20150715Hearing Transcript Volume II.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: r-> -1 c::, ·- CJ\ =to '- PLACE: Commission Hearing Room -) ... c::: rn-- r- 472 West Washington Street =: �)
Boise, Idaho ("')_ LJ1 0 :::: ;r:w :::t:
DATE: June 29, 2015 a
Cl ..
17'" c, N
VOLUME II - Pages 87 - 283
ORIGINAL CSB REPORTING
Certified Shorthand Reporters
Post Office Box 9774
Boise, Idaho 83707
csbreporting@heri tagewi fi .com
Ph: 208-890-5 l 98 Fax: l-888-623-6899
Reporter:
Constance Bucy,
CSR
1
2
3
4
5
For the Staff:
A P P E A R A N C E S
Donald Howell, Esq.
and Daphne Huang, Esq.
Deputy Attorneys General
472 West Washington Street
Boise, Idaho 83720-0074
6
7
8
For Idaho Power Company: Donovan E. Walker, Esq.
Idaho Power Company
Post Office Box 70
Boise, Idaho 83707-0070
For Rocky Mountain Power: Yvonne R. Hogle, Esq.
9 Rocky Mountain Power
201 S. Main Street, Ste. 2400
10 Salt Lake City, Utah 84111
11 For Avista Corporation: Michael Andrea, Esq.
Avista Corporation
12 Post Office Box 3727
Spokane Washington 99220
13
14
15
16
17
18
For Clearwater Paper:
For Intermountain Energy
Partners:
RICHARDSON ADAMS PLLC
by Peter J. Richardson, Esq.
515 North 27th Street
Boise, Idaho 83702
McDEVITT & MILLER
by Dean J. Miller, Esq.
420 West Bannock Street
Boise, Idaho 83702
For J.R. Simplot Company: RICHARDSON ADAMS PLLC
19 by Gregory M. Adams, Esq.
515 North 27th Street
20 Boise, Idaho 83702
21
22
23
24
25
For Idaho Irrigation
Pumpers:
CSB REPORTING
[phone]
RACINE OLSON NYE BUDGE
& BAILEY
by Eric L. Olsen, Esq.
Post Office Box 1391
Pocatello, Idaho 83204-1391
APPEARANCES
1
2
APPEARANCES (Continued)
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
For Idaho Conservation
League & Sierra Club:
For Snake River
Alliance:
For Renewable Energy
Coalition:
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 1�31
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. Howland, Esq.
377 S. Nevada Street
Carson City, Nevada 89703
ARKOOSH LAW OFFICES
by C. Tom Arkoosh, Esq.
Post Office Box 2900
Boise, Idaho 83701
FISHER PUSCH LLP
by John R. Hammond, Jr., Esq.
Post Office Box 1308
Boise, Idaho 83701
APPEARANCES
1
2
3
4
5
6
7
8
9
10
11
12
13
14
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16
17
18
19
20
21
22
23
24
25
I N D E X
WITNESS EXAMINATION BY PAGE
Lisa A. Grow Mr. Walker (Direct) 103
(Idaho Power) Prefiled Direct Testimony 105
Mr. Adams (Cross) 136
Mr. Otto (Cross) 142
Mr. Hammond (Cross) 149
Ms. Nunez (Cross) 157
Mr. Miller (Cross) 161
Commissioner Raper 164
Commissioner Kjellander 166
Randy Allphin Mr. Walker (Direct) 171
(Idaho Power) Prefiled Direct Testimony 175
Prefiled Rebuttal Testimony 194
Ms. Nunez (Cross) 224
Mr. Miller (Cross) 227
Mr. Otto (Cross) 250
Mr. Adams (Cross) 254
CSB REPORTING
[phone]
INDEX
1
2
3 NUMBER
E X H I B I T S
DESCRIPTION PAGE
4 FOR IDAHO POWER COMPANY:
5
6
7
1. PURPA Projects Under Contract
& Proposed
2. Renewable Energy Contracts List
Premarked
Premarked
3. Proposed PURPA Solar - Premarked
8 As of 1/20/15
9 4. Cogeneration and Small Power Premarked
Production, Contract Obligations -
10 As of 1/9/15
11 5. Idaho Power Compared to Regional Premarked
Renewable Portfolio Standard/
12 Renewable Portfolio Goal
13 6. Estimated Load, Must run Premarked
Resources, Utility PPAs and
14 PURPA for 2016 and 2017
15 7. Idaho Power PURPA Payments Premarked
16 8. Approved Net Power Supply Expense Premarked
in Base Rates (Normalized)
17
9. PURPA Solar projects under Premarked
18 contract - As of 1/20/15
19 10. Average PURPA Price vs. MidC Index Premarked
20 11. PURPA Solar projects under Premarked
contract - As of 4/22/15
21
22
23 FOR J.R. SIMPLOT COMPANY:
24
25
206. Request for & Response to
Production No. 22
Admitted 258
CSB REPORTING EXHIBITS
Wilder, Idaho 83676
1
2
3 NUMBER
EXHIBITS (Continued)
DESCRIPTION PAGE
1
4 FOR J.R. SIMPLOT COMPANY: (Continued)
5
6
7
8
207. Request for & Response to
Production No. 11
208. IPCo Avoided Cost Rates for
Wind Projects, 6/1/15
Admitted
Admitted
261
274
9 FOR ICL/SIERRA CLUB:
10 305. Excerpt from IPUC Order No. 33159, Identified 147
pages 1 & 7
11
12
13 FOR SNAKE RIVER ALLIANCE:
14 501. Environmental Rules for Hydropower Identified 224
in State RPS's
15
16
FOR ECOPLEXUS:
17
18
19
20
21
22
23
24
25
1501. Draft Integrated Resource Plan for Admitted
2015 for Idaho Power Company
152
CSB REPORTING EXHIBITS
Wilder, Idaho 83676
1
2
3
4
BOISE, IDAHO, MONDAY, JUNE 29, 2015, 9:30 A. M.
COMMISSIONER KJELLANDER: Well, good morning.
5 This is the time and place for a hearing in Case Nos.
6 IPC-E-15-01, AVU-E-15-01, and PAC-E-15-03, also referred
7 to as in the matter of Idaho Power Company's, Avista
8 Corporation's, and Rocky Mountain Power Company's
9 petition to modify terms and conditions of PURPA purchase
10 agreements.
11 Good morning, my name is Paul Kjellander. I'll
12 be the Chairman of today's proceedings. To my left is
13 Commissioner Kristine Raper. To my right we normally
14 have Mack Redford, he is excused, and for those of you
15 who need more details about Mack's status, you could
16 contact our public information officer. Additionally,
17 Mack will have access to the transcript of this case and
18 any of the public hearings that we have and that will be
19 made available to him prior to any deliberation the
20 Commission undertakes.
21 So with that, then, today we are prepared to
22 move directly to the appearances of the parties and let's
23 begin with the Applicants. Idaho Power.
24 MR. WALKER: Thank you, Mr. Chairman. Donovan
25 E. Walker representing Idaho Power Company.
CSB REPORTING
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87 COLLOQUY
1 COMMISSIONER KJELLANDER: Thank you, and
2 PacifiCorp.
3 MS. HOGLE: Good morning, Chairman Kjellander
4 and Commissioner Raper, my name is Yvonne Hogle and I'm
5 here on behalf of the Rocky Mountain Power, and with me
6 here are Mr. Paul Clements to my left, who is the
7 director of commercial services, and behind me is Mr.
8 Brian Dickman, who is the director of net power costs.
9 Thank you.
10 COMMISSIONER KJELLANDER: Thank you. Avista
11 Corporation.
12 MR. ANDREA: Good morning, Mr. Chairman,
13 Commissioner Raper, Mike Andrea for Avista, and I've got
14 Clint Kalich with me this morning.
15 COMMISSIONER KJELLANDER: I apologize for
16 looking around, I heard a voice, didn't see a face.
17 Someone of your size shouldn't be able to hide behind
18 some of our smaller Staff members in front of you. Let's
19 move now to the Staff from the Idaho Public Utilities
20 Commission.
21 MR. HOWELL: Good morning, Mr. Chairman. My
22 name is Don Howell and with me is my colleague Daphne
23 Huang and we are Deputy Attorneys General representing
24 the Commission Staff.
25 COMMISSIONER KJELLANDER: J.R. Simplot Company
CSB REPORTING
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88 COLLOQUY
1 and Clearwater Paper Corporation.
2 MR. ADAMS: Good morning, Mr. Chairman. My
3 name is Greg Adams. I'll be representing the J.R.
4 Simplot Company. Peter Richardson to my right will be
5 representing Clearwater Paper and we have with us here
6 Dr. Don Reading, the witness for both parties.
7 COMMISSIONER KJELLANDER: Thank you very much.
8 Idaho Conservation League and Sierra Club.
9 MR. OTTO: Good morning, Commissioners. This
10 is Benjamin J. Otto with the Idaho Conservation League
11 and the Sierra Club, and I have with me today my
12 witnesses Mr. Adam Wenner and Mr. Tom Beach.
13 COMMISSIONER KJELLANDER: Thank you and
14 welcome. Intermountain Energy Partners.
15 MR. MILLER: Thank you, Madam Mr. Chairman,
16 did it again. Dean J. Miller appearing on behalf of
17 Intermountain Energy Partners, and also with me today is
18 our witness Mr. Mark Van Gulik.
19 COMMISSIONER KJELLANDER: Mr. Miller, I'm
20 starting to develop somewhat of a complex. Snake River
21 Alliance.
22 MS. NUNEZ: Good morning, Commissioners. I'm
23 Kelsey Nunez with the Snake River Alliance and with me is
24 my witness Ken Miller.
25 COMMISSIONER KJELLANDER: Thank you. Idaho
CSB REPORTING
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89 COLLOQUY
1 Irrigation Pumpers.
2 MS. OLSEN: Eric Olsen here for Idaho
3 Irrigation Pumpers, along with our witness Anthony
4 Yankel.
5 COMMISSIONER KJELLANDER: Welcome. Renewable
6 Energy Coalition.
7 MR. WILLIAMS: Mr. Chairman, Ron Williams,
8 Williams Bradbury, on behalf of Renewable Energy
9 Coalition. Also with me who will be conducting the
10 hearing is Mr. Irion Sanger from Sanger Law. Mr. John
11 Lowe, our witness, will be arriving shortly, and I would
12 also ask permission from the Commission at some point to
13 be excused from attending both days of the hearing on
14 behalf of the Coalition. Mr. Sanger will be conducting
15 the hearing.
16 COMMISSIONER KJELLANDER: Thank you, and
17 without any objection, which I hear none, that was your
18 chance, certainly no problem at all with you leaving at
19 your convenience. Thank you.
20
21
22
MR. WILLIAMS: Thank you, Mr. Chairman.
COMMISSIONER KJELLANDER: Ecoplexus.
MR. HAMMOND: Chairman Kjellander and
23 Commissioner Raper, my name is John Hammond. I'm with
24 the firm Fisher Pusch and we represent Ecoplexus today.
25 COMMISSIONER KJELLANDER: Thank you very much.
CSB REPORTING
[phone]
90 COLLOQUY
1 Are there any parties to the case that we have
2 overlooked? Yes.
3 MR. ARKOOSH: Tom Arkoosh, North Side Canal
4 Company, Twin Falls Canal Company. With me today is Alan
5 Hansten from North Side and Louis Zamora from Twin Falls.
6 COMMISSIONER KJELLANDER: Okay, if you could
7 for us down the road, I think you were close enough to
8 our court reporter for her to hear you, but you'll need
9 to turn that on. You'll know that it's on when the
10 little red light pops up.
11
12
MR. ARKOOSH: Thank you.
COMMISSIONER KJELLANDER: Thank you. Anyone
13 else? Mr. Miller.
14 MR. MILLER: Mr. Chairman, I've also appeared
15 on behalf of AgPower, which is a company that was granted
16 intervenor status. Given, however, the current state of
17 the record, I do not anticipate any cross-examination
18 during the hearing on behalf of AgPower.
19 COMMISSIONER KJELLANDER: Thank you very much
20 for the notice. Yes.
21
22 name is
23
MS. HOWLAND: Good morning, Commissioners. My
COMMISSIONER KJELLANDER: You're going to have
24 to step up to a microphone, make sure a little red light
25 is on and make sure that you're speaking in it.
CSB REPORTING
[phone]
91 COLLOQUY
1 MS. HOWLAND: Good morning, Commissioners. My
2 name is Pam Howland. I'm here on behalf of Micron. I'm
3 appearing today and Fred Schmidt will be present tomorrow
4 and the next day.
5 COMMISSIONER KJELLANDER: Okay, are you an
6 official party to the case?
7
8
9
10
MS. HOWLAND: As an intervenor.
COMMISSIONER KJELLANDER: Okay, thank you.
MS. HOWLAND: Thank you.
COMMISSIONER KJELLANDER: Do you anticipate any
11 cross-examination?
12 MS. HOWLAND: I do not, Commissioner, but Mr.
13 Schmidt may well when he arrives tomorrow.
14 COMMISSIONER KJELLANDER: Okay, thank you. Is
15 there anyone else that we need to recognize with regards
16 to your presence as a party to the case? Seeing none,
17 then, we're ready to move on to any initial motions,
18 preliminary matters before the Commission. Yes.
