drop in the federal ITC
6 could add $15 to $20 per MWh (+20% to +25%) to solar
7 contract prices after 2017.41 As a result, now is an
8 opportune moment to purchase solar generation at contract
9 prices that may not be available for a considerable
10 period after 2016.42 Based on solar PPA prices surveyed
11 by LBNL through mid-2014, the utility-scale PPA prices at
12 which Idaho Power has procured solar generation (and
13 today has a window of opportunity to procure more) are
14 comparable to the solar PPAs being procured elsewhere in
15 the country, as shown in the figure below.43
16
"' ..... * - :!l c • - ::= c • -.
..... ..... c .. -.
0 ..... c • -.
g c • ... ! c • -.
s c • - g c • ... s c • ...
0
·------ - ---- - - -- I""'\- - . ---
� 32 MW (New Yorl()
! c • ...
o
�' Planned (1,292 MW, 20 contracts)
O Operatlnc (S,201 MW, 60 contracts)
s c • -
17 � I $250 18 ....... � "' 19 ! $200
20 i $l50 t 21 1 $100
J:t
22 1 $S0
23 $0
24
PPA Execution Date 2 5 Figure 16. Levehzed PPA Prices by Operational Status and PPA Execution Date
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20 41 Based on the 2012 WECC Generation Costing Tool, developed by
Energy & Environmental Economics for the WECC. Available at
21 https://ethree.com/public_projects/renewable_energy_costing_tool.php,
assuming a $2,000 per kW utility-scale solar PV capital cost in 2017.
22 42 This is what the California utilities concluded in 2013, even
though they had largely contracted adequate generation to reach the
23 state's 33% by 2020 RPS goal. Supra n. 28, Lacey, Steven As
California Loses Hydro Resources to Drought, Large-Scale Solar Fills
24 in the Gap.
43 Supra n. 16, LBNL Solar Cost Report, at pp. 26-31 and Figure 16.
25
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1
2
VI. SYSTEM RELIABILITY
Q. Idaho Power is concerned that it will not be
3 able to integrate additional intermittent solar
4 generation into its system, and that the new resources
5 will aggravate the oversupply situation that it faces at
6 certain times of the year, principally in the spring
7 months when hydro resources are abundant. Please
8 comment.
9 A. First, it is my understanding that Idaho Power
10 recently completed a solar integration study and is
11 currently expanding this study to include larger
12 penetrations of solar power.44 Also, the recent solar
13 QF contracts in Idaho require the QF project to cover
14 these integration costs. Second, Idaho Power could
15 reduce the oversupply issue by 15 - 29% by idling the
16 Valmy coal plant in 2016 and 2017.45 Third, as I explain
17 below recent studies of the western grid conclude the
18 system can integrate high solar penetrations and that
19 evolving market mechanisms, like the Energy Imbalance
20 Market, can facilitate this integration.
21 The integration of higher levels of wind and solar
22 resources presents a challenge to utilities and grid
23 operators across the U.S., not just in the West. In
24 recent years, significant effort and numerous studies
25 have been conducted on the operational and system
680 BEACH, Di 33
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1 reliability impacts of the increasing penetration of
2 variable renewable resources. The WWSIS is the most
3 significant such effort in the WECC. As noted above, the
4 WWSIS included a high solar penetration study that
5 considered a 25% solar penetration in the West Connect
6 area, and 15% penetration in the rest of the WECC
7 (including 1,000 MW of solar in Idaho). The WWSIS
8 concluded that it will be
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24 44 See IPC-E-14-18.
45 Based on data from Idaho Power Response to !CL Production Request
25 No 6.
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1 feasible to operate the WECC grid at these levels of
2 solar penetration in the WECC, provided that certain
3 operational changes are made. The key findings of the
4 WWSIS include:
5 Increasing the size of the geographic area over
6 which the wind and solar resources are drawn
7 substantially reduces variability.
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Scheduling generation and interchanges
subhourly reduces the need for fast reserves.
Using wind and solar forecasts in utility
operations reduces operating costs by up to
14%.
Existing transmission capacity can be better
used. This will reduce new transmission needs.
Demand response programs can provide
flexibility that enables the electric power
system to more easily integrate wind and
solar-and may be cheaper than alternatives.
Efforts are already underway to implement such
24 changes. Most notably, PacifiCorp has joined with the
25 CAISO to create a new energy imbalance market (EIM) that
682 BEACH, Di 34
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1 is intended, among other benefits, to address the first
2 two findings of the WWSIS - balancing wind and solar
3 resources over a larger geographic footprint and reducing
4 the costs of integrating such resources by balancing the
5 system more efficiently on a sub-hour basis. A white
6 paper from the FERC staff explains the benefit's of an
7 EIM for renewable integration:
8 An EIM could enhance the reliability of the
9 bulk power system as the system moves towards
10 higher levels of variable energy resources.
11 Balancing authorities need reserves that are
12 loaded and able to reduce output, as well as
13 reserves that are
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unloaded and able to increase output, in order
to respond to the variability from variable
energy resources. Without an EIM, the
variability from variable energy resource
output in the Western Interconnection is not
diversified across balancing authorities. An
7 EIM could help manage variable energy resources
8 more reliably by pooling variability over a
9 larger area, and redispatching resources to
10 help manage imbalance energy caused by variable
11 energy resources.46
12 The EIM began operations on November 1, 2014, and
13 achieved $6 million in savings for its participants in
14 just the first two months of operation.47 NV Energy and
15 Puget Sound Energy will be joining the EIM in October
16 2015 and October 2016, respectively; thus, by the end of
17 2015, utilities that operate in all of the states that
18 neighbor Idaho will be participating in this market.48
19 In discovery, Idaho Power stated that it cannot join the
20 EIM because it lacks the transmission rights to do so
21 (presumably, a lack of rights to access the CAISO
22 balancing area) .49 However, it is my understanding that
23 utilities can participate in the EIM using Available
24 Transmission Capacity even if they do not have rights to
25 the CAISO areaso and that the EIM will be modifying its
684 BEACH, Di 35
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1 protocols to allow expansion to non-contiguous balancing
2 areas within the WECC.51 Significantly, the costs of
3 participation in the EIM are based largely on how much
4 you use it, and
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16 46 FERC, Qualitative Assessment of Potential Reliability Benefits
from a Western Energy Imbalance Market, at p. 17 (February 26, 2013)
17 Available at: http://www.caiso.com/Documents/QualitativeAssessment­
PotentialReliabilityBenefits-WesternEnergyimbalanceMarket.pdf
18 47 CAISO, Benefits for Participating in EIM, at slide 3 (February 11,
2015) Available at : http://www.caiso.com/Documents/Presentation-
19 PacifiCorp_ISO_EIMBenefitsReportQ4_2014.pdf
48 A fact sheet from PacifiCorp about the EIM is Exhibit IPC/SC-303
20 to this testimony. See also https://pse.corn/aboutpse/PseNewsroom/
NewsReleases/Pages/PSE-to-Join-Energy-Imbalance-Market.aspx.
21 49 Idaho Power response to J.R. Simplot Company Production Request
16, included in Exhibit IPC/SC-302.
22 50 For example, NV Energy plans to use Available Transmission
Capacity, and not firm transmission rights, for its EIM transfers.
23 See CAISO, Energy Imbalance Market Year 1 Enhancements - Draft Final
Proposal, at p. 3 (February 11, 2015). Available at:
24 http://www.caiso.com/Documents/DraftFinalProposal_
EnergyimbalanceMarketYearlEnhancements.pdf
25 51 Ibid., at pp. 19-21.
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1 participants retain dispatch authority within their
2 control areas. In essence, the EIM promotes the more
3 granular and efficient exchange of power among the
4 participating control areas.
5 Although the WWSIS study showed the ability to
6 integrate 15 - 25% solar penetration, the rest of the
7 West, except for California, is not close to even a 5%
8 level of solar penetration today. Thus, today Idaho
9 Power should be able to integrate the possible level of
10 solar generation on it system, especially if it can
11 obtain greater access to balancing resources in the
12 region through mechanisms such as the EIM. In addition,
13 the 461 MW of approved solar contracts will be sited in
14 or close to Idaho Power's Treasure Valley load center; I
15 assume that the additional 885 MW will be interconnected
16 directly to Idaho Power's system as well. Because these
17 resources will be internal to Idaho Power's system and
18 will produce significant power during the utility's
19 summer on-peak hours, they should reduce loadings on the
20 congested transmission paths into Idaho during these
21 summer peak periods, further increasing Idaho Power's
22 access to regional markets. Additional capacity on the
23 transmission system serving Idaho also may become
24 available as a result of the retirement of out-of-state
25 coal units serving Idaho Power. This available
686 BEACH, Di 36
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1 transmission capacity will expand access to the regional
2 markets that are increasingly seen as the key to
3 successful integration of a growing penetration of
4 renewable generation.
5 VII. REFINEMENTS TO THE IRP METHOD
6 Q. You have stated above that ICL and the Sierra
7 Club believe that the IRP Method is working well. Please
8 elaborate.
9 A. In my judgment, the IRP method accurately
10 predicts future avoided energy costs, and captures the
11 need for additional generation through the timing of
12 capacity payments. As a result,
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687 BEACH, Di 36a
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1 there is no need to shorten the term of PURPA contracts
2 out of a concern that these contracts will be a future
3 burden for ratepayers in Idaho. To the contrary, as
4 discussed above, they offer many benefits to consumers
5 that are not captured in the avoided cost price.
6 Q. Are there ways in which the IRP method might be
7 improved so that it would reflect Idaho Power's avoided
8 costs even more accurately?
9 A. Possibly. ICL and the Sierra Club recommend
10 that the Commission consider allowing Idaho Power to
11 include the energy and capacity contribution of each QF
12 with a signed contract when calculating the avoided cost
13 values for the next subsequent QF, instead of updating
14 its capacity position just once a year. In essence, this
15 refinement would allow more frequent updates to Idaho
16 Power's capacity position. This more granular
17 calculation of avoided costs based on the utility's
18 up-to-date capacity position and need could further
19 increase the accuracy of the IRP method, and at least
20 partially address Idaho Power's concerns in this regard.
21
22
23
24
25
Q.
A.
Does this conclude your direct testimony?
Yes, it does.
688 BEACH, Di 37
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1 Q. Are you the same R. Thomas Beach who filed
2 Direct Testimony on behalf of the Idaho Conservation
3 League and the Sierra Club on April 23 2015?
4
5
6
A.
Q.
A.
Yes.
Please summarize your rebuttal testimony.