19 MS. HUANG: Yes, good morning, Mr. Chairman.
20 There are pending --
21 COMMISSIONER KJELLANDER: Can you please
22 recognize yourself?
23 MS. HUANG: Sorry, my apologies. Daphne Huang
24 representing Commission Staff. There are two pending
25 motions before the Commission, from Commission Staff and
CSB REPORTING
[phone]
92 COLLOQUY
1 also Idaho Power has filed one. These are motions to
2 strike the testimony of Adam Wenner, a witness for Idaho
3 Conservation League and Sierra Club. The Commission has
4 the motions before it and it either may address those,
5 rule on them later, defer them, or if the Commission
6 wishes to hear any reply arguments, I'm prepared to make
7 that at this time.
8 COMMISSIONER KJELLANDER: Ms. Huang, are you
9 introducing both of the motions that were made by various
10 parties or just your own?
11 MS. HUANG: I will only speak on behalf of
12 Commission Staff for our motion, just to advise the
13 Commission that there are these two motions and I'm sure
14 Idaho Power Company can speak to their motion as well.
15 COMMISSIONER KJELLANDER: Well, it would be my
16 intent to go ahead and deal with that now as a
17 preliminary matter, so if we could tee up those issues
18 and get the point, counterpoint rolling, let's do so.
19 MS. HUANG: And we do have -- so filed we have
20 Staff's motion, Idaho Power's motion. There is a
21 response that has been filed by Mr. Otto on behalf of the
22 Idaho Conservation League and Sierra Club, but in very
23 brief reply to the response that was filed, Staff will
24 assert today or puts forth two points, really; the first
25 being in response to the motion, Idaho Conservation
CSB REPORTING
[phone]
93 COLLOQUY
1 League and Sierra Club have asserted that there are other
2 witnesses also testifying to the same types of
3 information that Mr. Wenner is testifying to, to which
4 Staff objects.
5 Those witnesses, Mr. Sterling, Mr. Clements,
6 Mr. Dickman, and Mr. Yankel are distinguishable from
7 those of Mr. Wenner. The experts Sterling, Clements,
8 Dickman, and Yankel are not putting themselves forward as
9 legal experts. They are instead engineering, business,
10 accounting experts, so they're not putting themselves
11 forward as experts in the law. To the extent that they
12 are addressing the legalities or the validity of certain
13 aspects of federal regulations and law, they are mixed
14 questions of law in fact and they're putting them forth
15 more as policy arguments; whereas Mr. Wenner holds
16 himself out as a legal expert only, and that has been
17 found to be, as set forth in Staff's motion is found to
18 be, impermissible and not able to be considered.
19 Secondly, to the extent that Mr. Otto has put
20 forth authority that legal opinion is admissible before a
21 tribunal, those cases are from outside of this
22 jurisdiction. They are not controlling authority for
23 this Commission. They also have addressed an Eighth
24 Circuit decision, a Van Dyke cited in Mr. Otto's
25 response, which involves very complex legal issues
CSB REPORTING
[phone]
94 COLLOQUY
1 involving banking, in o�her instances on tax law, where
2 the abilities of parties' counsel is inadequate to
3 articulate the legal positions for the decision makers
4 and I would put forth that that is not the case here.
5 Unless the Commission feels that counsel are
6 unable to set forth the arguments about how to interpret
7 case law and the regulations having to do with PURPA in
8 this tribunal, I would argue that they are not, so for
9 those reasons, Staff does request that this Commission
10 strike Mr. Wenner's direct testimony only.
11 COMMISSIONER KJELLANDER: Thank you very much.
12 Mr. Otto, we will give you an opportunity to respond, but
13 before we do so, I know we have another motion to strike
14 and if we could move forward and hear the argument there,
15 and by the way, thank you to all parties who gave us the
16 prefiled motions. That makes it easier for us as a
17 Commission to dig through this and we do appreciate that,
18 also recognizing we've had an opportunity to read it, to
19 the extent you have new things to add, if you could sort
20 of condense your message instead of going through the
21 entire argument, thank you.
22 MR. WALKER: Thank you, Mr. Chairman. Donovan
23 Walker on behalf of Idaho Power Company. As referenced
24 on June 23rd, Idaho Power did file a motion to strike the
25 direct and rebuttal testimony of Adam Wenner, the witness
CSB REPORTING
[phone]
95 COLLOQUY
1 on behalf of Idaho Conservation League and Sierra Club,
2 and so as not to be overly repetitive, I think it's
3 extremely clear that Mr. Wenner's testimony as an
4 attorney holding out as an expert in the law and as a
5 former staffer on FERC offering his interpretation of
6 what those rules mean and making legal conclusions
7 therefrom, it's very clear that that's not admissible
8 testimony in front of this Commission.
9 It may be appropriate legal argument, analysis
10 and conclusions, but that's not proper for a factual
11 witness in front of the Commission. As outlined in our
12 written motion, there are several cases indicating that
13 that type of testimony is not admissible offered either
14 from a lay witness or an expert witness, and we went
15 further that even if it was admissible, it's irrelevant
16 and not helpful to this Commission.
17 The case law, we recite -- we've broken it out
18 into two lines of case law. One line deals specifically
19 with a lawyer as a witness, which is relevant to the way
20 that the testimony is laid out and the context of the
21 testimony in addressing the very legal conclusions that
22 this Commission is called upon to make as part of this
23 proceeding.
24 Furthermore, even if the Commission were to
25 determine it admissible, essentially the recollections of
CSB REPORTING
(208} 890-5198
96 COLLOQUY
1 a former staffer of FERC do not form a proper basis for
2 statutory interpretation and are not necessary for this
3 Commission who may review the documents, the historical
4 documents, as well as statutory and administrative law
5 that's applicable and reach its own conclusions of law,
6 which is your duty, so with that, we ask that both his
7 direct and rebuttal be stricken.
8 COMMISSIONER KJELLANDER: Thank you very much.
9 Is there anyone else who wishes to weigh in in support of
10 the motion to strike? If not, then, we'll move to Mr.
11 Otto.
12
13
MR. OTTO: Thank you, Mr. Chairman.
COMMISSIONER KJELLANDER: Could you please turn
14 on your microphone or at least get closer?
15 MR. OTTO: Benjamin Otto with the Idaho
16 Conservation League and the Sierra Club. We did file, I
17 did file, our response in responding to both the Staff
18 and Idaho Power and we stand by that response, but to
19 briefly summarize, the core objection to offering
20 testimony regarding the law is the ability to confuse or
21 influence the jury in an improper manner and we don't
22 have a jury here. The Commission is well suited to look
23 at this evidence and give it the weight you feel it
24 deserves.
25 We filed this in an attempt to be helpful;
CSB REPORTING
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97 COLLOQUY
1 could have done so in a legal briefing. The schedule
2 called for witness testimony. We followed that schedule.
3 The fact that Mr. Wenner is an attorney is a distinction
4 without a difference. That would be very true if this
5 was a jury trial, because the jury would see the witness
6 as a lawyer and maybe give the evidence a little more
7 credibility than it might deserve, you know, because they
8 are a lay jury.
9 As a Commission, that's less of a worry.
10 You're well suited to understand whether, just as in a
11 legal brief, this an opinion or some evidence that you
12 could put a lot of weight to or not. By statute and by
13 Supreme Court interpretation, this Commission is not
14 bound by the technical rules of evidence and you have
15 substantial discretion to allow things into the record
16 and to afford it weight. That's been the traditional
17 course of action at this Commission and I would ask that
18 you continue to follow that traditional course.
19 The fact that we cite to Eighth Circuit cases,
20 yes, they're outside this jurisdiction. I think they're
21 informative. PURPA is a complex statute. I think it's
22 appropriate to have, you know, some evidence, some
23 weighing, at least setting forth what the law says.
24 There may be some sentences that come to a conclusion,
25 but, again, the Commission is well suited to give that
CSB REPORTING
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98 COLLOQUY
1 the weight you feel it deserves.
2 Idaho Power's argument that it's not relevant
3 seems to miss the mark. PURPA law appears to be relevant
4 in this case. Many parties address it and the statutory
5 interpretation argument, that's not why the Idaho
6 Conservation League puts forward this argument or this
7 evidence. This is merely to help inform and assist the
8 fact finder, so, again, you're not bound by the technical
9 rules of evidence. You have plenty of discretion to
10 allow evidence in and can create a robust record and then
11 give that record the weight that you feel it deserves, so
12 we ask that you allow Mr. Wenner's testimony into the
13 record. Thank you.
14 COMMISSIONER KJELLANDER: Thank you, Mr. Otto.
15 Is there anything else that needs to come before the
16 Commission before we take a brief recess to discuss --
17 MR. ADAMS: Mr. Chairman, Greg Adams on behalf
18 of the J.R. Simplot Company. We didn't file any formal
19 position on this particular motion to strike, but we do
20 oppose the motion to strike. We think it's clear from
21 the cases that were cited that a lawyer can in fact be a
22 witness if he's qualified, and if you're talking about a
23 complex regulatory structure, we don't see how this is
24 different than banking regulations or something complex
25 of that nature.
CSB REPORTING
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99 COLLOQUY
1 These FERC regulations and what a long-term
2 contract means, what the regulation means, what Order 69
3 means are all relevant issues that are complex regulatory
4 issues and we believe Mr. Wenner's testimony was proper
5 to respond to the utilities' testimony and the Staff
6 testimony, also, which included legal conclusions, so we
7 do support leaving Mr. Wenner's testimony in the record,
8 so we would request that the Commission deny the motion
9 to strike. Thanks.
10 COMMISSIONER KJELLANDER: Thank you. Is there
11 anything else that needs to be presented to the
12 Commissioners? Mr. Miller.
13 MR. MILLER: Thank you, Madam or Mr. Chairman.
14 I won't repeat the arguments that have been made. The
15 only additional point, observation I would make is that
16 neither the Staff objection nor Idaho Power's objection
17 allege the existence of any prejudice; prejudice in the
18 sense that the testimony is beyond the scope of the case;
19 prejudice in the sense that it broadens, unduly broadens,
20 the issue; prejudice in the sense it introduces topics
21 beyond the expertise of the Staff or Idaho Power Company.
22 It seems to me that certainly neither the Staff
23 nor Idaho Power like Mr. Wenner's testimony. That
24 doesn't establish the existence of prejudice and I would
25 ask the Commission to take into account whether any party
CSB REPORTING
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100 COLLOQUY
1 is truly prejudiced by the admission of this testimony.
2 COMMISSIONER KJELLANDER: Thank you,
3 Mr. Miller. Any further comments before the Commission?
4 So it's fully before us and I guess I'll weigh in first
5 and we'll go ahead and do this live. First of all,
6 again, I appreciate the prefiling. It gives us an
7 opportunity to go back through and look at all the
8 testimony and see how interwoven a lot of rebuttal
9 testimony and reply comments were, and with that in mind,
10 I believe, at least from my perspective, that it would be
11 very different and laborious to try to unwind a lot of
12 the other testimony that's already been submitted in the
13 record.
14 Personally, it's very difficult to unread what
15 I've already read, but more importantly, recognizing, and
16 I think everyone agrees, that we ultimately as a
17 Commission will be the trier of facts, drawing the
18 conclusions of law, and we can give it the appropriate
19 weight it deserves, so that's my general comment with
20 that. Commissioner Raper.
21 COMMISSIONER RAPER: It would seem that the
22 parties generally agree that if it's a matter of fact and
23 law, then it should be something that appears on the
24 record. If it's a matter of purely law and it's
25 something pursuant to the rules, then it is not permitted
CSB REPORTING
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101 COLLOQUY
1 to be included in the case. I think that in an abundance
2 of caution, it would be appropriate to presume that in
3 the breadth of the testimony that's given that there are
4 probably some factual arguments in there that are part of
5 the interpretations of the law. I think that going with
6 the tradition of the Commission in allowing us to give it
7 the weight it deserves upon full consideration of the
8 entire record at the conclusion of the case is the
9 appropriate way to go, and I make a motion to deny the
10 Staff and Idaho Power's motion to strike.
11 COMMISSIONER KJELLANDER: So we have a motion
12 before us to deny the motions to strike. All those in
13 favor signify by aye.
14
15
COMMISSIONER RAPER: Aye.
COMMISSIONER KJELLANDER: Aye, and that motion
16 carries, so we will reject those motions to strike and we
17 will move forward, then, to the first witness, and unless
18 there is any objection, let's begin with Idaho Power.
19 MR. WALKER: Thank you, Mr. Chairman. Idaho
20 Power calls as its first witness Lisa Grow.
21
22
23
24
25
CSB REPORTING
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102 COLLOQUY
1 LISA A. GROW,
2 produced as a witness at the instance of Idaho Power
3 Company, 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 MR. WALKER:
DIRECT EXAMINATION
10 Q. Would you please state your name and spell your
11 last name for the record?
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A.
Q.
My name is Lisa Grow, G-r-o-w.
And by whom are you employed and in what
14 capacity?
15 A. I'm employed by Idaho Power Company and I'm the
16 senior vice president of power supply.
17 Q. Are you the same Lisa Grow that filed direct
18 testimony on January 30th, 2015?
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A.
Q.
I am.
And do you have any corrections, changes, or
21 additions to your testimony?