I provide my opinion on three topics. First, I
7 rebut Staff Witness Mr. Sterling's testimony on pages
8 13 - 15 regarding the relative risk of long-term
9 contracts. Second, I rebut Mr. Sterling's position that
10 long-term commitments to utility-owned resources are
11 different than long-term qualifying facility (QF)
12 contracts, because of the scrutiny afforded to utility
13 projects in the IRP process. Third, I describe an
14 example of an adjustable rate contract that complies with
15 PURPA.
16 Q. Do you agree with Mr. Sterling that "a fixed
17 price contract is more risky than one in which prices are
18 adjusted frequently"?l
19 A. No. The standard definition of "risk" is "the
20 chance of loss."2 A contract whose price adjusts
21 frequently may produce the result that the ratepayer
22 receives a price close to the prevailing market price.
23 In this respect, such a contract may reduce the risk that
24 the ratepayer will pay a price different than the market
25 price. However, based on my experience in the utility
689 Beach, Rebuttal 1
ICL & SC
1 industry, this is not what the ratepayer desires,
2 particularly if there is substantial volatility in the
3 market price, for example, as there is in the natural gas
4 market, illustrated in Figure 1 reproduced from my direct
5 testimony. Consumers value rate stability and reasonably
6 predictable rate changes and monthly bills.
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24 1 Sterling Direct, at pg. 13, ln 9 - 10.
2 Webster's New Twentieth Century Dictionary (2nd edition, 1983).
25
690 Beach, Rebuttal la
ICL & SC
1
2
3
4
5
6
::, 7 ... co s �
8 ... QI Q.
<I>
9
10
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13
Figure 1: Henry Hub Market Prices
Monthly Average Market Prices
16.00
14.00
12.00
10.00
-Monthly Averaee
8.00
6.00
4.00
2.00
14 What the ratepayer seeks is a low price, not just a price
15 that equals the market price. And if they cannot always
16 obtain a low price; they prefer a stable price that is
17 predictable. Ratepayers can be substantially harmed if
18 their costs for energy at times are very high as a result
19 of the volatility in energy market prices. As a result,
20 consumers generally are willing to pay a premium to
21 expected market prices in order to eliminate the future
22 volatility in market prices. In essence, this premium
23 represents insurance that consumers are willing to buy
24 against the high costs of periodic spikes in market
25 prices.
691 Beach, Rebuttal 2
!CL & SC
1 Q. Does the economic literature commonly ascribe a
2 risk reduction benefit to fixed price contracts?
3 A. Yes. There are numerous examples and studies
4 that demonstrate that consumers
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692 Beach, Rebuttal 2a
ICL & SC
1 are willing to pay a premium to fix or to limit the price
2 of a commodity, including energy commodities.
3 Perhaps the most familiar is the fixed-rate home
4 mortgage, which typically carries a higher interest
5 rate than an adjustable rate mortgage as the premium
6 required to eliminate the risk of future periods of
7 high interest rates.
8 The natural gas forward market provides consumers
9 with a means to buy future supplies of natural gas
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at a price known today. Comparisons between forward
gas market prices and contemporaneous
fundamentals-based forecasts of gas prices reveal a
consistent premium in the forward prices, perhaps
associated with the "risk premium" that sellers in
the forward markets require, and that buyers are
willing to pay, in order to fix future prices.3
Long-term contracts for natural gas, at
publicly-known prices, are not common today.
However, such contracts typically show a premium to
current price forecasts. For example, in 2011
Public Service of Colorado (PSCo) signed a ten-year
gas supply contract with Anadarko Petroleum to
support the replacement of a portion of PSCo's
coal-fired generation with gas generation, at a
fixed price that was $1.38 per MMBtu higher than the
693 Beach, Rebuttal 3
ICL & SC
1
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Energy Information Administration's contemporaneous
forecast of prices in PSCo's market.4
Many utilities, including those in Idaho, conduct
risk management programs that include hedging that
uses a variety of forward market instruments and
that is designed primarily to reduce the near-term
volatility of their fuel and purchased power
expenses. Generally,
20 3 Mark Bolinger and Ryan Wiser, Comparison of AEO 2010 Natural Gas
Price Forecast to NYMEX Futures Prices (Lawrence Berkeley National
21 Lab, January 2010), esp. Figure 8, available at http://emp.lbl.gov/
sites/all/files/UPDATE%20MEM0%20lbnl%20-%2053587.pdf.
22 4 Lisa Huber, Utility-scale Wind and Natural Gas Volatility:
Unlocking the Hedge Value of Wind for Utilities and Their Customers
23 (Rocky Mountain Institute [RMI], July 2012), at pg. 13-14. The
executive summary is attached as Exhibit 304. The full report is
24 available at http://www.rmi.org/Knowledge-Center/Library/
2012-07_WindNaturalGasVolatility.
25
694 Beach, Rebuttal 3a
ICL & SC
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these programs focus on reducing volatility only in
the next 1-3 years, as the forward markets are most
liquid in the near-term and there are substantial
transaction costs associated with long-term hedges
in financial markets. Significantly, PacifiCorp's
discussion of its hedging program in its most recent
IRP emphasizes how its long position in the power
market functions as a hedge against its short
position in natural gas, and concludes that "[t]his
has the effect of reducing the amount of natural gas
hedging that the Company would otherwise pursue."5
This is exactly the hedge represented by the
fixed-price solar contracts at issue in this case.
In addition, other observers have noted that
long-term, fixed-price contracts for renewable
generation provide utilities with a means not
available in the financial markets to hedge their
long-term exposure to gas and power markets, and
could thus replace a portion of their current
budgets for risk management.6
21 Q. Can you provide examples of "investments made
22 by private investors in which the rates are fixed and the
23 entire revenue is guaranteed for 20 year periods"?7
24 A. Yes, a home mortgage with a fixed interest rate
25 is an obvious example. Banks and other financial
695 Beach, Rebuttal 4
ICL & SC
1 institutions invest in the housing market by lending
2 money to homeowners at fixed rates of return for the
3 interest and principal, for terms of 15 or 30 years. The
4 revenue stream from this investment is guaranteed by a
5 lien on the underlying home property.
6
7
Q.
A.
Is QF revenue guaranteed in Idaho for 20 years?
No. QFs must actually deliver energy within the
8 performance bounds contained in the
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ICL & SC
23 5 PacifiCorp 2015 IRP, at pg. 246-247.
6 Supra note 4, L. Huber, Utility-scale Wind and Natural Gas
24 Volatility: Unlocking the Hedge Value of Wind for Utilities and Their
Customers. (The Executive Summary is attached as Exhibit 304).
25 7 Sterling Direct, at pg. 15, ln 9 - 12.
1 contracts to receive any payments. They are not paid if
2 the QF project is never built or fails to operate
3 correctly. They are not paid for over-delivery and they
4 are penalized for under-delivery. The only element of
5 the contractual payment which is guaranteed is the rate.
6 I note that this is substantially riskier for the QF
7 project than an investment in generation assets is for
8 the utility. Once a utility generation asset is approved
9 for rate recovery through the utility's rate base, the
10 utility will recover its costs, including necessary fuel,
11 and earn a return, even if the plant is out of service or
12 does not perform with the efficiency originally
13 advertised. The only circumstance in which this assured
14 return will be reduced is the infrequent event that the
15 Commission finds, typically after a lengthy regulatory
16 process, that the utility's operation of the plant was
17 imprudent or unreasonable.8 No such finding is required
18 to deny payment to a QF project: if the QF fails to
19 deliver per the contract, it is not paid. Ratepayers
20 benefit from the QF's assumption of this appreciably
21 greater level of operating risk, compared to
22 utility-owned generation.
23 Q. Do you agree with Mr. Sterling that it would be
24 "fair" for utilities to receive long-term commitments to
25 build utility-owned resources, while QFs are limited to
697 Beach, Rebuttal 5
ICL & SC
1 contracts no longer than five years, because of the
2 "intense scrutiny" of the Integrated Resource Plan (IRP)
3 and other approval processes for utility-owned
4 resources?9
5 A. Based on my understanding, PURPA projects in
6 Idaho undergo an equivalently "intense" level of
7 scrutiny. First, the Commission approves an avoided cost
8 methodology developed through a fully litigated
9 Commission docket with multiple parties. Second, the
10 utility's comprehensive IRP process establishes a future
11 resource plan, including the timing of the utility's
12 future need for generation, and models the utility's
13 avoided energy and capacity costs associated with that
14 plan. This extensive process, combining both the IRP and
15 the Commission's approved
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22
23 8 See Order No. 33140 at p 5, AVU-E-14-06 (September 30, 2014)
(allowing recovery of replacement power costs, and declining to
24 review recovery of fixed costs, due to unforced outage of Colstrip
Unit 4).
25 9 Sterling Direct, at pg. 21, ln 22 through pg. 22, ln 7.
698 Beach, Rebuttal Sa
ICL & SC
1 avoided cost methodology, establishes the level and
2 timing of both the capacity and energy payments unique to
3 each proposed QF, and has regular annual updates to
4 ensure accurate information as time moves forward.
5 Importantly, the assumptions and computer model used to
6 develop these avoided cost prices are the same ones used
7 to assess utility-proposed new generation or transmission
8 resources.
9 Finally, once a QF and utility negotiate a contract,
10 the Commission must approve the contract to ensure
11 adherence to Idaho rules and practices. These contracts
12 include performance guarantees by the QF that are more
13 stringent than those which apply to a utility-owned
14 plant. Idaho's method for calculating avoided costs also
15 relies on the utilities' IRPs and thus provides the same
16 assumptions, uses the same tools, and is subject to the
17 same robust scrutiny as utility proposals to build owned
18 resources.
19 Q. In your experience can a state establish
20 long-term PURPA contracts with an adjustable component to
21 rates?
22 A. Yes. For example, in the 1980s, California
23 adopted a standard QF contract for renewable generators
24 ("small power producers" under PURPA) that included ten
25 years of fixed energy and capacity prices, followed by an
699 Beach, Rebuttal 6
ICL & SC
1 additional 5 to 20 years of fixed capacity prices but
2 variable energy prices indexed to natural gas prices and
3 the incremental heat rates of the California utilities.10
4 The CPUC found that this contract structure was necessary
5 to allow renewable QF generation to be financed in the
6 state. The result of this contract was the successful
7 development of many of the first large-scale wind, solar,
8 biomass, and geothermal projects in the U.S. Many of the
9 renewable projects brought on-line in this initial
10 tranche of QF development in California continue to
11 operate today under successor contracts in the state's
12 Renewable Portfolio Standard
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24 10 See CPUC Decision No. 83-09-054 (12 CPUC 2d 604), at 8-9.
25
700 Beach, Rebuttal 6a
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1 (RPS) program, and, as I noted in my direct testimony,
2 these projects supply the lowest-cost renewable
3 generation now available to the RPS.