22 A. I do. If you can go to page 3, line 1, there's
23 the end of a sentence that's actually over on page 3 or
24 2, excuse me, the words were "two years," I would like to
25 add "for projects above the published rate eligibility
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103 GROW (Di)
Idaho Power Company
1 cap," so that sentence would read, "Therefore, Idaho
2 Power requests that the Idaho Public Utilities Commission
3 issue an order directing that the maximum required term
4 for an Idaho Power PURPA energy sales agreement to be
5 reduced from 20 years to two years for projects above the
6 published rate eligibility cap."
7 And then again on page 16, it is basically the
8 same sentence and at the end on line 1 following the
9 words "two years," it would be again "for projects above
10 the published rate eligibility cap."
11 Q. If I were to ask you the questions set out in
12 your corrected prefiled testimony, would your answers be
13 the same here today?
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15
A. Yes, they would.
MR. WALKER: Mr. Chairman, I move that the
16 prefiled direct testimony of Lisa Grow be spread upon the
17 record as if read.
18 COMMISSIONER KJELLANDER: And without
19 objection, we will spread the prefiled testimony across
20 the record as if read.
21 (The following prefiled testimony of
22 Ms. Lisa A. Grow is spread upon the record.)
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104 GROW (Di)
Idaho Power Company
1
2
Q.
A.
Please state your name and business address.
My name is Lisa A. Grow and my business address
3 is 1221 West Idaho Street, Boise, Idaho 83702.
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5
Q.
A.
By whom are you employed and in what capacity?
I am employed by Idaho Power Company ("Idaho
6 Power" or "Company") as the Senior Vice President of
7 Power Supply.
8 Q. Please describe your educational background and
9 work experience with Idaho Power.
10 A. I graduated from the University of Idaho in
11 1987 with a Bachelor of Science in Electrical
12 Engineering. I received an Executive Masters of Business
13 Administration from Boise State University in 2008. I
14 began my career at Idaho Power after graduating from the
15 University of Idaho in 1987, and have held several
16 engineering positions before moving into management in
17 2005. In 2005, I was named Vice President of Delivery
18 Engineering and Operations. In 2009, I was appointed to
19 my current position as Senior Vice President of Power
20 Supply. My current responsibilities include overseeing
21 the operation and maintenance of Idaho Power's generation
22 fleet, power plant engineering and construction,
23 environmental affairs, water management, power supply
24 planning, and wholesale electricity and gas operations.
25 I also oversee Idaho Power's Load Serving Operations
Group, which is responsible for delivering
105 GROW, DI 1
Idaho Power Company
1 reliable energy to customers through the Company's
2 electrical grid using its generation portfolio and system
3 purchases. The management and administration of Public
4 Utility Regulatory Policies Act of 1978 ("PURPA")
5 cogeneration and small power production facilities is
6 within Idaho Power's Load Serving Operations Group.
7 Q. What is the purpose of your testimony in this
8 matter?
9 A. The purpose of my testimony is to present the
10 Company's request to modify terms and conditions for
11 PURPA energy sales agreements that the Company is
12 required to enter into pursuant to federal law. More
13 specifically, Idaho Power believes the current 20-year
14 authorized contract term places undue risk of power
15 supply cost increases on customers at a time when Idaho
16 Power has sufficient resources to meet customer demands.
17 The Company's required Integrated Resource Plan ("IRP")
18 process is filed and updated every two years. Non-PURPA
19 purchase and sales transactions are limited to less than
20 two years pursuant to the Company's approved risk
21 management policy. Avoided cost rates are updated at
22 least every year. Therefore, Idaho Power requests that
23 the Idaho Public Utilities Commission ("Commission")
24 issue an order directing that the maximum required term
25 for an Idaho Power PURPA energy sales agreement be
reduced from 20 years to
106 GROW, DI 2
Idaho Power Company
1 two years for projects above the published rate
2 eligibility cap. I will provide an overview of the
3 Company's case and describe the composition of Idaho
4 Power's generation resources, including its carbon
5 emissions and renewable generation.
6
7
Q.
A.
Are you sponsoring any exhibits?
No. However, Idaho Power is contemporaneously
8 filing the Direct Testimony of Randy Allphin. Mr.
9 Allphin is sponsoring 10 exhibits in support of Idaho
10 Power's Petition and request in this matter.
11
12 Q.
I. IDAHO POWER'S GENERATION RESOURCES
Could you describe Idaho Power and its
13 generation resources?
14 A. Yes. Idaho Power is a vertically integrated
15 electric utility with operations beginning in 1916.
16 Idaho Power serves more than 513,000 customers throughout
17 a 24,000 square mile area in southern Idaho and eastern
18 Oregon. Idaho Power owns and operates 17 hydroelectric
19 generating facilities, primarily on the Snake River,
20 which provide the bulk of the Company's generating
21 ability. Idaho Power has a nameplate generation capacity
22 of nearly 3,600 megawatts ("MW"). Idaho Power's peak
23 system load is just over 3,400 MW, which occurred on July
24 2, 2013. The Company's peak system load for 2014 was
25 approximately 3,184 MW. Its minimum system load for 2014
107 GROW, DI 3
Idaho Power Company
1 was approximately 1,073 MW. Idaho Power residential,
2 business, and
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Idaho Power Company
1 agricultural customers consistently pay some of the
2 nation's lowest prices for electricity.
3 Idaho Power's five-year average fuel mix consists of
4 over 58 percent renewables, which is primarily hydro and
5 wind. Idaho Power has always been a low carbon emitting
6 and primarily renewable energy electric utility. Idaho
7 Power is nearly 100 years old, and its first power plant
8 was hydroelectric. Idaho Power believes in a balanced
9 generation portfolio, including renewable energy that
10 blends demand-side management and energy efficiency
11 programs to meet the needs of all its customers. As
12 shown in Mr. Allphin's Exhibit No. 2, as of January 26,
13 2015, Idaho Power had 1,428 MW of renewable energy (PURPA
14 and non-PURPA purchases) on its system or under contract,
15 excluding the Company's hydro resources. This renewable
16 generation consists of: 728 MW of wind, 461 MW of solar,
17 35 MW of geothermal, and 184 MW of small PURPA hydro and
18 other. Because Idaho Power does not receive the
19 Renewable Energy Certificates/Credits ("RECs") from most
20 of its Qualifying Facility ("QF") generation, this
21 generation cannot be used to meet any potential renewable
22 portfolio standard requirements. Idaho Power cannot
23 represent to customers that they are receiving renewable
24 energy from the QFs, or from generation, for which it
25 does not receive the RECs, and is not making any such
representation here.
109 GROW, DI 4
Idaho Power Company
1 However, these are the renewables that operate on the
2 Company's system and which the Company must integrate.
3 Q. Could you describe Idaho Power's current
4 portfolio of generation resources?
5 A. Idaho Power's current resource portfolio
6 consists of a diverse mix of low-cost generation types
7 totaling nearly 3,600 MW of nameplate capacity. Idaho
8 Power's resource portfolio is anchored by the Company's
9 hydroelectric system consisting of 17 projects located on
10 the Snake River and its tributaries. These 17 projects
11 provide 1,709 MW of nameplate capacity and approximately
12 8.4 million megawatt-hours ("MWh") annually under median
13 water conditions. Idaho Power is the non-operating
14 partner in three coal-fired power plants that provide the
15 Company with 1,119 MW of nameplate capacity. Idaho
16 Power's share of these resources includes the Jim Bridger
17 power plant at 771 MW, the North Valmy power plant
18 ( "Valmy") at 284 MW, and the Boardman power plant
19 ("Boardman") at 64 MW. Idaho Power's resource portfolio
20 also includes three natural gas-fired combustion turbine
21 plants. Langley Gulch, a combined-cycle plant, provides
22 318 MW of nameplate capacity. The Company's two
23 simple-cycle "peaker" plants, the Danskin power plant and
24 Bennett Mountain power plant, provide a combined 444 MW
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Idaho Power Company
25 of nameplate capacity. Idaho Power also owns a small
diesel-fired generator located in
1 Salmon, Idaho, that provides approximately 5 MW of
2 nameplate capacity.
3 Q. In addition to energy from its own resources,
4 does Idaho Power obtain generation from any other
5 sources?
6 A. Yes. The Company currently has power purchase
7 agreements with one wind project and two geothermal
8 projects. Elkhorn Valley wind project, located in
9 northeastern Oregon, provides 101 MW of nameplate wind
10 generation. The Raft River geothermal power plant,
11 located in southern Idaho, provides 13 MW of nameplate
12 capacity. The Neal Hot Springs geothermal project,
13 located in eastern Oregon, provides 22 MW of nameplate
14 capacity.
15 Idaho Power also contracts with QFs for energy
16 purchases under PURPA. As shown in Mr. Allphin's Exhibit
17 No. 2, Idaho Power currently has 133 PURPA contracts for
18 approximately 1,302 MW of nameplate capacity. The PURPA
23 burning facilities.
22 projects, anaerobic digesters, landfill gas, and wood
19 generation facilities consist of low-head hydroelectric
How does a diverse generation portfolio benefit Q.
21 projects at industrial facilities, wind projects, solar
20 projects on various irrigation canals, cogeneration
24
25 Idaho Power and its customers?
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Idaho Power Company
1 A. Idaho Power has learned from nearly a century
2 of operations that energy diversity means energy
3 security.
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112 GROW, DI 6a
Idaho Power Company
1 The Company's resource portfolio is among the most
2 diverse and therefore secure in the nation. The Company
3 leverages its hydro, coal, and natural gas resources to
4 provide dependable "baseload" energy to customers, along
5 with purchased renewable resources and a robust set of
6 energy efficiency programs. It is the same principle as
7 maintaining a diversified investment portfolio to manage
8 risk; a variety of resources minimizes the risk that
9 comes with having all your eggs in one basket.
10 Q. Could you describe Idaho Power's carbon
11 emissions?
12 A. Idaho Power is one of the lowest carbon
13 emitting utilities in the industry. Based upon 2012
14 emissions, for overall emissions, Idaho Power is ranked
15 among the 36 lowest and, for emission intensity (MWh), it
16 is among the 38 lowest carbon dioxide emitters among the
17 nation's 100 largest electricity producers. Idaho Power
18 charts its carbon intensity in its annual sustainability
19 reports, as well as tracking and displaying its progress
20 on its website. Idaho Power established a carbon
21 emission intensity goal in 2009 to reduce average carbon
22 dioxide emission intensity for the 2010 to 2013 period by
23 10 to 15 percent below its 2005 intensity of 1,194 pounds
24 per MWh. In November 2012, Idaho Power's Board of
25 Directors approved extending that goal through 2015. By
the end of 2013,
113 GROW, DI 7
Idaho Power Company
1 Idaho Power had reduced its average carbon dioxide
2 intensity over the 2010 to 2013 period to 929 pounds per
3 MWh, a 22 percent reduction from 2005 carbon dioxide
4 intensity. Preliminary results for the year ending 2014
5 show that the Company remains on track with approximately
6 944 pounds per MWh, which is a 21 percent reduction from
7 2005 levels.
8 Being a predominately hydro-based system, Idaho
9 Power's carbon intensity varies based upon the hydrologic
10 conditions; that is, good water years help reduce carbon
11 emissions. However, Idaho Power has taken other steps to
12 reduce emission intensity. The most recent addition to
13 Idaho Power's generation is the Langley Gulch natural
14 gas-fired plant, which was originally planned to be a
15 coal plant, generates with about half of the carbon
16 dioxide intensity of a coal-fired plant, helps with
17 integration of intermittent renewable energy, and
18 provides an option to further reduce carbon dioxide
19 emissions and intensity by fuel switching from coal to
20 natural gas. Idaho Power has also been working to
21 maximize effective utilization of its existing
22 hydroelectric resources. Recent turbine upgrades have
23 seen efficiency gains of 3 to 5 percent increases in MW
24 generated with the same amount of water. This includes
25 cloud seeding and effective water leasing practices.
114 GROW, DI 8
Idaho Power Company
1 Idaho Power's current cloud seeding project includes 36
2 ground
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115 GROW, DI Sa
Idaho Power Company
1 generators and an aircraft, which results in an estimated
2 193,000 MWh of additional hydroelectric generation.
3 Expansion of the cloud seeding program could produce an
4 estimated additional 277,000 MWh of hydroelectric
5 generation.
6 Q. Are there other considerations with the
7 continued operation of coal plants besides carbon
8 emissions?
9 A. Beyond carbon dioxide, Idaho Power has been
10 working to reduce NOx and S02 emissions from coal-fired
11 plants and has seen a dramatic decrease in those
12 emissions since 1998 because of enhanced operating
13 efficiencies at the plants, improvements in pollution
14 control equipment, and increased integration of renewable
15 energy. In testimony from Case No. IPC-E-13-16 during
16 2013, Idaho Power discussed a path for the eventual
17 retirement of coal resources. As the Company seeks to
18 balance the impacts of carbon with the economic realities
19 of its customers, it knows that it cannot inunediately
20 terminate operation of coal-fired plants. As the Company
21 continues to evaluate its coal plants from an economic
22 standpoint, from the context of lll(d), and from all
23 relevant considerations, it is mindful that those plants
24 have a finite life. The Company has no new coal plants
25 in its IRP. The Company is shutting down coal-fired
operations at the Boardman plant
116 GROW, DI 9
Idaho Power Company
1 in 2020. Idaho Power has been in discussions with the
2 joint owner of the Valmy plant regarding the future of
3 that plant and the resource alternatives that could
4 replace the generation from that plant. Cost is, of
5 course, an important factor, and the state public utility
6 commissions and Idaho Power's customers demand that risk
7 be considered and that future rate increases be mitigated
8 where possible. Idaho Power currently benefits from the
9 diversity of its generation resources, and that diversity
10 helps mitigate the power supply cost risk borne by
11 customers as the Company transitions to the new energy
12 landscape.