4 Q. Could such a structure be adapted to how QF
5 generation is priced in Idaho?
6 A. Yes. Idaho currently calculates the rates for
7 capacity and energy separately. Capacity payments are
8 based on the capital costs of a combined cycle combustion
9 turbine and begin in the first year the utility has an
10 identified resource deficiency. Capacity payments
11 continue through the life of the contract and for
12 subsequent contracts based on the premise that, once a QF
13 has resolved a capacity deficit, it continues to avoid
14 other capacity needs for the life of the project. I do
15 not recommend any adjustments to this portion of the
16 avoided costs rates or to power purchase agreements.
17 The Commission could adopt a variable component to
18 the energy rate. For the energy component, the first ten
19 years of prices in the contract would be fixed at the
20 level indicated by the current application of the IRP
21 method. Beginning in Year 11, the portion of the Year 11
22 indicative energy price that represents the forecast of
23 Mid-Columbia (Mid-C) prices in Year 11 would not be
24 fixed, but would be variable based on actual Mid-C prices
25 beginning in Year 11. The remainder of the indicative
701 Beach, Rebuttal 7
ICL & SC
1 energy price for Years 11-20 would continue to be fixed.
2 This would allow, in essence, for the energy portion of
3 the contract to be re-priced after the first ten years.
4 For example, assume that the contract price in Year 11
5 under the IRP Method at the time of contract formation
6 was $75 per MWh, and that at that time the forecast of
7 Mid-C prices in Year 11 was $45 per MWh. Under this
8 option, in Year 11, the contract would include a fixed
9 component of $30 per MWh ($75 - $45 = $30), and the
10 remainder of the contract price would be
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702 Beach, Rebuttal 7a
ICL & SC
1 based on actual Mid-C prices in Year 11, which could be
2 higher or lower than the originally forecasted $45 per
3 MWh.11
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21
Q.
A.
Does this conclude your rebuttal testimony as
Yes.
5 of May 14, 2015?
22 11 This simplified example uses annual prices. It is my
understanding that the !RP method uses much more granular prices
23 disaggregated by month and High Load/Low Load hours, so the
calculation proposed here would be performed on that more granular
24 basis.
25
703 Beach, Rebuttal 8
ICL & SC
1 (The following proceedings were had in
2 open hearing.)
3
4
5 Walker.
6
7
8
9
MR. OTTO: Mr. Beach is available for cross.
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. WALKER: Thank you, Mr. Chairman.
CROSS-EXAMINATION
10 BY MR. WALKER:
11 Q. Mr. Beach, you prepared this testimony
12 specifically for this Idaho case?
13
14
A.
Q.
Yes, I did.
And did you prepare it and the items you
15 discuss, did you discuss those from a general perspective
16 or was it specific for Idaho Power and its operations in
17 the State of Idaho?
18 A. I believe it was specific to Idaho Power and
19 its operations in the State of Idaho.
20 Q. And did you give particular considerations to
21 the implementation of PURPA and the market fundamentals
22 in Idaho or do you speak in a more general sense to those
23 items?
24 A. I believe that my testimony was intended to
25 refer specifically to the fundamentals in Idaho.
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1 Obviously, Idaho is not -- is part of a broader energy
2 market in the Western U.S., so there's some discussion of
3 matters in the broader -- in those broader markets, but
4 my testimony was focused on the issue at hand in Idaho.
5 Q. Isn't it true that your testimony contains a
6 lot of discussion about such things as independent system
7 operator, regional transmission organizations, or EIM
8 markets?
9 A. There is some discussion of that. It's
10 certainly not a major part of the testimony.
11 Q. So isn't it true that Idaho Power has no access
12 or participation in any of those types of
13 organizations?
14
15
A.
Q.
Not that I'm aware of as of this date.
Now, your direct testimony, you purport that
16 fixed price renewable generation actually offers
17 significant benefits to Idaho Power's ratepayers; is that
18 part of your testimony?
19
20
A.
Q.
Yes, it is.
And you go through a number of items that you
21 believe to be those benefits?
22
23
A.
Q.
Yes.
And isn't it true one of those items you list
24 is low-priced solar generation, that there's a limited
25 window of opportunity for Idaho Power to purchase
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1 low-cost solar generation before the 30 percent federal
2 investment tax credit expires at the end of 2016; is that
3 one of your benefits?
4
5
A.
Q.
Yes.
So isn't it true that Idaho Power and its
6 customers do not benefit from that 30 percent federal tax
7 credit?
8 A. No, I disagree with that, because they would
9 benefit in that it reduces the cost, the levelized cost,
10 of energy from solar projects.
11 Q. Who gets the money from that federal tax
12 credit? Isn't it true that Idaho Power and its customers
13 don't see any of that money and it goes right to the
14 developer?
15 A. And it enables the developer to offer a lower
16 price.
17 Q. But does that affect the price that the
18 developer receives in their PURPA avoided cost
19 contract?
20 A. It means that the developer can develop
21 projects at lower avoided cost prices which --
22 Q. Excuse me, that's not what I asked, sir. I
23 asked if that affects the avoided cost rate that they're
24 paid in their contracts.
25 A. Well, the avoided cost rate is not influenced
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1 directly by the federal tax credit.
2 Q. Is the avoided cost rate influenced at all by
3 the federal tax credit?
4
5
A.
Q.
The avoided cost price itself is not.
And you list -- another one of these benefits
6 that you list is lower market prices, and by explanation,
7 you say zero variable cost renewable generation will
8 reduce energy market prices in the West generally; is
9 that one of your benefits?
10
11
A.
Q.
Yes.
And so in this testimony that you prepared
12 taking into consideration Idaho Power's operations, would
13 it surprise you to know that in many instances a reduced
14 energy market price in the West generally actually
15 results in a higher cost to Idaho Power customers for
16 power supply expenses; does that surprise you?
17
19
21
22 yes.
23
A.
Q.
A.
Q.
I think it would depend on whether Idaho Power
And wouldn't it depend, sir, on Idaho Power's
I think that's essentially what I just said,
And you're aware that revenue from Idaho
18 is a net buyer or a net seller.
20 revenue from surplus sales?
24 Power's surplus sales directly offsets the cost that our
25 customers bear of power supply expenses?
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1 A. Yes, when I was putting this testimony
2 together, I looked at what your position is and it
3 appeared to me that you're a net buyer, so you would
4 benefit from lower market prices in the West.
5 Q. But you'd accept, subject to check, that that's
6 not always the case and in many instances lower markets
7 can mean higher prices for our customers?
8 A. Well, if you are a seller, then lower prices
9 are not beneficial, but as I said, my understanding is
10 you're a net buyer and, therefore, lower market prices
11 would benefit your customers.
12 Q. And what did you base that understanding
13 upon?
14 A. I believe I looked at some recent data on your
15 purchases and sales.
16 Q. Did you review any of the Company's annual
17 power cost adjustment filings?
18
19
20
A.
Q.
A.
I believe I did look at those, yes.
From those or one or
I believe I may have looked at data in your
21 recent resource plan, as well as some data that was
22 produced on discovery about your purchases and sales.
23 Q. And another one of your benefits in your
24 testimony talks about sales revenues.
25 A. Yes.
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1 Q. And you've been present to hear the testimony
2 here today; correct?
3
4
A.
Q.
Yes.
And do you recall some previous testimony about
5 how Idaho Power does not have any claim to the RECs for
6 almost all of the PURPA generation that operates on its
7 system?
8 A. It's my understanding that Idaho Power has no
9 claim on it because it sells the RECs that it acquires,
10 and, therefore, that's a revenue stream that benefits
11 customers.
12 Q. So would it surprise you to find out that for
13 all of the approximately 700 megawatts of wind on Idaho
14 Power's system that it claims none of the RECs for
15 that?
16 A. I don't know what the situation is with the
17 wind generation. It is my understanding that your solar
18 contracts that you get 50 percent of the RECs from those
19 contracts.
20 Q. And were you also present when there was
21 testimony about how many of those solar projects operate
22 on our system today?
23 A. Yes, I think you have solar projects under
24 contract but not yet operating.
25 Q. Okay, and are you generally aware of what the
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1 market value of a REC is today?
2 A. I believe in my testimony has -- shows what
3 your REC prices have been for the last five years.
4 Q. And I take it from that chart that you're
5 familiar with this Commission's directions to Idaho Power
6 on what it is to do with any RECs it does own?
7
8 them.
9
A.
Q.
Yes, I believe that the policy is to sell
And is the Company able to fully monetize those
10 over any type of long-term transactions?
11 A. I'm not sure I understand what you mean by
12 "long-term transactions."
13 Q. Does the REC management policy require the
14 Company to sell those RECs in the short term or the long
15 term?
16 A. Well, I'm not aware that there's a long-term
17 market for RECs in the West. There is a short-term
18 market, so it would not surprise me if the directive is
19 to sell the RECs in the short-term market.
20 MR. WALKER: No further questions from Idaho
21 Power, Mr. Chairman.
22 COMMISSIONER KJELLANDER: Thank you. Mr. Otto,
23 before we go any further, I think we need to correct for
24 the record the exact number of exhibits that you have.
25 As I understand, the exhibits attached to Mr. Beach are
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710 BEACH (X)
ICL & SC
1 301, 302, and 303, and in his rebuttal there is one
2 Exhibit 304, so I think what we probably need to do is to
3 renumber the exhibit that you introduced when witness
4 Grow was on the stand and probably label that one as
5 305.
6 MR. OTTO: Yes, thank you very much for that
7 assistance.
8 COMMISSIONER KJELLANDER: Okay, thank you; so
9 without objection, we'll do exactly that and we'll move
10 forward, then. Let's see, Ms. Huang. Mr. Howell.
11 MR. HOWELL: Just ask for Staff. Thank you,
12 Mr. Chairman.
13
14
15
16 BY MR. HOWELL:
CROSS-EXAMINATION
17 Q. Mr. Beach, just a few questions. If you could
18 turn to page 19 of your direct testimony
19
20
A.
Q.
All right, I'm there.
on line 12, you say under the IRP
21 methodology, QFs must supply 50 percent of the associated
22 RECs to Idaho Power. Do you see that line?
23
24
A.
Q.
Yes.
And can you tell me why you use the word
25 "supply"?
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711 BEACH (X)
ICL & SC
1 A. I think my understanding is that the RECs must
2 be transferred to the utility as part of the sale of the
3 power. I guess that's what I meant by "supply."
4 Q. Did you read Order No. 32697?
5 A. I have read parts of that Order.
6 Q. Have you read the Orders in that Case
7 GNR-E-11-03 on reconsideration?
8
9
A.