13 At the end of the day, the Company is still
14 obligated to produce reliable, fair-priced energy for its
15 customers. Moreover, it has to operate within its
16 regulatory framework, but while doing so must be
17 conscientious as to environmental issues, cost recovery
18 risk, and other various issues that must be considered
19 when striking an appropriate balance.
20
21 Q.
II. OVERVIEW OF THE COMPANY'S CASE
What does Idaho Power see as the major issues
22 in this case?
23 A. Several things: (1) the continuing and
24 unchecked requirement for the Company to enter into
25 long-term, fixed-price agreements to acquire QF
117 GROW, DI 10
Idaho Power Company
1 generation with no regard for the Company's need for
2 additional generation
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118 GROW, DI lOa
Idaho Power Company
1 on its system; (2) the continued acquisition of large
2 amounts of unneeded intermittent PURPA generation
3 pursuant to long-term, fixed-price agreements which
4 inflate power supply costs and degrade the reliability of
5 Idaho Power's system; (3) the continuing requirement to
6 acquire generation outside of the Commission's
7 established !RP process; (4) the fundamental
8 disconnection between the way a regulated monopoly
9 service provider, like Idaho Power, must plan for and
10 acquire generation resources and the PURPA mandatory
11 purchase requirement; and (5) the unnecessary risk that
12 is entirely borne by Idaho Power and its customers of
13 locking in a long-term, fixed-price agreement, with no
14 ability to alter, change, update, or adjust the pricing,
15 terms, and conditions therein for the duration of the
16 agreement.
17 Q. Why is the Company bringing another PURPA
18 related matter before the Commission at this time?
19 A. Idaho Power's requested modification of terms
20 and conditions of required PURPA energy sales agreements
21 is in response to the overwhelming amount of continued
22 PURPA requests for long-term, fixed-price contracts with
23 Idaho Power and in response to the Commission's recent
24 statements in orders approving contracts for upwards of
25 500 MW of new PURPA solar generation.
119 GROW, DI 11
Idaho Power Company
1 Idaho Power has a long history of active PURPA QF
2 projects. The first QF projects were constructed and
3 started selling their output to Idaho Power under PURPA
4 in approximately 1982. For about the next 20 years,
5 Idaho Power accumulated a large number of predominately
6 small hydro PURPA QF projects that steadily increased and
7 maintained energy deliveries under 200 MW total
8 generation, as shown in Mr. Allphin's Exhibit No. 1. In
9 fact, to this day, small hydro QFs make up the majority
10 of PURPA projects under contract with Idaho Power, but
11 provide a relatively small amount of the total PURPA
12 generation. However, since about 2002, and after the
13 Commission increased the maximum contract term from 5
14 years back to 20 years (Case No. GNR-E-02-01), Idaho
15 Power has experienced rapid and large additions of
16 predominately wind, and now solar, QF projects coming
17 on-line and under contract. Idaho Power currently has a
18 total of 1,302 MW of PURPA QF projects under contract,
19 with 781 MW of those projects constructed and operating
20 today, as shown in Mr. Allphin's Exhibit No. 2. In
21 addition, Idaho Power has current requests, received over
22 the last several months, for an additional 885 MW of
23 PURPA solar generation.
24 Upon review of the Commission's recent approval of
25 the last 11 PURPA solar energy sales agreements in the
last two months, the Commission questioned the continued
120 GROW, DI 12
Idaho Power Company
1 acquisition of such large amounts of PURPA generation
2 when there is no associated need for that generation, and
3 a concern for passing those substantial costs on to Idaho
4 Power customers. The Commission stated in those orders:
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To encourage the development of
renewable energy resources, PURPA
requires that electric utilities
purchase generation produced by QFs
under a federal rate mechanism
(i.e., avoided cost) that is
established and implemented by state
utility commissions. Unfortunately,
PURPA does not address and FERC
regulations do not adequately
provide for consideration of whether
the utility being forced to purchase
QF power is actually in need of such
energy.
Idaho Power's 2013 Integrated
Resource Plan does not reflect that
the utility is in need of energy to
reliably serve its customers. And
yet, in less than four months time,
13 QFs have contracted with Idaho
Power for nearly 400 MW of solar
generation - all expected to be on­
line and producing power by the end
of 2016. The combined 20-year
contractual obligation of these 13
projects is approximately $1.4
billion. As we have previously
stated, 100% of the costs of QF
generation are passed on to
ratepayers ....
We recently undertook a detailed
review of the implementation of
PURPA in Idaho. See generally GNR­
E-11-03. This Commission considered
changes to numerous terms and
conditions contained in PURPA
agreements. Recent modifications of
variables within the incremental
121 GROW, DI 13
Idaho Power Company
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cost IRP methodology confirm that
the methodology provides flexibility
that allows us to accurately value
each QF's unique capability to
deliver its resources. However, QFs
continue to request contracts with
Idaho Power in significant enough
numbers that we remain concerned
about the Company's ability to
balance the substantial amount of
must-take intermittent generation
and still reliably serve customers.
While we are pleased with the
progression of the IRP methodology,
avoided cost rates are not the only
terms to a PURPA contract. The
utilities are in the best position
to inform the Com.mission if review
of additional PURPA contract terms
and conditions is warranted.
12 Order Nos. 33198, pp. 5-7; 33199, pp. 5-7; 33200, pp.
13 5-7; 33201, pp. 5-6; 33202, pp. 5-6; 33204, pp. 6-7;
14 33205, pp. 6-7; 33206, pp. 7-8; 33207, pp. 6-8; 33208,
15 pp. 6-8; 33209, pp. 6-8. Idaho Power agrees with and
16 shares the Com.mission's concerns, and thus believes it is
17 necessary to bring the current action to the Com.mission
18 for its determination.
19 Q. What issues does Idaho Power believe should be
20 reviewed by the Com.mission in response to its concerns?
21 A. Several issues related to the Com.mission's
22 implementation of PURPA in the state of Idaho could
23 warrant additional examination and possible revision.
24 These items could include: (1) further modification to
25 the existing avoided cost pricing methodologies to more
appropriately
122 GROW, DI 14
Idaho Power Company
1 reflect need and resource sufficiency in the price; (2)
2 implement new avoided cost pricing methodologies which
3 move to a market-based or competitively bid-based avoided
4 cost mechanism, such as that utilized in Washington; (3)
5 exemption from PURPA under§ 210, part M; (4) Commission
6 pursuit of a waiver from the requirements of § 210,
7 subpart C, for Idaho Power pursuant to 18 C.F.R. §
8 292.402; (5) refinement of the Commission's 90%/110%
9 definition of firmness to require firm scheduled
10 deliveries for entitlement to rates established at the
11 time of contracting or legally enforceable obligation, as
12 opposed to rates determined at the time of delivery,
13 similar to the implementation in Texas; (6) further
14 refinement of the eligibility for rates established at
15 the time of contracting or legally enforceable obligation
16 by requiring QFs to be within 90 days of delivering power
17 before the utility is obligated to the price, again
18 similar to the implementation in Texas; (7) contractual
19 term limitations; and (8) caps, or MW targets, upon the
20 amount of new or repowered projects a utility is required
21 to procure over a given period of time, similar to those
22 in place in California. However, at this time, Idaho
23 Power's specific request with its Petition is that the
24 Commission modify the terms and conditions of prospective
25 purchases from PURPA QFs by reducing the current 20-year
contract term for Idaho
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Idaho Power Company
1 Power energy sales agreements to a maximum of two years
2 for projects above the published rate eligibility cap,
3 and direct any other relief it deems appropriate and in
4 the public interest.
5 Q. Has the Commission changed the maximum term of
6 required PURPA energy sales agreements in the past?
7 A. Yes. I am generally aware that the Commission
8 has changed the authorized maximum term of a required
9 PURPA purchase several times throughout its
10 implementation of PURPA in the state of Idaho. The
11 various changes to the maximum contractual term have
12 resulted from the Commission's evaluation of changing
13 conditions in the energy and utility environment and its
14 attempts to balance the promotion of the development of
15 QF resources with the cost and risk borne by Idaho Power
16 and its customers in the transaction. From 1980 when
17 PURPA was first implemented in the state of Idaho through
18 1987, utilities were obligated to provide QFs with a
19 35-year contract. In 1987, the Commission shortened the
20 maximum term to 20 years based primarily upon the
21 inherent uncertainty in long-term forecasting. Order No.
22 21630. In 1996, the Commission further reduced contract
23 term to five years for QFs of 1 MW and larger, the
24 published rate eligibility cap at that time. Order No.
25 26576. In 1997, the Commission extended the five-year
124 GROW, DI 16
Idaho Power Company
1 contract term limitation to include QFs under the 1 MW
2 published rate eligibility cap as well. Then, in
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Idaho Power Company
1 2002, the Commission went back to a 20-year contract
2 term, which has been in place to the present. Order No.
3 29029.
4 Q. What factors does Idaho Power believe support
5 its request to reduce the maximum term of a PURPA energy
6 sales agreement to a maximum of two years?
7 A. Several things establish that the long-term
8 lock-in of contractual rates, and the bearing of that
9 risk entirely by customers, for 20 years is unjust,
10 unreasonable and contrary to the public interest. The
11 acquisition of any Company-owned generation resource, as
12 well as the Company's purchase and sale of non-PURPA
13 generation, is either limited to terms of two years or
14 less or is subject to intensive Commission and public
15 participation, scrutiny, process, and proceedings to
16 determine that the Company is acting prudently, in the
17 public interest, and fulfilling a need in the least cost,
18 most reliable manner possible. These requirements,
19 particularly that of establishing need for the resource,
20 are absent in a mandatory PURPA QF purchase. The further
21 constraint imposed by PURPA that eliminates any ability
22 to modify, adjust, or change the prices that are locked
23 into a PURPA energy sales agreement for the duration of
24 that contract's term, regardless of whether all costs
25 were included or whether actual costs and conditions
changed or varied, makes long-term, 20-year
126 GROW, DI 17
Idaho Power Company
1 contract terms at best risky, and in Idaho Power's case
2 harmful.
3 The Company's required IRP is filed with and
4 reviewed by the Commission every two years. Changes in
5 conditions, positions, market prices, gas forecasts, load
6 forecasts, etc., are incorporated and captured
7 continually as they happen during the development of the
8 IRP and its biennial filing. Those decisions and inputs
9 are not locked in for 20 years with no ability to adjust,
10 update, or change, like PURPA transactions.
11 With regard to market purchases of generation
12 resources to serve load or any other energy market
13 transactions of purchases and sales that the Company
14 conducts, it must comply with the Commission-approved
15 risk management policy. The Company's risk management
16 policy, set up to govern the risk and customer exposure
17 to market fluctuations when the Company makes power
18 purchases and sales on the market, has short-term
19 limitations. Under its authorized and required risk
20 management policy, the Company does not enter into
21 transactions beyond 18 months. If the Company were to
22 desire to transact for any periods of two years or more,
23 specific Commission authorization and approval is
24 required. This policy has been deemed a prudent process
25 for managing customer exposure to the market and
transactional risk with making generation
127 GROW, DI 18
Idaho Power Company
1 purchases and sales, and the prudent term is far below
2 the 20 years required for mandatory, unchangeable PURPA
3 purchases.
4 The Company is not able to acquire any other
5 generation or purchased power that is indiscriminately
6 locked in for such long terms. If the Company does
7 acquire any non-PURPA generation or purchases longer than
8 two years, it comes with specific Commission
9 determinations of meeting a need in the least cost, most
10 reliable manner available. These determinations are made
11 only after careful examination and process, including
12 various public processes and proceedings such as through
13 the IRP process, a certificate of public convenience and
14 necessity proceeding, rate base proceedings, and other
15 specific Commission proceedings and determinations that
16 assure customers are protected and the Company meets its
17 obligations to reliably serve. It does not follow that a
18 PURPA transaction, that does not have the benefit,
19 requirement, or protections associated with all of the
20 previously mentioned Commission processes and procedures,
21 and must be acquired regardless of need, would be
22 indiscriminately locked in with long-term, fixed costs
23 that cannot be changed.
24 Q. You previously mentioned an inflation of power
25 supply expenses. Could you explain?
128 GROW, DI 19
Idaho Power Company
1 A. Yes. As shown in Mr. Allphin's Exhibit No. 7,
2 PURPA power supply expenses are growing at a very rapid
3 pace and becoming quite large. In sum, Exhibit No. 7
4 shows an alarming 575 percent increase in PURPA power
5 supply expense from 2004 through 2024. Additionally,
6 Exhibit No. 10 shows that Idaho Power's average cost of
7 PURPA generation since 2001 has always exceeded the Mid-C
8 index price and is projected to always exceed the Mid-C
9 index price through 2032.