Q.
I don't believe I read that.
Would it surprise you if I asked you whether
10 Order 32802 said that the ownership of the property
11 interest of RECs should vest equally in both the utility
12 and the QF; would you accept that, subject to check?
13
14
A.
Q.
Subject to check, yes.
So my point is you don't know whether the QF
15 supplies RECs or whether the utility and the QF each own
16 an equal share of the RECs?
17 A. I don't -- I'm not sure I understand the
18 distinction between the two.
19 Q. Well, to me when I read your line 12 and it's
20 your testimony, you say -- you imply that the QF supplies
21 Idaho Power with the RECs, and my question is doesn't the
22 Commission's Order in that case, 11-03, say that the
23 utility and the QF equally own half of the RECs unless
24 they otherwise contract something different?
25 A. Well, I guess, I mean, REC markets, the details
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712 BEACH (X)
ICL & SC
1 of them, can be different from state to state. In some
2 states the generator owns the REC and then they are
3 transferred or supplied to the utility along with the
4 power as part of the transaction under contract. It's
5 possible that states could have a different arrangement
6 where the RECs aren't originally owned by the generator,
7 but somehow get created when the power is produced and
8 half of the ownership goes to the utility. That's
9 conceivable that it works that way in Idaho. I wasn't
10 aware of that detail.
11 Q. So one last question, do you have a
12 recollection of reading Order No. 32802?
13
14
A. No.
MR. HOWELL: All right, thank you very much.
15 No further questions.
16
17
18
19
20
COMMISSIONER KJELLANDER: Thank you. Avista.
MR. ANDREA: Thank you, Mr. Chairman.
CROSS-EXAMINATION
21 BY MR. ANDREA:
22 Q. On page 11 of your testimony, Mr. Beach,
23 starting at line 3, this is your direct, you state, "As
24 discussed earlier, a QF's legal right to long-term, fixed
25 rates under Section 210 of PURPA is well-established as a
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713 BEACH (X)
ICL & SC
1 result of the FERC's J.D. Wind Orders." Is that your
2 testimony?
3
4
A.
Q.
Yes.
I didn't find a site to the J.D. Wind Orders
5 anywhere in your testimony or any discussion of it in the
6 previous pages of your testimony, but I assume that the
7 J.D. Wind Orders that you're referring to are FERC's
8 Notice of Intent Not to Act and Declaratory Order, 129
9 FERC �61,148 issued in 2009, and the Order Denying
10 Requests for Rehearing, Reconsideration or Clarification
11 issued in J.D. Wind 1, LLC, et al., 130 FERC �61,127
12 issued in 2010, both in Docket No. EL09-77; is that
13 correct?
14 A. I can't say that you got the exact cite right,
15 but that sounds like it's correct from the time frame
16 that I was aware of those Orders.
17 Q. If I provided you a copy of those Orders, would
18 it refresh your recollection?
19
20
21
22
23
A.
Q.
Perhaps, yes.
MR. ANDREA: Mr. Chairman, may I approach?
COMMISSIONER KJELLANDER: Yes.
(Mr. Andrea approached the witness.)
BY MR. ANDREA: Now, that you have those
24 Orders, does that refresh your recollection as to whether
25 those are the Orders you intended to cite when you
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714 BEACH (X)
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1 referred to the J.D. Wind Orders?
2 MR. OTTO: Before you answer, I would like to
3 object to this line of questioning. This section of
4 testimony, Mr. Beach just provides a citation and a block
5 quote from a North Carolina order as an example of how
6 another state has dealt with this issue. He doesn't
7 interpret the orders. He's not arguing, you know, what
8 they say. He's just laying out here's how North Carolina
9 dealt with this as, you know, essentially that's kind of
10 like a fact and he's just putting it in front of the
11 Commission for them to consider.
12 MR. ANDREA: So far I haven't asked any
13 questions of substance other than to get clarification
14 over which orders he's referring to there.
15 COMMISSIONER KJELLANDER: And that's exactly
17 because he did reference the J.D. Wind Orders and now
22 taken from a decision of the North Carolina Commission
24 these Orders to conclude whether that's what the North
BY MR. ANDREA: Mr. Beach, are those the Orders
Well, again, I didn't -- this paragraph is A.
Q.
16 where I was at on that, so until we have a question and
19
18 they're here, let's see where the question goes.
20 you intended to cite in your testimony?
21
25 Carolina Commission was referring to. I was involved in
23 and I think I would need to take a look at the details of
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715 BEACH (X)
ICL & SC
1 that case in North Carolina last year and I was aware
2 that the -- that these Orders, you know, have to do with
3 when a legally enforceable obligation is established
4 under PURPA, which is what these Orders appear to be
5 about, so based on that, I would conclude that these are
6 probably the Orders that were referenced by the North
7 Carolina Commission, but I can't say much more beyond
8 that.
9 Q. So you have not read the Orders that I just
10 identified?
11
12
A.
Q.
No, I have not read those.
So you're not aware of any subsequent history
13 to those Orders
14
15
16
17
A.
Q.
A.
Q.
No.
-- presumably?
No.
So you're not aware that the Exelon Wind 1
18 versus Nelson case issued by the Fifth Circuit arose out
19 of these same Orders?
20
21
A.
Q.
No, I am not.
And you're not aware that in that Exelon Wind 1
22 Fifth Circuit opinion, the Fifth Circuit held that
23 resources that couldn't provide reliable output were not
24 entitled to long-term contracts?
25 MR. OTTO: Mr. Chairman, I have to object
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716 BEACH (X)
ICL & SC
15 don't we move to that motion.
12 is incorrect.
BEACH (X)
!CL & SC
717
MR. ANDREA: So Mr. Chairman, he is using this
MR. ANDREA: Okay, I was going to establish a
COMMISSIONER KJELLANDER: If you have a motion
MR. OTTO: Again, his testimony is just a block
COMMISSIONER KJELLANDER: We have a motion,
CSB REPORTING
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6
3 Carolina Order, an example of how another state dealt
5 attempt to interpret them.
2 testimony. He merely cited to a section of a North
7 excerpt from this North Carolina case to establish
1 again. This is going beyond the scope of Mr. Beach's
8 certain facts and I am just trying to establish whether
9 or not he has the knowledge and familiarity with the
4 with this. He did not dive into the J.D. Wind Orders or
11 this particular paragraph should be stricken because it
14 to strike, I think you've probably drilled down, why
10 Orders that are cited within that excerpt and whether
13
18 motion. I would move to strike the question and answer
16
17 couple more facts, but we can move directly to that
19 that starts on page 10 and continues from line 18 through
22 the current state.
23
20 page 11, line 17, on the grounds that it's based upon
21 incorrect, outdated precedent. It doesn't acknowledge
25
24 Mr. Otto.
1 quote from a North Carolina order. It says what North
2 Carolina says. He's not attempting to interpret it or
3 anything. He's just providing an example of what North
4 Carolina said. That seems relevant and admissible.
5 COMMISSIONER KJELLANDER: What about, Mr. Otto,
6 on lines 14 through 16 when there appears to be a
7 conclusion drawn from that North Carolina case?
8 MR. OTTO: I read that as a statement of -- you
9 know, it's an opinion, not a fact, at least. It's just
10 saying Idaho's circumstances are very similar to what
11 North Carolina faced.
12 MR. ANDREA: By failing to recognize the
13 subsequent history, which is directly relevant, it is not
14 complete and, therefore, should be stricken.
15 COMMISSIONER KJELLANDER: So one of your
16 primary objections is to that last -- after the comma on
17 15 through 16, which essentially says, "so this decision
18 is directly relevant to this case"?
19
20
MR. ANDREA: Yes, Mr. Chairman.
COMMISSIONER KJELLANDER: If just that section
21 were stricken, would that satisfy you?
22 MR. ANDREA: I am concerned that the testimony,
23 the other testimony, tends to mislead by not citing to
24 the subsequent history, so I would request that all of
25 what I requested be stricken or, in the alternative, that
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718 BEACH (X)
ICL & SC
1 the subsequent history be included in the record.
2 COMMISSIONER RAPER: It is my observation that
3 the question asks the witness specifically about an
4 interpretation by asking how another state commission has
5 dealt with these things. The witness has said that he
6 was involved in the case in North Carolina. It is the
7 North Carolina Commission that makes the citation to
8 J.D. Wind. I think that, Mr. Otto, you have a choice to
9 make as to whether you allow Mr. Andrea to cross on that
10 basis, because the information was brought up by your
11 witness, or risk the testimony being stricken from the
12 record.
13 COMMISSIONER KJELLANDER: If you'd like a
14 second opinion.
15
16
MR. OTTO: Always a pleasure.
COMMISSIONER KJELLANDER: Yes, I'm inclined to
17 agree with my colleague.
18 MR. OTTO: Mr. Andrea also had a second
19 suggestion, which is to include the follow-up Orders in
20 the record to complete it. I wouldn't object to that
21 solution.
22 MR. ANDREA: I can live with that solution as
23 long as it's included in the record. I've got copies of
24 that follow-up Order. It would be my preference,
25 obviously, to have it stricken because of its tendency to
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719 BEACH (X)
ICL & SC
1 mislead and it being incomplete, but if the Commission
2 would prefer to just lodge the subsequent history in the
3 record, I can provide that as an exhibit.
4 COMMISSIONER KJELLANDER: I think we can live
5 with the resolution that we have there, but also allow
6 cross and to the extent that the witness can respond,
7 that's fine as it relates to that. To the extent that
8 the witness has no knowledge of the Orders or its impact
9 past then, you can get that established as well since
10 we'll be allowing those Orders in as part of the record.
11 MR. ANDREA: Thank you, Mr. Chairman. I think
12 that I can accomplish what I was setting out to
13 accomplish by simply including the subsequent history in
14 the record as part of the record as an exhibit and I
15 think I've established what I needed to on cross.
16 COMMISSIONER KJELLANDER: Thank you, and we
17 need to give these a number. Do we want to keep these
18 exhibits separate or to incorporate them as one exhibit?
19 What number series is Avista?
20 MR. ANDREA: We don't have any exhibits at this
21 point, and I can't remember what exhibit number we were
22 supposed to start with, I apologize.
23 COMMISSIONER KJELLANDER: For purposes of just
24 moving through this and not wrestling with the exact
25 numbers, why don't we just refer to them as Exhibit A and
CSB REPORTING
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720 BEACH (X)
ICL & SC
1 Exhibit Band apparently Exhibit C.
2 MR. HOWELL: Mr. Chairman, actually the
3 Commission's Amended Notice of Parties in this case
4 designates Avista's exhibits as starting at 1101.