10 Moreover, as illustrated in Mr. Allphin's Exhibit
11 No. 8, which shows net power supply expenses in base
12 rates, the average cost of PURPA purchases, at $62.49 per
13 MWh, is greater than the average cost of coal at $22.79
14 per MWh, greater than gas at $33.57 per MWh, greater than
15 non-PURPA purchases of $50.64 per MWh, and significantly
16 greater than what is being sold as surplus sales at
17 $22.41 per MWh. If and when the Company is required to
18 purchase PURPA generation when it is not needed, the
19 Company may be required to back-down or curtail other
20 less expensive sources of generation or market purchases
21 in order to continue purchasing PURPA generation at a
22 higher cost. This would mean that the Company's overall
23 net power supply expense, on a dollars per MWh basis,
24 would increase, adversely impacting customers.
25
129 GROW, DI 20
Idaho Power Company
1 Q. You also previously mentioned a degradation of
2 the reliability of Idaho Power's system. Could you
3 explain?
4 A. Yes. Idaho Power's hydroelectric and coal
5 generation has must-run levels that the Company cannot go
6 below without violating environmental regulations
7 relating to the hydro facilities or taking the coal
8 generation off-line and thus making it unavailable to
9 meet required loads until it could be restarted. With
10 the addition of the must-take PURPA generation, which is
11 less predictable than firm generation and does not equate
12 to non-firm generation as it is unscheduled and delivered
13 if, when, and in whatever amount the QF determines, the
14 Company's system can rapidly move to an imbalance
15 position, in this case, primarily to an over-generation
16 position, and the Company must take remedial actions to
17 balance the system. If remedial actions are not
18 available, or not employed in a timely manner, then the
19 Company can have system reliability violations, events,
20 and/or outages and damage. In fact, over the last
21 several years, reliability curtailments of PURPA
22 generation have been necessary in order to maintain the
23 integrity of Idaho Power's system. For the period from
24 May 2011 through December 2014, the Company had at least
25 15 reliability events that resulted in wind generation
130 GROW, DI 21
Idaho Power Company
1 output reductions in order to maintain the reliable
2 operation of
3 I
4
5 I
6
7 I
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
131 GROW, DI 21a
Idaho Power Company
1 the Company's electrical system. These curtailments, or
2 generation limitation set points, have been relatively
3 infrequent, for relatively short durations, and are
4 removed as soon as possible once it can safely be done
5 and maintain a balanced system.
6 Q. Has the Company done any analysis as to what
7 effect the continued acquisition of large amounts of
8 unneeded must-take PURPA generation has upon the
9 reliability of the system?
10 A. Yes. As previously noted, the Commission
11 expressed concern with this issue stating, ''we remain
12 concerned about the Company's ability to balance the
13 substantial amount of must-take intermittent generation
14 and still reliably serve customers." Mr. Allphin's
15 Exhibit No. 6 contains a summary of the Company's
16 analysis estimating the frequency of hours, over the
17 years 2016 and 2017, in which Idaho Power's must-run and
18 must-take resources exceed total system load.
19 Q. What are the results of that analysis?
20 A. The results are summarized on page 1 of Exhibit
21 No. 6. The results generally show an alarming amount of
22 hours throughout 2016 and 2017 where must-run and
23 must-take generation exceeds total system load.
24 Without the inclusion of any gas-fired generation,
25 and including only the Company's must-run coal and hydro
132 GROW, DI 22
Idaho Power Company
1 generation, without any of the must-take PURPA generation
2 whatsoever, that generation is projected to exceed load
3 for 14 percent of all hours during 2016 and 2017. The
4 Company's must-run hydro and coal generation combined
5 with existing must-take PURPA, but without any of the
6 recently approved PURPA solar generation, exceeds total
7 system load for approximately 29 percent of all hours
8 during 2016 and 2017. When the 461 MW of PURPA solar
9 that is under contract and scheduled to be on-line in
10 2016 is included, Idaho Power's must-run and must-take
11 generation exceeds total system load for approximately 32
12 percent of all hours in a year. Finally, inclusion of
13 the additional 885 MW of proposed PURPA solar generation
14 increases the frequency of must-run and must-take
15 generation in excess of load to 40 percent of all hours
16 during 2016 and 2017.
17 Q. What is significant about the hours in which
18 must-run and must-take generation exceeds total system
19 load?
20 A. It is significant because the system has
21 already been backed down as far as it can without
22 shutting something off or sending generation off-system.
23 Each one of these hours creates a potential
24 over-generation event where remedial action of some kind
25 will be necessary to keep the system in balance and meet
133 GROW, DI 23
Idaho Power Company
1 the obligation to reliably serve customers. The
2 historical and projected
3 I
4
5 I
6
7 I
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
134 GROW, DI 23a
Idaho Power Company
1 market price for surplus sales has always been, and is
2 projected to always be, much lower than the price the
3 Company pays for PURPA. Allphin, Ex. 8; Ex. 10. If
4 transmission capacity is available to conduct off-system
5 sales, the Company would sell at a loss. When the
6 Company has no identifiable need for any additional
7 generation, each one of these potential reliability
8 events is a completely unnecessary destabilization of
10 customers at risk.
9 Idaho Power's system, putting its required service to its
12 requested relief proposed by the Company is in the public
Yes. The Company's requested relief is in the
Is it your opinion that the granting of the
A.
Q. 11
14
13 interest?
15 public interest, is within the authority and discretion
16 of the Commission, and the Company respectfully asks the
17 Commission to implement the same.
18 Q. Does this conclude your testimony?
19 A. Yes, it does.
20
21
22
23
24
25
135 GROW, DI 24
Idaho Power Company
1 (The following proceedings were had in
2 open hearing.)
3 MR. WALKER: Thank you, Mr. Chairman. The
4 witness is available for cross-examination.
5 COMMISSIONER KJELLANDER: Thank you very much.
6 Let's look to Avista, any questions?
7
8
9
10
MR. ANDREA: No questions.
COMMISSIONER KJELLANDER: PacifiCorp.
MS. HOGLE: No questions.
COMMISSIONER KJELLANDER: Staff from the Public
11 Utilities Commission.
12
13
14
MS. HUANG: No questions.
COMMISSIONER KJELLANDER: J.R. Simplot Company.
MR. ADAMS: Yes, Mr. Chairman, we have some
15 questions.
16
17
18
19
COMMISSIONER KJELLANDER: Please proceed.
CROSS-EXAMINATION
20 BY MR. ADAMS:
21
22
23
Q.
A.
Q.
Good morning, Ms. Grow.
Good morning.
On page 14 of your direct testimony, you
24 discuss eight different potential ways the Commission
25 could address the perceived problem with large PURPA
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136 GROW (X)
Idaho Power Company
1 solar projects, and the very first that you suggest is
2 "further modification to the existing avoided cost
3 pricing methodologies to more appropriately reflect need
4 and resource sufficiency in the price"; do you remember
5 that?
6
7
A.
Q.
Yes.
Isn't it true that the IRP method used by Idaho
8 Power was proposed by Idaho Power just a few years ago?
9
10
A.
Q.
It was.
It was. Isn't it true that that method
11 excludes capacity payments to the QF during the utility's
12 capacity surplus period?
13
14
A.
Q.
Correct.
Isn't it true that under that method as
15 prospective QFs in the queue request prices that the
16 prices that are provided to them go down because there's
17 prior QFs ahead of them in the queue?
18
19
A.
Q.
That's correct.
Wouldn't you agree that at some point the
20 avoided cost rates to a new QF would get so low that a QF
21 project would be unable to be built?
22
23
24
A.
Q.
A.
I don't know that.
You don't know?
I don't know what would cause a facility to be
25 built or not.
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137 GROW (X)
Idaho Power Company
1 Q. If the price got to zero dollars per
2 megawatt-hour, do you think a solar QF could build the
3 project and sell it?
4 A. I would find that difficult, but, again, I
5 don't know.
6 Q. So would you agree, at least, at some point
7 between zero and the price in the existing contracts the
8 projects would become uneconomical and not be able to be
9 developed?
10
11
A.
Q.
I imagine that would be true.
Later on in your testimony on page 16, you
12 testify regarding the Commission's prior Orders where it
13 shortened the contract term to five years from the period
14 1996 until 2002, including Order No. 29029. Do you
15 recall that?
16
17
18
19
A.
Q.
A.
Q.
Uh-huh, yes.
Did you read those orders?
Yes.
Okay; so then you're aware that in the period
20 between 1996 and 2002, only one QF contract was signed
22
23
A.
Q.
That's correct.
Is that the goal with the application in this
21 while the contract length was limited to five years?
24 case, to eliminate future PURPA contracts?
25 A. Actually, no. The goal of this case is to
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138 GROW (X)
Idaho Power Company
1 limit the term from 20 to two years because we believe
2 that 20 years is too long. It's too much risk placed on
3 our customers at a time when we don't need it.
4 Q. Okay, and on page 18 of your testimony, you
5 discuss the IRP process and how that's a two-year process
6 and you discuss the IRP-derived resources and you state,
7 "Those decisions and inputs are not locked in for 20
8 years with no ability to adjust, update, or change, like
9 PURPA transactions."
10 Isn't is it true, though, that the capital
11 costs of the Company's rate base resources are in fact
12 "locked in" for the life of the project, not for just two
13 years?
14 A. That comparison, that isn't an accurate
15 comparison of the two. The PURPA rules are for --
16 according to the PURPA law. The way that things are rate
17 based for utilities is very different and it's been
18 differentiated that way.
19 Q. But you would agree that the rate-based
20 resources' capital costs are in fact locked in for more
21
22
23
24
25
than two years, aside from the comparison?
A. They are in our rate base.
Q. For longer than two years?
A. Correct.
Q. Would Idaho Power had built the Langley Gulch
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139 GROW (X)
Idaho Power Company
1 gas plant with rate recovery terms of only two years?
2 A. Again, we go through a very different process.
3 We have to go through the IRP process. We demonstrate
4 that there's a need. We demonstrate what type of
5 resource; what reliability objectives are. We have to go
6 through, now we have to go through, competitive bidding
7 to demonstrate that's the most economic solution. We
8 have to go through a CPCN where it's a very public
9 process that the decision is scrutinized once again, and
10 then we go in for a rate case where we actually then have
11 another very public process where it is scrutinized and
12 put into rates if this Commission believes it was done so
13 prudently.
14 Q. And those CPCNs provide recovery for longer
15 than two years; right?
16 A. They do. Well, if it is given with
17 pre-approval. CPCN doesn't necessarily guarantee
18 approval.
19 Q. Okay, and if the Company moves forward with the
20 Boardman to Hemingway transmission line, it will probably
21 ask for more than two years of recovery; right?
22
23
A.
Q.
That's correct.
On page 18 of your testimony, you discuss your
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140 GROW (X)
Idaho Power Company
25 enter into transactions beyond 18 months in duration; do
24 risk management policy and say that the Company does not
1 you recall that?
2
3
A.
Q.
Without approval.
Without approval. Isn't it true that each of
4 your rate-based resources are transactions that involved
5 transactions beyond 18 months?
6 A. That's not -- these are for energy
7 transactions.
8
9
10
Q.
A.
Q.
Not long-term resources?
Correct.
Okay, on page 20, you discuss Mr. Allphin's
11 Exhibit No. 8 and you assert that the average cost of
12 Idaho Power's coal resources is $22.79 per megawatt-hour
13 and the average cost of Idaho Power's gas resources is
14 $33.57. Do you see that?
15 A. Yeah.
16 Q. Isn't it true that these figures do not include
17 the capital costs, Idaho Power's return on investment,
18 the operation and maintenance costs, or any reasonable
19 estimates for capital upgrades for these coal and gas
20 plants?
21 A. Well, as noted, these are the net power supply
22 expenses that are put into base rates. That's what
23 those -- those were the numbers from 2013, the last time
24 we updated net power supply costs in base rates.
25 Q. So it's only the fuel cost; right? It actually
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141 GROW (X)
Idaho Power Company
1 didn't even include the fuel transportation costs?
2
3
A.
Q.
That's correct.
Can you generate electricity with just fuel and
4 no other costs?
5
6
7
A. Of course not.
MR. ADAMS: No further questions, Mr. Chair.
COMMISSIONER KJELLANDER: Thank you. Let's
8 move to Idaho Conservation League/Sierra Club, any cross?
9
10
MR. OTTO: Yes.
COMMISSIONER KJELLANDER: Please move the
11 microphone close.
12
13
14
15 BY MR. OTTO:
CROSS-EXAMINATION
16
17
18
Q.
A.
Q.
Good morning, Ms. Grow.
Good morning.
On page 10 of your testimony and into 11, you
19 cite to five major issues in the case, so I want to
20 explore just a couple of those. We're going to start
21 with No. 3, so that starts on page 11, lines 5 through 7,
22 and it's the continuing requirement to acquire generation
23 outside the IRP process. Are you there in your
24 testimony?
25 A. I see that.
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142 GROW (X)
Idaho Power Company
1
2
3
Q.
A.
Q.
Are you with me?
Uh-huh.
So the avoided cost model is called the IRP
4 method; is that correct?
5
6
A.
Q.
Correct.
And so the IRP, that begins with identifying
7 the existing resource stack; correct?
8
9
A.
Q.
Correct.