5 COMMISSIONER KJELLANDER: So we have a
6 clarification. Thank you, Mr. Howell. We have 1101,
7 1102, and 1103.
8 (Avista Corporation Exhibit Nos. 1101 - 1103
9 were marked for identification.)
10 COMMISSIONER KJELLANDER: And that concluded
11 your cross-examination; is that correct?
12
13
MR. ANDREA: Yes, it does. Thank you.
COMMISSIONER KJELLANDER: Ms. Hogle, have
14 we given you a chance yet on this round?
15 MS. HOGLE: I think you may have, but in case
16 you didn't, Rocky Mountain Power does not have any cross.
17 Thank you.
18 COMMISSIONER KJELLANDER: Thank you. Let's
19 see, I can't recall if I let Staff have a round at this
20 yet. I did. Thanks for not taking a second bite of the
21 apple. Mr. Adams.
22
23
MR. ADAMS: No questions.
COMMISSIONER KJELLANDER: Thank you.
24 Mr. Richardson.
25 MR. RICHARDSON: No questions, Mr. Chair.
CSB REPORTING
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721 BEACH (X)
ICL & SC
1
2
3
COMMISSIONER KJELLANDER: Mr. Miller.
MR. MILLER: No, thank you.
COMMISSIONER KJELLANDER: Thank you.
4 Ms. Nunez.
5
6
7
8
9
MS. NUNEZ: No questions. Thank you.
COMMISSIONER KJELLANDER: Mr. Olsen.
MR. OLSEN: No questions.
COMMISSIONER KJELLANDER: Mr. Sanger.
MR. SANGER: We have no cross-examination for
10 Mr. Beach.
11
12 Hammond.
13
COMMISSIONER KJELLANDER: Thank you. Mr.
MR. HAMMOND: We have no cross-examination for
14 Mr. Beach either, Mr. Chairman.
15
16
COMMISSIONER KJELLANDER: Mr. Arkoosh.
MR. ARKOOSH: No questions. Thank you,
17 Mr. Chairman.
18
19
20
22
23
COMMISSIONER KJELLANDER: And Ms. Howland.
MS. HOWLAND: No questions.
COMMISSIONER KJELLANDER: Thank you very much.
MR. OTTO: I have three.
COMMISSIONER KJELLANDER: Oh, one moment.
21 Any redirect?
24 Anything from the Commission? Please proceed with
25 redirect.
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722 BEACH (X)
ICL & SC
1
2
3 BY MR. OTTO:
REDIRECT EXAMINATION
4 Q. Mr. Beach, Mr. Walker asked you about your
5 testimony regarding RTO's ISO's, RPS's. Was the
6 purpose -- what was the purpose of that section of your
7 testimony?
8 A. That section of my testimony responded to the
9 concerns that were raised about integrating a higher
10 penetration of renewable resources on Idaho Power's
11 system, and I included them to make sure the Commission
12 understands the developments that are occurring in the
13 West related to integrating higher penetrations of
14 renewable resources.
15 Q. Mr. Walker also asked you about how tax credits
16 play in this world, so let me give you a hypothetical.
17 Idaho Power's avoided costs are $65.00 a megawatt-hour.
18 How would the tax credit enable a QF developer to meet
19 that price?
20 MR. WALKER: Objection, that goes beyond the
21 scope. My question was related to whether the tax
22 credits affected the avoided cost price calculation that
23 they were paid in their contracts, not whether it
24 affected the way they can develop, the point being that
25 it goes to them and isn't in the avoided cost calculation
CSB REPORTING
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723 BEACH ( Di)
ICL & SC
1 at all, which he confirmed.
2
3
4 Q.
COMMISSIONER KJELLANDER: Okay.
MR. OTTO: Okay, I'll rephrase my redirect.
BY MR. OTTO: Actually, no. The last one is
5 just about RECs, that section of your testimony, is that
6 about the past or the future benefit of RECs?
7 A. It was primarily about the future benefit of
8 RECs, yes.
9
10
MR. OTTO: That's all.
COMMISSIONER KJELLANDER: Thank you, Mr. Otto,
11 and we appreciate your presence today. Thank you for
12 your testimony.
13
14
15
THE WITNESS: Thank you.
(The witness left the stand.)
MR. OTTO: I'd ask that Mr. Beach be excused
16 from the remainder of this hearing.
17 COMMISSIONER KJELLANDER: And without
18 objection, we will allow you to be excused. Again, thank
19 you for your presence.
20 Let's move to Ms. Nunez and the Snake River
21 Alliance.
22 MS. NUNEZ: Thank you. Snake River Alliance
23 would like to call Ken Miller, please.
24
25
CSB REPORTING
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724 BEACH (Di)
ICL & SC
1 KEN MILLER,
2 produced as a witness at the instance of the Snake River
3 Alliance, having been first duly sworn to tell the truth,
4 the whole truth, and nothing but the truth, was examined
5 and testified as follows:
6
7
8
9 BY MS. NUNEZ:
DIRECT EXAMINATION
10
11
12
Q.
A.
Q.
Thank you. Good afternoon, Mr. Miller.
Good afternoon, Ms. Nunez.
Could you please state your name and spell your
13 last name for the record?
14
15
A.
Q.
Ken Miller, M-i-1-1-e-r.
And by whom are you employed and in what
16 capacity?
17 A. Snake River Alliance as the energy program
18 director.
19 Q. Thank you. Are you the same Ken Miller who
20 filed direct testimony on the Snake River Alliance's
21 behalf on April 23rd, 2015?
22
23
A.
Q.
I am.
Do you have any additions or deletions to your
24 testimony?
25 A. I do not.
CSB REPORTING
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725 MILLER (Di)
Snake River Alliance
1 Q. If I were to ask you the same questions I asked
2 in the testimony, would your answers change?
3
4
A. They would not.
MS. NUNEZ: Thank you. I move that the
5 prefiled testimony of Mr. Ken Miller be spread across the
6 record as though read.
7 COMMISSIONER KJELLANDER: Without objection,
8 we'll spread the testimony across the record as if read.
9 (The following prefiled testimony of
10 Mr. Ken Miller is spread upon the record.)
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
CSB REPORTING
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726 MILLER (Di)
Snake River Alliance
1 Introduction and Background
2
3
Q.
A.
Please state your name and business address.
My name is Ken Miller and my business address
4 is 223 N. 6th Street, Boise, Idaho.
5
6
Q.
A.
By whom are you employed and in what capacity?
I am employed by the Snake River Alliance as
7 its Clean Energy Program Direct�r . •
8 Q. Please describe your educational background.
9 A. I graduated from Kansas State University in
10 1977 with bachelor degrees in journalism and in political
11 science. I have also attended multiple extended education
12 programs in the journalism and energy fields.
13 Q. Please describe your professional work
14 experience.
15 A. I worked as a journalist from 1977-2002 at
16 newspapers and news services in Oklahoma, Washington,
17 D.C., Kansas, Nevada, Hawaii and Idaho. My assignments
18 in my journalism career ranged lrom covering state, local
19 and federal government affairs, including Congress and
20 national politics. As the national energy and
21 environment correspondent for Gannett News Service in
22 Washington, D.C., my assignment included the U.S.
23 Environmental Protection Agency and the Department of
24 Energy.
25 Upon leaving journalism to work in the nonprofit
727 Miller - Direct 2
Snake River Alliance
1 community, I worked from 2002-2004 as the Education and
2 Outreach Coordinator and the Public Policy Coordinator
3 for the Winter Wildlands Allian!e in Boise and from
4 2004-2005 as a nonprofit grant writer for Idaho Public
5 Television and other entities. I was hired in 2005 as
6 the first Idaho Energy Advocate for the Seattle-based NW
7 Energy Coalition, and in May 2007 my position was shifted
8 from the Coalition to one of its Idaho members, the Snake
9 River Alliance, where I became the Alliance's first Clean
10 Energy Program director and where I am currently
11 employed. I have served as Idaho
12 I
13 l
14 I
15
16 I
17
18
19
20
21
22
23
24
25
728 Miller - Direct 2a
Snake River Alliance
1 Caucus Chair for the NW Energy Coalition and also served
2 on the NWEC Executive Board and as NWEC Board Chair from
3 2008-2010. In that capacity, I worked with Coalition
4 staff, Board members, and NWEC members in the Pacific
5 Northwest on state, regional, and national energy policy
6 issues in which the NW Energy Coalition and its members
7 are involved, including in Idaho. I have served on the
8 Idaho state wind, geothermal, a�d solar PV working f
9 groups; I participated in the dJvelopment of the 2007 and
10 2012 Idaho Energy Plans. In my capacity with the
11 Alliance and with the NW Energy Coalition, I regularly
12 attend energy conferences and workshops in Idaho, the
13 Northwest, and nationally.
14 Q. Do you have experience working with Idaho
15 electric utilities and before the Idaho Public Utilities
16 Commission?
17 A. Yes. I have served for several years on the
18 Idaho Power Integrated Resource�Plan Advisory Council and
I
19 the Idaho Power Magic Valley El�ctrical Plan Community
20 Action Committee and other Idaho Power planning
21 initiatives. As Clean Energy Program Director, I have
22 represented the Snake River Alliance in multiple electric
23 utility dockets before the Idaho PUC, and I have
24 participated in and provided comments to the Idaho PUC on
25 a variety of regulatory matters on behalf of the NW
729 Miller - Direct 3
Snake River Alliance
1 Energy Coalition and the Snake River Alliance for the
2 past 11 years, beginning in 2004. In addition, the Snake
3 River Alliance successfully par�nered with Idaho Power
4 and local planning entities in various jurisdictions,
5 such as McCall, Twin Falls, and Driggs, Idaho, to conduct
6 workshops on how local governments can improve their
7 energy efficiency and reduce their energy consumption.
8 I
9
10 I
11
12 I
13
14
15
16
17
18
19
20
21
22
23
24
25
730 Miller - Direct 3a
Snake River Alliance
1 Q. Do you have experience working with Idaho Power
2 with respect to the operation of its coal fleet?
3 A. Yes. In addition to my participation in the
4 past five Idaho Power Integrated Resource Plans, I have
5 met on multiple occasions with Idaho Power
6 representatives to discuss the company's coal plant
7 operations. I have also prepared multiple reports for
8 the Snake River Alliance, including its September 2011 .
9 report, "Idaho's Dangerous Dalliance with King Coal"; its
10 August 2012 report, "Kicking Idaho's Coal Habit, Charting
11 a Cleaner Energy Future"; and its September 2013 white
12 paper, "Putting Down a Coal Plant: Retiring a Utility
13 Asset", which we presented at the 2013 Western Energy
14 Policy Research Conference in September 2013.
15 Q. Have you participated in cases before the
16 Commission involving setting rates for electric
17 utilities?