And then this IRP applies this resource stack
10 to a forecast of load and hydro conditions to determine
11 the utility's need for additional resources; is that
12 correct?
13 A. That's correct.
14 Q. And so that need, it identifies the timing,
15 correct, like what date you are resource deficient?
16
17
A.
Q.
For a given scenario, yes.
And it identifies the size of the need; is that
18 correct?
19
20
A.
Q.
That's correct.
And it identifies the basic shape, like is it a
21 base load or an intermediate or a peaking need; is that
22 correct?
23
24
A.
Q.
Correct.
So then after identifying this need, you use
25 these data, the existing resources, the forecast for
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143 GROW (X)
Idaho Power Company
1 loads, and hydro, and gas prices, they're input to an
2 hourly dispatch model, the AURORA model, to compare
3 different options; is that correct?
4
5
A.
Q.
Basically, yes.
And these are 20-year forecasts for these
6 inputs and a 20-year kind of result stream; is that
7 correct?
8
9
A.
Q.
That's correct.
So when you're doing the avoided cost model,
10 aren't these the same -- is it the same computer model
11 and the same inputs that go into the avoided cost
12 model?
13
14
A.
Q.
Basically, yes.
So isn't it fair to say that while the resource
15 decision or acquiring the output may be outside the IRP,
16 all the pricing components come directly from the IRP; is
17 that a fair statement?
18 A. No. It comes from -- the same model is used in
19 the calculation, but the determination of need for our
20 customers, these come whenever they want, in whatever
21 amount, the PURPA projects do, in whatever amount they
22 want to come, whatever type of technology, fuel source,
23 any type of dispatch -- not even dispatch, just any type
24 of generation pattern, so no, it's very different.
25 Q. But the IRP defines the resource deficiency
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144 GROW (X)
Idaho Power Company
1 date; correct?
2
3
A.
Q.
For the given scenario, yes.
Right, and that date then out of the IRP
4 defines when the capacity payment starts for a QF
5 project; is that correct?
6
7
A.
Q.
That's correct.
And, you know, essentially the avoided cost for
8 energy, that comes out of the IRP; isn't that correct?
9 A. Well, it doesn't -- there isn't an established
10 needs test. It's a model that produces a price, but at
11 no time it really assesses whether or not the resource is
12 needed. It is merely a pricing mechanism.
13 COMMISSIONER RAPER: Mr. Otto, if I could
14 interrupt for just a minute, can you make a distinction
15 for me going forward between whether you're talking about
16 the integrated resource plan or the IRP methodology?
17 MR. OTTO: Yes, I will. I recognize that that
18 can be confusing. I'll do my very best.
19
20 Q.
COMMISSIONER RAPER: Thank you.
BY MR. OTTO: So less than a year ago the
21 Company filed a case asking to update the capacity
22 deficiency date for the IRP methodology and that was Case
23 14-22. Do you recall that?
24 A. I do.
25 Q. Did you read the final Order in that case,
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145 GROW (X)
Idaho Power Company
1 Order 33159?
2
3
A.
Q.
I did, at the time.
So on page 7 that Order states, "The IRP
4 methodology at issue here" -- and I can give you a copy
5 of this. Would you like that?
6 A. I don't have one if you want me to --
7 Q. Yes, let me do that.
8 MR. OTTO: I'm going to offer this as
9 !CL/Sierra Club Exhibit 304, and this is the Commission's
10 Order 33159, which you can take official notice of. This
11 is just the first page and the seventh page.
12 (Mr. Otto distributing documents.)
13 MR. OTTO: So on the back side there's a
14 highlighted section and it says --
15 MR. WALKER: Excuse me, Mr. Chairman, I'd like
16 to be heard regarding the request to admit this as -- for
17 the Commission to take official notice of this document,
18 and Idaho Power's request would be that if it chooses to
19 admit this under those grounds that it admit the entire
20 document, the entire Order No. 33519, rather than the
21 excerpted portions offered by Mr. Otto.
22
23 Mr. Otto?
24
COMMISSIONER KJELLANDER: Is there a response,
MR. OTTO: Of course, of course, you want to
25 recognize or take official notice of the whole entire
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146 GROW (X)
Idaho Power Company
1 Order. I just used this excerpt so we could just cut to
2 the chase of the operative part of the Order. This is
3 the Commission's findings and conclusions, but I have no
4 objection to admitting the whole entire Order.
5 COMMISSIONER KJELLANDER: So with no objection,
6 then we'll consider that a piece of it. In terms of
7 proceeding at this point, though, I feel pretty confident
8 having signed this Order that I can easily find it and be
9 reminded of all the wonderful, glorious things that we
10 put in it, so if there's no further objection, please
11 proceed.
12 (ICL/SC Exhibit No. 305 was marked for
13 identification.)
14 Q. BY MR. OTTO: So the highlighted sentence says,
15 "The IRP methodology, at issue here, takes into account
16 many different variables and produces a result based on
17 the characteristics of the generation and each individual
18 utility's needs for the resources." Do you see that?
19
20
21
A.
Q.
A.
I do.
Do you disagree with this Commission Order?
I believe that it is much better than the
22 surrogate avoided resource that was used before, but I
23 still think there's issues and that's why we've not
24 really asked to open up the avoided or the IRP
25 methodology and we just asked for the term to limit the
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147 GROW (X)
Idaho Power Company
1 risk.
2 Q. So on page 10, line 20 and 21, you say that
3 price agreements to acquire QF generation with no regard
4 for the Company's need.
5
6
A.
Q.
Correct.
That seems to be in conflict with this
7 Commission Order.
8 A. Well, I believe that it takes it into account,
9 but if you don't need it, the resources can still come,
10 so there's still an issue. It doesn't necessarily
11 address the need question, so it does better than the
12 methodology that was used before, but, again, we felt
13 like it was a much better approach to go for the reduced
14 term to limit the risk rather than reopening this at this
15 time, unless the Commission would find that to be a
16 remedy they would like to explore, then we would take
17 that up.
18 Q. Just two last questions. Idaho Power customers
19 need capacity when the Company is capacity deficient; is
20 that correct?
21
22
A.
Q.
That's correct.
And Idaho Power customers need energy every
23 minute of every day; is that correct?
24
25
A. I would say so.
MR. OTTO: Thank you. That's all.
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148 GROW (X)
Idaho Power Company
1 COMMISSIONER KJELLANDER: Thank you. Mr.
2 Hammond, since you are sitting next to the microphone,
3 does Ecoplexus have any cross-examination?
4 MR. HAMMOND: I have some questions,
5 Commissioner Kjellander. I do have an exhibit. I may
6 not have given it to everybody as the room kept filling
7 up. I do believe most people have it. If you don't have
8 it, let me know, and I don't believe you have a copy, so
9 may I approach?
10 COMMISSIONER KJELLANDER: You may approach if
11 you can find a path.
12 (Mr. Hammond approached the witness.)
13
14
15
16 BY MR. HAMMOND:
CROSS-EXAMINATION
17 Q. Hello, Ms. Grow. My name is John Hammond. I
18 work for Fisher Pusch and we represent Ecoplexus today.
19 A. Good morning.
20 Q. Thank you for taking the time to come today and
21 testify. I've handed you a document that's marked
22 Exhibit 1501. Do you recognize that document?
23
24
A.
Q.
I do.
And let me qualify that first. The document
25 that I've handed you, is that a complete copy -- oh, can
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149 GROW (X)
Idaho Power Company
1
2
3
4
5
you identify what this document is?
A. This is the draft of our integrated resource
plan that was just recently filed for 2015.
Q. And what I've handed you, that's not a complete
copy of the entire document; is that correct?
6
7
A.
Q.
It doesn't appear to be, no.
With that, if there's any objection, you know,
8 I don't have any objection to admitting the entire IRP
9 document. I tried to keep it short and pointed to what
10 our questions were. I don't have any objection if the
11 Company wishes to have the entire document in or not, so
12 just with that, I'd offer this.
13 Are you familiar with this document?
14
15
A.
Q.
I am.
Did you participate in creating this
16 document?
17 A. Not directly, no. I oversee it, though. My
18 team does it.
19 Q. What do you do -- what are your
20 responsibilities in overseeing the creation of this
21 document?
22 A. I make sure that we follow the process, that
23 timelines are met, that the team has the resources they
24 need to complete the analysis. I do engage in
25 discussions along the way on policy issues, et cetera.
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150 GROW (X)
Idaho Power Company
1 Q. Would you be able to answer questions about
2 data in this document do you believe?
3 A. Perhaps, perhaps.
4 Q. Or would Mr. Allphin be the more appropriate
5 witness? Do you have an opinion on that?
6 A. Depending on your question.
7 MR. HAMMOND: I'd like to ask that this exhibit
8 be admitted to the record and then open that up for any
9 objection that someone might have.
10
11
COMMISSIONER KJELLANDER: Without objection
MR. WALKER: Once again, Mr. Chairman, I
12 believe that the draft IRP is a publicly available
13 document and would note that this exhibit contains
14 selected excerpts from that.
15 COMMISSIONER KJELLANDER: Thank you, and also
16 to the extent that the Commission needs to take note,
17 Mr. Hammond, you said that the entire document would be
18 included as part of the exhibit, and I would appreciate
19 that, so if you could make sure the entire document is
20 incorporated into this exhibit, the draft, and make that
21 available to the court reporter, that would be
22 appreciated.
23
24
25 I
MR. HAMMOND: I will do so.
COMMISSIONER KJELLANDER: Thank you.
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151 GROW (X)
Idaho Power Company
1 (Ecoplexus Exhibit No. 1501 was admitted into
2 evidence.)
3
4 Q.
COMMISSIONER KJELLANDER: Please proceed.
BY MR. HAMMOND: Can you proceed to -- it's
5 page No. 125 in that document. That's the page number in
6 the IRP itself. Are you familiar with this table?
7
8
9
A.
Q.
A.
I am.
Can you tell me what it describes?
It describes a variety of the portfolios that
10 were analyzed and it goes through a variety of fixed and
11 variable costs, and it's sort of the total summary, the
12 total cost of each portfolio and compares them to a base
13 case.
14 Q. And can you just describe for the record what
15 the portfolio is?
16 A. The portfolio is basically a selection of
17 resources that would be analyzed meeting the needs of
18 our -- our forecasted customer need.
19 Q. Isn't it true that looking at this table,
20 there's an option P6(b), are you aware whether that's the
21 Company's selected portfolio?
22
23
A.
Q.
It is.
Can you describe what makes up that part of
24 that portfolio?
25 A. So in this portfolio, it shows retirement of
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152 GROW (X)
Idaho Power Company
1 both units at Valmy in 2025. It shows the addition of
2 the Boardman to Hemingway line also in 2025. It contains
3 some demand response, as well as an ice technology that
4 is sort of an energy efficiency load shifting technology
5 and combined cycle combustion turbine.
6 Q. And in the next column over there is an
7 operating cost; is that correct?
8
9
A.
Q.
In --
Where it says "Variable Costs," the next
10 column; is that correct?
11
12
A.
Q.
Well, yes.
Can you describe what those variables costs
13 are, just generally?
14 A. Generally, those are fuel costs, maintenance
15 costs, et cetera.
16
17
18
Q.
A.
Q.
And then can we move down to portfolio P3?
Yes.
And in that portfolio, does that portfolio
19 contain solar generation as an option?
20
21
A.
Q.
It does.
And in that, moving over to the operating cost
22 for that, is the operating cost with that portfolio
23 including solar less than the Company's selected
24 portfolio?
25 A. It is, slightly.
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153 GROW (X)
Idaho Power Company
1 Q. Can you describe -- do you have any knowledge
2 why that is?
3 A. Mostly it was the retirement of Valmy in 2019
4 was my recollection.
5 Q. Can you move to page 132, that's 132 as marked
6 in the IRP document? Now, I'm going to represent that
7 this didn't turn out like I wanted it to.
8 A. Yeah, I was hoping you weren't going to ask me
9 to point out anything.
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13
14
Q.
A.
Q.
A.
Q.
Do you recognize this page?
I do.
Now, are you familiar with it?
I am. Not in black and white, but --
I wish it was in color, so if you cannot answer
15 the question, I understand and I'll offer the document in
16 the record, of course, with a color copy. There are a
17 number of -- in this graph can you see the box that has,
18 for example, P2a? P3? P6?
19
20
A.
Q.
Yes.
Are those portfolios that Idaho Power was
21 examining to determine whether or which portfolio would
22 be preferred?
23
24
A.
Q.
It was.
Is there without colors, and I appreciate
25 this, are you able to identify which line on the graph
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154 GROW (X)
Idaho Power Company
1 matches up with those?
2
3
A.
Q.
I'm sorry, I'm not.
Okay, that's fair, and I apologize for that.
4 Now, let's move to go page 137. Is it true that in the
5 preferred portfolio, P6, Boardman to Hemingway or
6 Boardman is part of that mix or that portfolio?
7 A. Were you talking about the power plant when you
8 said Boardman the second time?
9
10
Q.
A.
Yeah, I'm sorry.
Actually, no. The Boardman power plant is
11 scheduled to be -- cease coal fire operations at the end
12 of 2020.
13
14
15
Q.
A.
Q.
2020?
Yes.
Are there any proposed transmission upgrades
16 for Boardman to Hemingway that you are aware of?
17 A. I'm not sure I understand your question. It in
18 itself is a new transmission line.
19 Q. Boardman to Hemingway is a new transmission
20 line; correct?
21
22
A.
Q.
Yes.
Okay. On page 137 you discuss the Boardman to
23 Hemingway transmission line risk. Can you surrunarize
24 those for the Corrunission?
25 A. Well, at this point siting and permitting is
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155 GROW (X)
Idaho Power Company
1 proving to be difficult, so that is the risk at this
2 point in time.
3 Q. And is Boardman to Hemingway included in the
4 portfolio P6(b)?
5
6
A.
Q.
It is.
With those risks, are those risks, let's say,
7 acceptable or -- strike that. Given those risks, why is
8 portfolio P6(b) still preferred rather than one that
9 doesn't have those risks in it, like P3 that has solar?
10 A. Well, P3 does not -- solar doesn't mitigate all
11 risk for there's risk in everything that we do, and so
12 no, I don't think that the comparison of those two -- the
13 bigger risk is the ability to actually shut down Valmy in
14 '19. It's not about Boardman to Hemingway versus PV, and
15 just in general, transmission is a very different
16 resource than PV. It works at night. It works when it's
17 cloudy, so it's a very different resource. It has a very
18 different performance.
19 Q. Certainly, but the costs of that aren't known
20 at this point, are they?
21
22
A.
Q.
We have estimates.
And even with those estimates, is that still a
23 cheaper resource in the portfolio than other options?
24
25
A.
Q.
It is.
And by what degree?
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156 GROW (X)
Idaho Power Company
1
2
A.
Q.
Well, it's shown in that chart.
But isn't it true that the operating costs for
3 P3, which include solar, are less than that for P6(b)?
4 A. For the variables that were in that, yes, but
5 it's a slight difference and it's not really attributable
6 to the difference of risk between Boardman to Hemingway
7 and PV. It's more about the Valmy timing.
8
9 questions.
MR. HAMMOND: I don't have any further
10 COMMISSIONER KJELLANDER: Thank you. Let's
11 move to the Renewable Energy Coalition.
12
13
MR. SANGER: No questions.
COMMISSIONER KJELLANDER: Thank you. Idaho
14 Irrigation Pumpers.
15
16
MS. OLSEN: No questions, Your Honor.
COMMISSIONER KJELLANDER: Thank you. Let's
17 see, Snake River Alliance.
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MS. NUNEZ: Thank you, Commissioner.
CROSS-EXAMINATION
22 BY MS. NUNEZ:
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25
Q.
A.
Q.
Good morning, Ms. Grow.
Good morning.
I wanted to ask you a few questions about risk
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157 GROW (X)
Idaho Power Company
1 management of the customers. Would you agree that your
2 testimony and the Company's application express the goal
3 to reduce carbon emissions and work towards the closure
4 of coal plants?
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6
A.
Q.
That this filing is about that?
That the filing expresses a preference to do
7 that or an intention to do that.
8 A. Well, I think the filing is about reducing the
9 term of PURPA from 20 to two years.
10 Q. Yes, there are several places in your testimony
11 and also in the filing that discuss the carbon intensity
12 and emissions reduction moves that the Company has taken
13 and also insinuates that there will be closures of coal
14 plants in the future.
15
16
A.
Q.
I do discuss that, yes.
Okay; so I was asking if you agree that that is
17 expressed in the filing. Just real quick, is there
18 anything about the integrated resource plan that's been
19 drafted that's changed any of your testimony, which was
20 filed before the IRP process concluded?
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22
A.
Q.
I don't believe so.
Okay, just wanted to check; so how does --
23 does, and if so, how does the Company calculate and
24 manage the environmental and economic consequences of
25 generating electricity from coal? Is that a factor in
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158 GROW (X)
Idaho Power Company
1 your calculations of the impacts of coal plants?
2 A. At this point we had -- previously we have
3 compared or used carbon taxes as a way of sort of valuing
4 that and this year was the first year we did not do that.
5 Instead, we tried to model the portfolios for lll(d)
6 compliance as it was written in its [inaudible]. We
7 don't know what those rules are going to be yet, so this
8 version of the !RP was a little interesting because we
9 didn't have a final order, so we did the best we could
10 with the information we had.
11 Q. Has the Company been able to measure impacts to
12 the hydropower resources, changes in flow that some have
13 said are attributed to climate change from fossil fuel
14 combustion?
15 A. We do not have an analysis that can attribute
16 that. There's many factors that go in.
17 Q. Has the Company began looking into how those
18 measurements might be done?
19
20
A.
Q.
We have not.
Do you think that Idaho Power and its customers
21 are exposed to risk from some of these unknown factors
22 associated with large investments in coal facilities that
23 the Commission did acknowledge were facing an uncertain
24 future?
25 A. Could you ask your question again?
CSB REPORTING
[phone]
159 GROW (X)
Idaho Power Company
1 Q. Putting it back in context, it seems like a lot
2 of this case is about managing risks to Idaho Power and
3 the customers and wanting to protect the customers from
4 risks associated with investments and these types of
5 PURPA projects, so what I'm asking is do you think that
6 Idaho Power and its customers are also exposed to unknown
7 risks associated with large investments in coal plants,
8 which the Commission has acknowledged have very uncertain
9 future economically and the environmental consequences of
10 which are not readily subject to calculations at this
11 point?
12 A. Well, we've been making significant investments
13 in reducing the pollution and emissions from the coal
14 plants, and we go through a process -- in fact, I recall
15 sitting on this very stand talking about that not too
16 long ago, so we go through an approval process and have
17 an open dialogue about that, so it is not the same as
18 just having over 2,000 megawatts show up overnight in
19 resources that we don't need and lock up our customers
20 for an obligation of 20 years of fixed prices, so they're
21 very different risks.
22
23
MS. NUNEZ: Okay, thank you.
COMMISSIONER KJELLANDER: Mr. Arkoosh, since
24 we're in your neighborhood, do you have any cross?
25 MR. ARKOOSH: No, thank you.
CSB REPORTING
[phone]
160 GROW (X)
Idaho Power Company
1 COMMISSIONER KJELLANDER: Thank you. Let's go
2 to Intermountain Energy Partners.
3 MR. MILLER: Thank you, Mr. Chairman, just a
4 few, if you don't mind.
5
6
7
8 BY MR. MILLER:
CROSS-EXAMINATION
9 Q. On the first page of your testimony, Ms. Grow,
10 you tell us that your current position with the Company
11 is vice president of delivery engineering and operations;
12 is that correct?
13 A. No, that's not correct. If you look on page 17
14 or line 17, excuse me, at the end, in 2009, I was
15 appointed to my current position of senior vice president
16 of power supply.
17 Q. There you go. My apologies for failing to
18 recognize your advancement.
19
20
A.
Q.
That's okay.
So in your current position as senior vice
21 president of power supply, you also tell us that you are
22 responsible for overseeing the operation and maintenance
23 of Idaho Power's generation fleet?
24
25
A.
Q.
I am.
And based on your responsibilities in that
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161 GROW (X)
Idaho Power Company
1 area, on page 3 you tell us that Idaho Power currently
2 has a nameplate generation capacity of nearly 3,600
3 megawatts?
4
5
A.
Q.
Correct, the Company-owned resources, yes.
In your capacity as senior vice president of
6 power supply, you also oversee in the Company persons
7 responsible for the Company's compliance with the Public
8 Utility Regulatory Policy Act of 1978, also known as
9 PURPA?
10
11
A.
Q.
I do oversee that, yes.
And in your capacity as senior vice president
12 of power supply, do you execute on behalf of the Company
13 energy sales agreements with qualifying facilities under
14 PURPA?
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16
A.
Q.
I do.
In the course of your responsibilities as
17 senior vice president, are you familiar with the phrase
18 "PURPA solar QF"?
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A.
Q.
A.
Q.
As a term, sure.
And what would you understand that phrase to
I would take that to mean a solar facility that
For discussion purposes, could we understand
23 qualifies for QF status.
21 mean?
25 that to mean qualifying facilities under PURPA that
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162 GROW (X)
Idaho Power Company
1 generate electrical energy through solar generation?
2
3
A.
Q.
I guess so.
Okay. With that understanding in mind and
4 taking into account your knowledge of the Idaho Power
5 system, what is the number of solar QFs in the State of
6 Idaho currently connected to the Idaho Power system and
7 capable of delivering energy to the Idaho Power system?
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15
16
A.
Q.
A.
At this point there are none online.
That would be zero?
That would be zero.
MR. MILLER: That's all I have.
COMMISSIONER KJELLANDER: Thank you, and I know
MS. HOWLAND: Yes.
COMMISSIONER KJELLANDER: Thank you. Are there
13 that in our initial proceedings Micron said that they
. 14 didn't have any cross, is that still the case?
17 any questions from the Commission? Commissioner Raper.
18 COMMISSIONER RAPER: I'm going to ask a
19 compound question. I'll tell Mr. Walker in advance so he
20 can object if he wants to.
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COMMISSIONER KJELLANDER: It would be unwise.
MR. WALKER: Noted.
THE WITNESS: I will have to answer, then.
CSB REPORTING
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163 GROW (X)
Idaho Power Company
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EXAMINATION
BY COMMISSIONER RAPER:
Q. Ms. Grow, in your testimony you talk about
lll(d) and the implications of your system on lll(d) and
specifically on page 10 you say, line 3, that your
well, let me read the whole sentence from line 1. "Idaho
Power has been in discussions with the joint owner of the
Valmy plant regarding the future of that plant and the
resource alternatives that could replace the generation
from that plant"; so my question is based on what we have
now as the proposed rule for lll(d), can QF energy of any
type, let's just say any IRP resource, be used to offset
the coal capacity that might be lost as a result of Idaho
Power's compliance with lll(d) and why or why not?
A. Well, it would be hard for me to say, because
there is no cap or limit to the amount of PURPA that
would show up, so if we're going to retire Valmy, that's
about 280 megawatts on our system and right now we have
PURPA contracts or requests all in, signed contracts,
those that are wind and small hydro that's already there,
over 2,000 megawatts, and so the fact that there's a
disconnect between need, what we might need to replace
Valmy, versus how much can just show up in PURPA is why
we're asking for the limit, so with two-year limits for
CSB REPORTING
[phone]
164 GROW (Com)
Idaho Power Company
more resources in PURPA to cover that and even then,
contracts, we believe it would better put the risk over
continuing to discuss the Valmy shutdown with our
there
It makes it very uncertain and that uncertainty
A coal plant can run 24/7 under almost any
really does not have the same operating characteristics
needed, like we do our resources, so it would be
intermittent nature is the other complicating factor.
uncertainty that our customers would have to sign up for
is some energy that you could say fills a need, but it
on the developers, and to the extent there is -- the
as a base load, nor does it have any limit that really
partners, but we're not sure when it will be, how much it
they breakdown, but it would -- you'd have to build a lot
is why we're here is that we're trying to reduce the
will be, so there's just a lot of uncertainty out
reliable way that we could call on it or turn it off as
dispatch it and be able to put it into our portfolio in a
enough capacity to be able to bring it on and be able to
again, at night, during cloudy days, there wouldn't be
we don't know what those rules are going to be, and we're
covers how much we would need to replace.
and bear for 20 years. Again, we go back to the lll(d),
there .
conditions, in fact, under all conditions, occasionally
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CSB REPORTING
[phone]
165 GROW (Com)
Idaho Power Company
1 Q. Thank you; so one last question, it wouldn't
2 change -- or, I guess, instead of leading you into
3 anything, would your testimony change or your position to
4 reduce contract limits change based on a final rule from
5 the EPA that would require earlier shutdown of the coal
6 plants?
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A. No, it would not.
COMMISSIONER RAPER: Thank you.
EXAMINATION
12 BY COMMISSIONER KJELLANDER:
13 Q. Ms. Grow, I just have a couple of clarifying
14 questions. You were asked a lot of questions from Mr.
15 Hammond in reference to the exhibit he presented and it
16 says draft all over it, draft IRP. When is the IRP
17 expected to be filed at the Commission?
18 A. That is in a matter of days, actually
19 tomorrow.
20
21
22
Q.
A.
Q.
Tomorrow?
Yes.
Okay; so based on the version that you saw
23 there and based on the areas in which you were
24 questioned, is it likely that the areas that you were
25 asked to respond to will in fact be in the final IRP
CSB REPORTING
[phone]
166 GROW (Com)
Idaho Power Company
1 that's presented to the Commission?
2
3
A. I believe so, yes.
COMMISSIONER KJELLANDER: Okay, thank you.
4 Let's move now to redirect.
5 MR. RICHARDSON: Mr. Chairman, before you go to
6 redirect, Peter Richardson with Clearwater Paper.
7 COMMISSIONER KJELLANDER: Oh, my apologizes. I
8 didn't know you were separated out, so my apologizes for
9 ignoring you. That was not my intent. Mr. Richardson.
10 MR. RICHARDSON: I just wanted to note that we
11 do not have any questions of Ms. Grow.
12 COMMISSIONER KJELLANDER: Thank you, Mr.
13 Richardson. I'll try not to skip over you next time, but
14 if I do and the response is the same, maybe I will.
15 Let's look now to redirect.
16
17
MR. WALKER: No redirect, Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you very much.