18 A. Yes. I represented the Alliance in cases
19 IPC-E-11-08 (Application of Ida&o Power Company for
20 Authority to Increase Its Rates an Charges for Electric
21 Service in Idaho) and IPC-09-30 (Application of Idaho
22 Power Company For An Accounting Order to Amortize
23 Additional Accumulated Deferral Income Tax Credits and An
24 Order Approving a Rate Case Moratorium). The Alliance
25 participated in all discussions in both cases. We signed
731 Miller - Direct 4
Snake River Alliance
1 the settlement agreement in the first, and declined to
2 sign the agreement in the second. We also fully
3 litigated IPC-E-13-16 (Application of Idaho Power Company
4 for a Certificate of Public Con�enience for the
5 Investment in Selective Catalytic Reduction Controls on
6 Jim Bridger Units 3 and 4). I have also represented the
7 Alliance in Idaho Power Cost Adjustments, Efficiency
8 Tariff Rider Adjustments, the treatment of Renewable
9 Energy Credits and Sulfur Dioxide Emissions Allowances,
10 and many other dockets before the Commission.
11 I
12
13 I
14
15 I
16
17
18
19
20
21
22
23
24
25
732 Miller - Direct 4a
Snake River Alliance
1 Interest of Snake River Alliance
2
3
Q.
A.
On whose behalf are you testifying?
I am testifying on behalf of the Snake River
4 Alliance and its members, most of whom are customers of
5 Idaho Power.
6 Q. Please describe the Snake River Alliance's
7 interest in this case.
8 A. The Snake River Alliance was formed in 1979 to
9 monitor activities at what is now known as the U.S.
10 Department of Energy's Idaho Na(ional Laboratory. Ten
11 years ago, with my arrival at the Alliance, the Alliance
12 became Idaho's first public advocacy organization to
13 address energy issues on a full-time basis. As an
14 environmental advocate, the Alliance promotes clean
15 energy resources such as energy efficiency and other
16 demand-side resources and renewable energy development,
17 while also working to reduce utility reliance on
18 traditional fossil fuel supply-side resources. The
19 Alliance is interested in this case because of the
20 serious policy implications raised by the Petitioners'
21 requests and the consequences to environmental quality
22 and the growing renewable energy industry in Idaho,
23 should Petitioners prevail.
24 Testimony and Recommendations
25 Q. Please summarize your testimony in this case.
733 Miller - Direct 5
Snake River Alliance
1 A. The Alliance and its members are concerned
'I
2 that, should the Commission grant Idaho Power's
3 Application in IPC-E-15-01 and the subsequent
4 applications by PacifiCorp (PAC-E-15-03) and by Avista
5 Utilities (AVU-E-15-01), the future of utility-scale
6 solar power development in Idaho will be impaired and
7 that customers of each of these utilities may face
8 increased electricity rates in the future as a result.
9 I
10
11 I
12
13 I
14
15
16
17
18
19
20
21
22
23
24
25
734 Miller - Direct Sa
Snake River Alliance
1 Q. The U.S. Environmentai Protection Agency (EPA)
2 has proposed rules that may impact the ongoing operations
3 of existing coal-fired power plants. Can you briefly
4 explain?
5 A. The EPA coal plant rule, also known as the
6 "Clean Power Plan" and "Rule lll(d)" is still under
7 development and may be in draft form through the
8 remainder of this year. In the draft, EPA assigned
9 states greenhouse gas reduction targets, and assigned
10 Idaho a 30% reduction by 2030. While I do not know
11 precisely what the final rule will require, I do know
12 that the prospects of approval have, in some form,
13 already triggered the closures of dozens of coal plants
14 nationwide. I believe that the number of coal plants
15 scheduled for closure will increase as a direct result of
16 this rule, even before adjudication is complete. And, I
17 should note that the Alliance has discussed the
18 likelihood of more stringent federal regulations for coal
19 plants for many years and is not surprised by the
20 proposed rule.
21 Q. Could Rule lll(d) affect the parties in this
22 case?
23 A. Yes. Rule lll(d) 's impacts on Idaho utilities'
24 portfolios, while not certain, are predictable. We are
25 fairly certain that these near-future mandates will
735 Miller - Direct 6
Snake River Alliance
1 require Idaho utilities to burn less coal or suffer
2 regulatory penalties. The needs analysis espoused by the
3 Petitioners could very well change significantly as
4 regulations increase the restrictions on coal-fired power
5 plants and the expenses associated with these
6 increasingly risky investments.
7
8
Q.
A.
How might that affect customers?
In short, as long as our utilities burn coal,
9 customers will be on the hook for the inevitable
10 associated regulatory costs and increased rates.
11 Q. Are you aware of any actions being taken by the
12 Petitioners to address these risks?
13 A. My understanding is that Petitioners are
14 modeling a variety of compliance scenarios relating to
15 potential Rule lll(d) changes. The Alliance encourages
16 continued analysis of portfolios that
17 I
18
19 I
20
21 I
22
23
24
25
736 Miller - Direct 6a
Snake River Alliance
1 model reduced and eliminated coal burning and discourages
2 actions that would serve to stymie accelerated
3 development and integration of renewable energy resources
4 such as the PURPA projects at issue in this case.
5 Q. Has the Commission expressed concern about the
6 impacts of coal on the environment and human health?
7 A. Yes. In IPC-E-13-16, the Commission granted in
8 part and denied in part Idaho Power's application for
9 approval of a Certificate of Public Convenience and
10 Necessity regarding its investment in Selective Catalytic
11 Reduction controls in Jim Bridger Units 3 and 4. While
12 the Alliance did not prevail on all of its arguments, the
13 Commission did acknowledge that "[t]he detrimental
14 effects of long-term coal use on human health, the
15 climate, wildlife, land, and water are well-documented."
16 Order No. 32929 at 10.
17 Q. Has the Commission expressed concern about the
18 impacts of future environmental regulations on Idaho's
19 coal fleet?
20 A. Yes. Also in IPC-E-13-16, the Commission
21 stated, "we recognize that the future of coal-fired
22 generation in the United States is uncertain at best."
23 Id. at 11. The Commission addressed the economic
24 consequences of this uncertainty: "Additional future
25 environmental regulations are likely. It is not
737 Miller - Direct 7
Snake River Alliance
1 inconceivable that, during the installation of the SCRs,
2 a tipping point could be reached making them uneconomic."
3 Id. In a clarifying order, the Commission restated its
4 concern about "the possibility of more stringent
5 environmental regulations that could make the Bridger
6 upgrades, and thus the Company's investment, uneconomic.''
7 Order No. 32996 at 3.
8 It is important to note that the SCR upgrades at
9 Bridger were not intended to reduce greenhouse gas
10 emissions, which will be required if and when proposed
11 Rule lll(d), or something like it, is implemented.
12 I
13
14 I
15
16 I
17
18
19
20
21
22
23
24
25
738 Miller - Direct 7a
Snake River Alliance
1 Q. You stated that the Alliance did not prevail on
2 all of its arguments in IPC-E-13-16. Can you elaborate?
3 A. In that case, the Commission held, based upon
4 short-term reliability concerns in existence at the time,
5 that upgrades to the units were in the public interest
6 but did not warrant ratemaking treatment. Order No.
7 32929. The Alliance and others argued about the risk of
8 future environmental regulations and disagreed that the
9 upgrades were in the public interest. I believe that
10 much progress has been made during the 2015 IRP process
11 towards addressing those then-stated concerns.
12 Q. Do you have an opinion about Petitioners'
13 assertions that they lack a "need" for the types of PURPA
14 projects at issue in this case?
15 A. Yes. My main concern is how "need" is defined
16 and in what context and time frame need is analyzed. The
17 Alliance and our members, for instance, see a strong need
18 to accelerate the reduction of toxic and damaging air
19 pollution, including greenhouse gases, caused by mining
20 for, transporting, and burning coal. The Alliance and
21 our members also see a strong need to strengthen Idaho's
22 economy with increased opportunities for entrepreneurs
23 and more jobs in the growing clean energy sector. The
24 increase in proposed solar developments is, from our
25 perspective, an opportunity to meet these needs and one
739 Miller - Direct 8
Snake River Alliance
1 that should be embraced. Idaho is nowhere near having
2 "too much" renewable energy. We also believe that the
3 challenges relating to integration are surmountable and
4 support greater efforts by the utilities to remove the
5 barriers to renewable energy as opposed to efforts that
6 inhibit development of renewable energy.
7 I
8
9 I
10
11 I
12
13
14
15
16
17
18
19
20
21
22
23
24
25
740 Miller - Direct Ba
Snake River Alliance
1 Q. Do you believe the requests by the utilities in
2 this case comport with the goals set forth in the 2012
3 Idaho Energy Plan, which was approved by the Idaho
4 Legislature and which currently serves as the primary
5 energy policy of the state of Idaho?
6 A. No. The Idaho Legislature adopted an Energy
7 Plan in 2012 which remains in effect today - that
8 states, when seeking to meet new electricity demands in
9 Idaho, we should turn first to energy efficiency and
10 other "demand-side" resources normally considered to be
11 on the customer's side of the meter, then to renewable
12 resources such as solar power and other resources we are
13 discussing in this case. Only then, and only if
14 absolutely necessary, should we turn to resources such as
15 fossil fuel generation like natural gas or coal-fired
16 generation. In my opinion, Petitioners have not
17 established that it is "absolutely necessary" to
18 prioritize fossil fuel generation over renewable sources
19 of generation for our future energy demands.
20 Q. As noted in Idaho Power's Petition, the
21 Commission ordered a PURPA contract length of 20 years in
22 2002, which remains in effect to date. What was the
23 stated reason for that change?
24 A. In Order No. 29029, the final order in
25 GNR-E-02-01, the Commission stated,
741 Miller - Direct 9
Snake River Alliance
1
2
3
4
This Commission also cannot ignore the fact that
since reducing the eligibility threshold to 1 MW and
contract term to 5 years, there has been only one
PURPA contract signed in Idaho. A longer contract,
5 we find, better coincides with the amortization
6 period or planned resource life of the renewable or
7 cogeneration resources being offered, better
8 reflects the amortization period of generation
9 projects constructed by the utilities themselves and
10 will coincidently provide a revenue stream that will
11 facilitate the financing of QF projects.
12 Order No. 29029 (page number uncertain in online
13 database).
14 I
15
16 I
17
18 I
19
20
21
22
23
24
25
742 Miller - Direct 9a
Snake River Alliance
1
2
Q.
A.
Do you think that logic still applies today?
Yes, yet I must defer to QF developers for
3 analysis of exactly how short contract lengths affect
4 their projects based upon their individual circumstances.
5 Q. How do you think this application, if approved,
6 will affect the future of solar power in Idaho?
7 A. I think this application, if approved, will
8 cause further migration of solar developers away from
9 Idaho, as the proposed reduction in contract terms to two
10 years is tantamount to a freeze on future solar PURPA
11 projects. I know that some solar generators are
12 considering or have already left our state, and multiple
13 cases involving the state of solar power development in
14 Idaho have demonstrated an ongoing migration of solar
15 power developers that have come to Idaho but then taken
16 their jobs and dollars to more welcoming jurisdictions,
17 most of which are directly across our state boundaries.
18 This case is not just crucial to the future of solar
19 generation in Idaho, it is enormously important as we as
20 a state determine where our energy will come from, who
21 will produce it, and who will pay for it. The use of
22 coal as a supply side generation resource is no longer
23 practical and should be measured alongside the costs,
24 benefits, and risks of other supply side and demand side
25 resources.
743 Miller - Direct 10
Snake River Alliance
1
2
3 I
4
s I
6
7 I
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
Q.
A.
Does this conclude your testimony?
Yes it does.
744 Miller - Direct lOa
Snake River Alliance
1 (The following proceedings were had in
2 open hearing.)
3 MS. NUNEZ: Thank you, and now Mr. Miller is
4 open for cross-examination.
5
6 Staff.
7
8
9
10
COMMISSIONER KJELLANDER: Let's begin with PUC
MR. HOWELL: Thank you, Mr. Chairman.
CROSS-EXAMINATION
11 BY MR. HOWELL:
12 Q. Mr. Miller, if you could turn to page 9 of your
13 testimony
14
15
A.
Q.
I'm there.
-- you're talking at the top of page 9 about
16 the 2012 Idaho state energy plan and you say on line 5
17 that that energy plan states when seeking to meet new
18 electric demand in Idaho that the state should turn first
19 to energy efficiency and other demand side resources, and
20 then only then on line 8 should we turn to resources, so
21 when QFs approach Idaho Power and want Idaho Power to
22 purchase their output, Idaho Power in and of its own
23 volition isn't in the process of acquiring resources, is
24 it?
25 A. No, I don't believe so.
CSB REPORTING
[phone]
745 MILLER (X)
Snake River Alliance
1 Q. And doesn't that -- the 2012 state energy plan
2 in policy 3 says after it says which you point out, give
3 priority to cost-effective conservation, energy
4 efficiency, and demand response, that the plan continues
5 to state that "recognizing that these alone will not
6 fulfill Idaho's growing energy requirements," doesn't the
7 plan go on to state that?
8 A. Yeah, I believe it does. I think it reflects
9 the same language that was in the 2007 energy plan.
10 Q. So there's nothing that says that you don't
11 move to fossil fuel generation like natural gas when it's
12 only absolutely necessary, does it?
13 A. For new generation and it depends on how you
14 want to define "absolutely," Mr. Howell, but for new
15 generation, I think that was the intent. I was at both
16 of them when they were written as was Idaho Power.
17
18
19
Q.
A.
Q.
How do you define "absolutely necessary"?
Without other options for the most part.
Doesn't the state energy plan actually say that
20 such fossil resources play a role in addition to the
21 conventional resources or that the renewable resources
22 will play a role in addition to conventional resources in
23 providing for Idaho's energy need, so doesn't it require
24 a balance?
25 A. I think it does require a balance, but I think
CSB REPORTING
[phone]
746 MILLER (X)
Snake River Alliance
1 what they were referring to, I think it was stipulated
2 during the development of the 2012 plan that we would not
3 be building additional coal plants. Gas was another
4 story.
5
6
Q.
A.
And are there any coal plants in Idaho?
Well, it depends on how you want to define
7 "coal plants." There are no --
8
9
Q.
A.
Is there any physical coal plant in Idaho?
There are two Amalgamated sugar factories that
10 burn a significant amount of coal, but there are no coal
11 plants within the state that are serving Idaho load if
12 that's what you're referring to.
13 Q. And are those two Amalgamated sugar plants,
14 they're not part of the proposed clean coal Section
15 lll(d) requirement, are they?
16 A. That's a good question. I think to the extent
17 that we're talking about overall emissions reductions, I
18 don't think that those could be left out of the picture,
19 but I think that it is the coal that's being burned
20 within the state and also that's being imported into the
21 state, but whether Amalgamated, those two plants are
22 directly -- would be directly impacted by lll(d) we don't
23 know yet because it's not been made final.
24 Q. Right; so at this point it's merely
25 speculation?
CSB REPORTING
[phone]
747 MILLER (X)
Snake River Alliance
1 A. It is merely speculation. As to whether the
2 plants would be included?
3
4
5
6
Q.
A.
Right.
Yeah, it would be speculation.
MR. HOWELL: No further questions.
COMMISSIONER KJELLANDER: Thank you. Mr.
7 Walker.
8
9
10
11
MR. WALKER: Thank you, Mr. Chairman.
CROSS-EXAMINATION
12 BY MR. WALKER:
13 Mr. Miller, you were present here when your
14 attorney presented Snake River Exhibit 501, this
15 Environmental Rules for Hydropower that I'm showing you?
16
17
18
19
A.
Q.
A.
Q.
I was here, Mr. Walker.
You're familiar with this report?
I am very familiar with it.
And I believe the questions that your attorney
20 referenced had something to do with the chart in here and
21 referred to California with a 30 megawatt capacity limit
22 on hydropower qualifications and RPS; does that sound
23 familiar?
24 A. It sounds familiar. I think it's also
25 reflected in Exhibit 5, I believe, the Company Exhibit 5,
CSB REPORTING
[phone]
748 MILLER (X)
Snake River Alliance
1 the chart I think you're referring to --
2
3
Q.
A.
Uh-huh.
-- is also well, it was what we used in
4 preparing our questions about the magnitude of hydropower
5 that is coming from each of these individual states.
6 Q. So in those questions we're referring to
7 Mr. Allphin's exhibit that included the Company's,
8 varying levels of the Company's, hydropower in comparing
9 to all the surrounding state RPS standards; is that --
10 A. Not all of them, because Utah has an RPG and so
11 not all of the states have
12
13
Q.
A.
Well, California
California, Nevada, Oregon, Washington,
14 Montana.
15
16
17
Q.
A.
Q.
Okay; so most of them?
Most of them.
All right, and so let me ask you, do you
18 consider hydropower to be renewable energy?
19 A. Well, I consider it to be carbon free, but I'm
20 unaware of any RPS around the country that does include
21 large scale hydro, because we distinguish between large
22 scale hydro and canal drops and other smaller forms of
23 hydropower, but there's a reason why when you look, Mr.
24 Walker, at these other states why they cap the amount of
25 hydropower that's eligible for RPS consideration.
CSB REPORTING
[phone]
749 MILLER (X)
Snake River Alliance
1 Q. Okay, well, let's look at some of the other
2 stuff in that chart, then, so is it -- would you agree
3 with me that these capacity limits, I don't know,
4 there's, what, one, two, three, four, five, I don't know,
5 there's 10 pages or so that all have varying capacity
6 lengths; is that correct?
7 A. If you're referring to this chart that's in the
8 back of
9
10
11
Q.
A.
Q.
Yeah, it's in this thing right here --
Right.
-- Exhibit 501, and so if you go down through
12 all those pages in Snake River Alliance Exhibit 501,
13 isn't it true that there are some that have no limit?
14 A. There are, and I think actually there's even
15 one in our region that has no limit, but the average if
16 you read the narrative in the report, the average is 30
17 megawatts. There's one that's 10 to 40. There's one
18 that's a little bit higher than that, but the average, in
19 fact, it's a national average, for what hydropower is
20 eligible for an RPS consideration is 30 megawatts.
21 Q. Isn't it true there are some that just say
22 none?
23
24
25
A.
Q.
A.
Uh-huh.
And some are at 100; is that correct?
I think there's one that's at 100, yeah, but
CSB REPORTING
[phone]
750 MILLER (X)
Snake River Alliance
3 that can be whatever it's defined to be in an RPS?
1 there are some that do say none, you're correct.
5 through the legislature or whether it's through, you
Well, when the states pass an RPS, whether it's
So some are at three and isn't it true that
A.
Q.
4
2
6 know, a regulatory-type thing, the states decide for
7 themselves what qualifies for RPS consideration.
8 Q. Or possibly some type of national RPS that may
9 decide --
10 A. Well, it could and that has come up and it also
11 has come up whether all hydro, whether gasification, coal
12 gasification, and whether even nuclear should be eligible
13 for an RPS, a national RPS, but as we sit here now, there
14 is no serious discussion in Congress about a national
15 RPS.
16 Q. And couldn't that vary based on, say, whether
17 it's a run-of-river or an impoundment with a reservoir?
18 A. Sure. Are you talking about the capacity of a
19 project or are you talking about just how it's
20 configured?
21 Q. Well, I'm talking about why you guys were
22 questioning us on this maximum capacity and whether hydro
23 is renewable, carbon free and whether it was fair for
24 Idaho Power to make that chart including its hydro as
25 renewable, carbon free.
CSB REPORTING
(208} 890-5198
751 MILLER (X)
Snake River Alliance
1 A. Whether it's renewable or carbon free, as I
2 said earlier, it is carbon free in our view. Renewable,
3 we have other issues that are mostly environmental issues
4 and that's why most of the other states in the region do
5 not consider it for an RPS. The point of the exhibit as
6 it related to Exhibit 5 from the Company was to show that
7 when you look at it, Idaho looks like it's off the charts
8 compared to our neighbors, when we know that most of our
9 neighbors in the region have a lot of hydropower on their
10 system. They're just not counting it for their RPS's.
11 Q. So it really depends, then, on how it's defined
12 in an RPS; isn't that true?
13
14
16
18
A.
Q.
A.
Q.
Right, but we don't have an RPS.
And we don't know how Idaho Power's would be
No, all I'm saying is it's far higher than what
Well, but it could be all of it or none of it
15 defined because we don't have a state RPS, do we?
17 any other state in the region uses.
19 or anywhere in between; isn't that correct?
20 A. I'm not sure what you're referring to about
21 "all of it."
22 Q. Well, if an RPS is written for the State of
23 Idaho in such a manner that all of Idaho Power's hydro
24 generation meets the definition of renewable energy under
25 that RPS, then all of it would be included in that RPS;
CSB REPORTING
[phone]
752 MILLER (X)
Snake River Alliance
1 is that not true?
2 A. If such an RPS was written in the State of
3 Idaho, but I've never heard that there was a desire to do
4 an RPS in the state.
5 Q. Well, sure; so that's something we just don't
6 know today; is that correct?
7 A. Whether to have an RPS in the state? No, we
8 don't know, but we can be reasonably confident that we're
9 not. I mean, the Commission is opposed to it, the
10 legislature is opposed to it, the Governor is opposed to
11 it. I don't see how realistically you're going to try to
12 move an RPS in the State of Idaho.
13 Q. And whether or not there's an RPS with some
14 definition of something that qualifies or doesn't
15 qualify, it still doesn't change the fact that Idaho
16 Power has a substantial amount of hydro generation on its
17 system, does it?
18 A. Yeah, I mean, the Hells Canyon complex is more
19 than 1,100 megawatts, I consider that significant.
20
21
22 Ms. Hogle.
23
MR. WALKER: No further questions.
COMMISSIONER KJELLANDER: Thank you.
MS. HOGLE: PacifiCorp has no questions. Thank
24 you, Your Honor.
25 COMMISSIONER KJELLANDER: Thank you. Avista.
CSB REPORTING
[phone]
753 MILLER (X)
Snake River Alliance
1
2 you.
3
MR. ANDREA: Avista has no questions. Thank
COMMISSIONER KJELLANDER: While we're in the
4 back row, let's see, Mr. Hammond.
5
6
7
8
9
10
11
12
13
MR. HAMMOND: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Mr. Sanger.
MR. SANGER: No questions. Thank you.
COMMISSIONER KJELLANDER: Mr. Olsen.
MR. OLSEN: Yes, a few questions.
COMMISSIONER KJELLANDER: Please proceed.
CROSS-EXAMINATION
14 BY MS. OLSEN:
15 Q. Mr. Miller, I'd like you to turn to page 6 of
16 your direct testimony here.
17
18
A.
Q.
I'm there.
Beginning on line 1 through 17, you talk about
19 the uncertainty behind the Rule lll(d) proposed
20 regulations; is that correct?
21
22 to.
23
A.
Q.
Yes, that's what that section is referring
All right, and a lot of the language in there,
24 you know, line 1, it may impact; line 12, could; line 13,
25 while not certain; or line 14, fairly certain that these
CSB REPORTING
[phone]
754 MILLER (X)
Snake River Alliance
4 fact here?
21 think we are, but in terms of the inevitable associated
1 near-future mandates, et cetera, is it safe to say that
Further there you start on a question and
Well, first, I take issue with your
Well, two things. A lot of this case is based
Q.
A.
A. 5
6 on projections and speculation, first of all, but second
7 of all, whether I'm hoping that lll(d) will turn out one
3 may bring? Your testimony relies on speculation and not
8 way or another is really not relevant. That's an
9 emotional response and it's what our expectations are. I
2 you have a strong belief or hope as to what the future
11 it's evolving and it's not that we have an emotional
10 mean, you know, anyone who follows this issue can see how
13 rule.
12 attachment to getting a strict lll(d) released as a final
15 answer on line 18, 18 through 20, you talk about --
16 speculate how it might affect the customers there, and
17 what type of costs are associated with this proposed
18 regulation that you can foresee?
20 characterization that we're speculating, because I don't
14
19
22 regulatory cost and increased rates, no matter what
23 happens with lll(d), we've already had -- although the
24 Supreme Court did attack part of it, I think it was just
25 today, the mercury rule, but there's no question but that
CSB REPORTING
[phone]
755 MILLER (X)
Snake River Alliance
1 the regulatory environment for coal-fired power plants is
2 changing. It's one of the reasons why even though the
3 MATS rule was -- part of it was ruled out and regardless
4 of whatever happens to lll(d}, it's one of the reasons
5 why we're seeing coal plants retire all around the
6 country, because of the expectation that maintaining
7 their operation will add additional costs. Look no
8 further than Bridger 1 and 2 or 3 and 4. You know,
9 installing very expensive pollution control equipment,
10 that does affect ratepayers. They're the ones who are
11 paying for it.
12 Q. Sure, isn't it -- I guess the direct result is
13 the increased costs associated with running coal plants
14 and with meeting the challenges of the regulation; isn't
15 that the bottom line?
16 A. Well, yeah, mostly the regulatory compliance.
17 You know, burning coal has historically been relatively
18 inexpensive, in fact, very inexpensive, but that was all
19 done in an environment where we did not have any
20 regulatory controls over greenhouse emissions or mercury.
21 Those are relatively new creatures over the past five
22 years.
23 Q. So with the retirement of coal plants that you
24 appear to follow very closely and whatnot, what's the
25 alternative once the coal plants go away?
CSB REPORTING
[phone]
756 MILLER (X}
Snake River Alliance
1 A. Well, there are several alternatives. I think
2 we heard one of them this morning from Ms. Grow. You
3 know, the Company's 2015 IRP is contemplating retirement
4 of coal plants and replacing it with, in this case,
5 transmission and quite probably with some solar, but it
6 depends where you are, Mr. Olsen, regionally and where
7 your power is corning from what's available to you, but
8 Boardman to Hemingway is in our view, and I think in the
9 view of Idaho Power, going to be the primary vehicle that
10 will get us to retire North Valrny 1 and 2, and I think I
11 heard 2020, but I'm not so sure that is the right number.
12 Q. Well, as you can see, the IRP can change
13 dramatically from year to year.
14
15
A.
Q.
Every other year.
Okay, and so while you might have the stated
16 facts, I think some of the uncertainty that we're
17 addressing in this case is how to price these
18 IRP-qualified PURPA projects, but one last question here,
19 why would you think it would be appropriate to add more
20 renewables now when we don't need them and have our rates
21 go up now rather than wait to see what the needs are
22 actually at the time as the IRP process progresses?
23 A. Well, once again, I think it's how you're going
24 to define need. You know, we have environmental concerns
25 that we're worried about. If we're going to start
CSB REPORTING
[phone]
757 MILLER (X)
Snake River Alliance
1 retiring two coal units within the next 10 years, then
2 there's going to be every need for as much clean energy
3 as we can develop, and the price of it is, as you know,
4 falling steadily and it really is more competitive, in
5 our view, than coal-fired generation is.
6
7 questions.
8
MS. OLSEN: Thank you, Mr. Chair. No further
COMMISSIONER KJELLANDER: Thank you, and
9 Mr. Miller, while the mic is still red hot, do you have
10 any cross?
11
12
MR. MILLER: I'll let it cool off.
COMMISSIONER KJELLANDER: Fair enough. Mr.
13 Richardson.
14 MR. RICHARDSON: I have no questions,
15 Mr. Chairman.
16 COMMISSIONER KJELLANDER: Thank you, Mr.
17 Richardson. Mr. Adams.
18
19
MR. ADAMS: No questions. Thank you.
COMMISSIONER KJELLANDER: Thank you.
20 Mr. Arkoosh.
21 MR. ARKOOSH: No questions. Thank you,
22 Mr. Chairman.
23 COMMISSIONER KJELLANDER: Thank you, and
24 Ms. Howland.
25 MS. HOWLAND: No questions.
CSB REPORTING
[phone]
758 MILLER (X)
Snake River Alliance
1 COMMISSIONER KJELLANDER: Thank you, and I
2 think that takes us to Mr. Otto.
3
4
MR. OTTO: No questions, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Did I
5 miss anyone? Oh, my colleague, you were next.
6
7
COMMISSIONER RAPER: I have none.
COMMISSIONER KJELLANDER: No questions from the
8 Commission, so that takes us to any redirect.
9 MS. NUNEZ: I don't have any redirect,
10 Commissioner.
11 COMMISSIONER KJELLANDER: Great, thank you.
12 Thank you very much, Mr. Miller.
13
14
15
THE WITNESS: Thank you.
(The witness left the stand.)
COMMISSIONER KJELLANDER: As I look at the
16 clock, I notice that we are about 12 minutes before 5:00
17 and I recognize that outside it's probably over 100
18 degrees and you all missed your chance to get out and get
19 some really great sun today, so I'm thinking that maybe
20 what we ought to do is turn you loose so you can capture
21 that last five hours of penetrating heat.
22 That said, we are down to our last three
23 witnesses, two from the IPUC and then Mr. Reading with
24 Clearwater Paper/Simplot. Does anybody have a preference
25 on how we want to proceed tomorrow? Do you mind going
CSB REPORTING
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1 first in the morning?
2 MR. RICHARDSON: We certainly don't mind going
3 first in the morning, whatever your preference is, Mr.
4 Chairman.
5 COMMISSIONER KJELLANDER: Why don't we plan on
6 that and then we'll move to Staff's witnesses, and as far
7 as the start time, I know you're going to hate me for
8 this, but I'd like to get cracking around 9:00 o'clock
9 tomorrow morning and that should give everybody a chance
10 to get here and hopefully, we can target, perhaps, a noon
11 end to this or close thereto.
12 Now, I mentioned at the public hearing the
13 other night, and we do have a telephonic hearing tomorrow
14 night, that I wasn't very fired up about the need to have
15 briefs since this has been a pretty robust and thorough
16 review; however, I don't want to put anything relating to
17 a chilling effect on someone's desire to argue or request
18 briefs. In lieu of that, however, though, we have a long
19 tradition at the Commission of allowing any closing
20 statements, so to the extent someone is just enamored
21 about providing more information to us, we certainly
22 would allow for closing statements from the parties if
23 that might ease any tension that they have that the
24 Commission hasn't been able to follow the granular
25 details or that we need to be briefed additionally.
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1 My desire to do that, if it sounds like I'm
2 pushing forward rather quickly, it's because many of you
3 may well know that we have a multitude of rate cases that
4 have been filed, and I would like to move through the
5 deliberative process on this and get an Order out as
6 quickly as possible so that we don't have these things
7 stacking up and overlapping, so that's my intent is to
8 try to get an Order out as quickly as possible.
9 It's also my desire to also let you know that
10 any requests for intervention, depending on when we wrap
11 this piece up, please be in within 10 days of us closing
12 this aspect of the hearing. Again, I'm not trying to
13 rush anybody too seriously, but I would like to try to
14 get this case as close as possible to try to target the
15 end of the month to get an Order out, again, so that we
16 don't have overlap for some of the future rate cases, of
17 which I know many of you will be parties to.
18 I'm sorry, it's so hot outside I forgot what
19 month it was, but I do know my gender. Mr. Miller has
20 reminded me of that on more than one occasion, so with
21 that, are there any other matters that need to come
22 before us this evening procedurally before we break? If
23 not, then, we'll see you all tomorrow morning at 9:00
24 o'clock, and thank you very much for your
25 patience and endurance.
(The hearing recessed at 4:55 p.m.)
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