18 Ms. Grow, at least for now, you are excused and unless
19 your attorney would like to have you excused, without
20 objection, we'll have to wait for that; otherwise, you
21 may stand by just in case.
22 MR. WALKER: Mr. Chairman, we would ask, if we
23 could, that Ms. Grow be excused, if there's no
24 objection.
25 COMMISSIONER KJELLANDER: Is there any
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[phone]
167 GROW
Idaho Power Company
1 objection? If not, then you can be excused. Thank you.
2
3
4
THE WITNESS: Thank you.
(The witness left the stand.)
COMMISSIONER KJELLANDER: Would you like to
5 call your next witness?
6 MR. WALKER: Thank you, Mr. Chairman. Idaho
7 Power would like to call as its next witness Mr. Randy
8 Allphin.
9 COMMISSIONER KJELLANDER: As you are moving up,
10 before we swear you in, I've been told perhaps we might
11 want to take just a quick break, so why don't we do so
12 and we'll take about 10 minutes.
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14
15
MR. WALKER: Thank you, Mr. Chairman.
(Recess.)
COMMISSIONER KJELLANDER: We will be back on
16 the record and as we return to the record, the second
17 witness for Idaho Power has been called forward and we're
18 ready now for Randy Allphin to take the stand.
19
20 RANDY ALLPHIN,
21 produced as a witness at the instance of Idaho Power
22 Company, having been first duly sworn to tell the truth,
23 the whole truth, and nothing but the truth, was examined
24 and testified as follows:
25
CSB REPORTING
[phone]
168 COLLOQUY
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MS. OLSEN: Mr. Chairman, before you get
started with questioning, the Idaho Irrigation Pumpers
wondered if we could just talk about some witness
scheduling issues.
COMMISSIONER KJELLANDER: Excellent, Mr. Olsen.
Please proceed.
MR. OLSEN: At least with our witness, Mr.
Yankel has some back issues and we would appreciate the
Chair's indulgence of allowing him to get on as soon as
possible so we could certainly spread his testimony and
see if there's any questions so he could be in a more
comfortable situation with his medical issues.
COMMISSIONER KJELLANDER: Certainly, thank you.
Are there any objections to moving Mr. Yankel upon the
conclusion of this witness? None? Thank you. If you
could just remind me that that is the case. Are there
any other witnesses as far as the order that we have in
reference to their availability today or any other
considerations as we --
MR. SANGER: Yes, Chairman Kjellander, this is
Irion Sanger with the Renewable Energy Coalition
COMMISSIONER KJELLANDER: Yes.
MR. SANGER: -- and Mr. Lowe, John Lowe, is our
witness and he also has some health issues and we would
like to get him on the witness stand as soon as possible
CSB REPORTING
[phone]
169 COLLOQUY
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today.
COMMISSIONER KJELLANDER: That is good. Anyone
else?
MR. OTTO: Yes, Benjamin Otto with the
Conservation League and Sierra Club. Both of my
witnesses are from out of town, one from D.C. and the
other from Oakland, they're available all day, so
hopefully, we can have them on at some point today.
COMMISSIONER KJELLANDER: The Tourism Bureau
would love it if they didn't come up until tomorrow.
MR. OTTO: Yes, I understand that.
COMMISSIONER KJELLANDER: All right.
MR. MILLER: Mr. Chairman, our witness, Mr. Van
Gulik, is available at the call of the Commission. He
has some other matters he's attending to at the moment
and he's completely flexible, but if I just had a little
bit of an advance notice of when you'd like to hear from
Mr. Van Gulik, that would be appreciated.
COMMISSIONER KJELLANDER: And is Mr. Van Gulik
here today?
MR. MILLER: He was here and had to leave for a
few minutes, but he can be back kind of basically at the
call of the Commission .
COMMISSIONER KJELLANDER: Remind me to remind
you.
CSB REPORTING
[phone]
170 COLLOQUY
1
2
MR. MILLER: I'll let you know.
COMMISSIONER KJELLANDER: Thank you. Anything
3 else? Okay, thank you, let's proceed.
4
5
6
7 BY MR. WALKER:
DIRECT EXAMINATION
8 Q. Could you please state your name and spell your
9 last name for the record?
10
11
A.
Q.
Randy Allphin, A-1-1-p-h-i-n.
And by whom are you employed and in what
12 capacity?
13 A. I'm employed by Idaho Power Company as the
14 energy contracts coordinator leader.
15 Q. Are you the same Randy Allphin that filed
16 direct testimony on January 30th, 2015, and prepared
17 Exhibits No. 1 through 10?
18
19
A.
Q.
Yes.
And are you the same Randy Allphin that filed
20 rebuttal testimony on June 11th, 2015?
21
22
A.
Q.
Yes.
And did you also file an Exhibit No. 11 on June
23 19th, 2015?
24
25
A. Yes.
MR. WALKER: And Mr. Chairman, let the record
CSB REPORTING
[phone]
171 ALLPHIN (Di)
Idaho Power Company
specifically Exhibit 1, 3, and 9 .
A. Yes.
9.
tell us what is contained in Exhibit No. 11?
Yes.
And Mr. Allphin, the four pages of Exhibit
Yes, the pages in Exhibit 11 reflect updated
do they have any relation to Exhibits 1 through
A. Yes, I'm sorry, back to back.
Q. And your testimony and Exhibits 1 through 10
A. Exhibit 11 consists of three pages that provide
Q. And excuse me, but doesn't Exhibit 11 actually
Q. And Exhibit 11 provides certain numbers and
Q. BY MR. WALKER: Mr. Allphin, could you please
COMMISSIONER KJELLANDER: Duly noted, thank
A.
Q.
No. 11,
10?
A.
values that will be carried through all the exhibits, but
values as of April 2015?
updated values corresponding to my Exhibits 1, 3, and
contain certain numbers and values as of January 2015?
Allphin's Exhibit No. 11 and I've also handed the court
you.
reflect that Idaho Power prefiled on June 19th Mr.
reporter a copy of that Exhibit No. 11 at hearing.
contain four pages?
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CSB REPORTING
(208} 890-5198
172 ALLPHIN (Di)
Idaho Power Company
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Q. So page 1 generally corresponds to Exhibit
No. 1?
A. Yes.
Q. And what about page 2, is there a corresponding
exhibit that that corresponds to?
A. Yes, page 2 corresponds to Exhibit 9.
Q. And what about page 3 and 4?
A. Page 3 and 4 correspond to Exhibit 3.
Q. Do you have any corrections or changes to your
testimony or exhibits?
A. No. My testimony and Exhibits 1 through 10 are
correct as of January 2015 and Exhibit 11 updates the
total megawatts and dollars of projects under contract
and seeking contracts as of April 2015.
Q. If I were to ask you the questions set out in
your prefiled testimony, would your answers be the same
here today?
A. Yes.
MR. WALKER: Mr. Chairman, I'd move that the
prefiled direct and rebuttal testimony of Mr. Randy
Allphin be spread upon the record as if read and that
Exhibits 1 through 11 be marked for identification.
COMMISSIONER KJELLANDER: Without objection,
then, the exhibits will be marked for identification and
the rebuttal and direct will be spread across the record
CSB REPORTING
[phone]
173 ALLPHIN (Di)
Idaho Power Company
1 as if read.
2 MR. WALKER: Thank you, Mr. Chairman.
3 (The following prefiled direct and rebuttal
4 testimony of Mr. Randy Allphin is spread upon the
5 record.)
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CSB REPORTING
[phone]
174 ALLPHIN (Di)
Idaho Power Company
Leader.
is 1221 West Idaho Street, Boise, Idaho 83702.
Q. Please state your name and business address .
work experience with Idaho Power.
In June
A. I graduated in 1982 from Boise State University
A. My name is Randy Allphin. My business address
Q. By whom are you employed and in what capacity?
A. I am employed by Idaho Power Company ("Idaho
Q. Please describe your educational background and
with a Bachelor of Business Administration.
Power" or "Company") as the Energy Contracts Coordinator
responsibilities were accounting for and performing
position as an Operations Accountant in the Operations
Specialist with Idaho Power. In 1986, I accepted a
1982, I accepted a position as a Customer Service
and Fuels Management accounting group. My specific
Administrator. In 2010, I was promoted to Senior Energy
and thermal operations and maintenance accounting. In
1998, in addition to the responsibility of performing the
accounting and economic analysis of QF agreements, I was
also assigned the responsibility of administering all
aspects of existing and new QF agreements as the
economic analyses of the Company's agreements with
Qualifying Facilities ("QF"}, as well as fuels accounting
Cogeneration and Small Power Production ("CSPP") Contract
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Contracts Administrator and was assigned two direct
reports to manage the large number of Idaho Power QF and
other renewable energy agreements. I have been involved
with accounting, economic analysis, contract
administration, and contract negotiations of Idaho Power
QF and renewable energy agreements for approximately 30
years. In addition, I was responsible for the initial
implementation of Idaho Power's Oregon Solar Photovoltaic
Pilot Program and currently am assigned supervisory
oversight of the administration of that program.
Q. What is the purpose of your testimony in this
matter?
A. The purpose of my testimony is to provide a
surrunary of the development of Public Utility Regulatory
Policies Act of 1978 ("PURPA") QF generation projects on
Idaho Power's system and to surrunarize the current status
of contracts, requests for contracts, inquiries, pricing
requests, etc., related to PURPA energy sales agreements,
obligations, and proposed QF projects with Idaho Power.
My testimony is submitted in support of Idaho Power's
Petition to Modify Terms and Conditions of Prospective
PURPA Energy Sales Agreements asking to reduce the
maximum term of prospective PURPA energy sales agreements
with Idaho Power from 20 years to a maximum of 2 years.
Q. Have you prepared any exhibits?
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A. Yes. I am sponsoring 10 exhibits that were
either prepared by me or prepared at my direction.
Q. Could you describe those exhibits?
A. Yes. Exhibit No. 1 is a graphical depiction of
the current and historical energy sales agreements that
Idaho Power has been required to enter into with QF
generation projects pursuant to PURPA. This graph
identifies the amount, in megawatts ("MW"), by year and
by resource type of signed and approved energy sales
agreements with PURPA QFs. It also identifies current
requests for contracts from proposed PURPA solar QFs.
This graph separately identifies the MW levels of PURPA
projects under contract and operational as of January 9,
2015 - 781 MW; the additional PURPA solar projects that
are under contract as of January 9, 2015, but not yet
operational - 461 MW; and the additional PURPA projects
that as of January 9, 2015, have made formal, written
requests for PURPA energy sales agreements with Idaho
Power - 885 MW. Exhibit No. 1 identifies the total
amount of PURPA projects, 2,187 MW, that have formally
requested contracts, are under contract, and are under
contract and operational.
Exhibit No. 2 is a complete listing of all active
renewable energy contracts that Idaho Power has as of
January 26, 2015. Page 1 of Exhibit No. 2 is a summary
page showing the total number and total MW of renewable
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energy contracts, breaking those totals down by resource
type and jurisdiction, showing which projects are
operational, and separately identifying PURPA QF projects
and non-PURPA projects. The remaining pages of Exhibit
No. 2, pages 2 through 7, provide the detail summarized
on page 1. Each individual project is listed by project
number (which is an internal tracking number for Idaho
Power) and identified by resource type, project name,
location by state and county, and the MW nameplate
capacity. The individual projects are grouped by
resource type, with subtotals for the number of
individual projects and the total MW for each resource
type.
Q. Do you have any information concerning any
additional PURPA QF projects seeking to contract with, or
obligate, Idaho Power to PURPA energy sales agreements?
A. Yes. Exhibit No. 3 shows each individual
proposed PURPA QF solar project that has submitted a
written request for indicative pricing from Idaho Power
for an energy sales agreement. There are 48 individual
projects, for a total of 885 MW that have submitted such
requests. Because the identity of the project developers
and their specific projects are not public record prior
to such time as they have obtained an executed contract
that is filed with the Idaho Public Utilities Conunission
178 ALLPHIN, DI 4
Idaho Power Company
1 for its approval or rejection, the project developers'
2 identities
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and names of projects have been removed. However,
because in almost all cases a single developer has
proposed several separate projects, a generic identifier;
i.e., Developer A, Project Al, Project A2, etc.,
Developer B, Project Bl, Project 82, etc., has been used.
Exhibit No. 3 also shows each project's size in MW, the
project's requested contractual term, the location by
state, the project's estimated operation date, and the
estimated 20-year and 2-year contractual obligation in
dollars.
Q. Does Idaho Power have any other requests for
PURPA energy sales agreements besides those shown in
Exhibit No. 3?
A. Yes. In addition to those 48 projects that
have submitted written requests for indicative pricing
pursuant to Schedule 73, Idaho Power has received
numerous other inquiries requesting energy sales
agreements for significant amounts of PURPA generation.
However, in the preparation of my exhibits, it was
necessary for the Company to select a point in time and
take a snapshot of the current proposed projects at that
point in time. This snapshot was at the time when the
Company had 48 solar project requests for a total of 885
MW, which are depicted in Exhibit No. 3. Since that
point in time, the Company has continued to receive
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numerous requests for additional PURPA QF energy sales
agreements.
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Q. What are some of those additional requests that
are not shown in Exhibit No. 3?
A. Over the last several weeks, Idaho Power has
received requests for eight additional PURPA solar
agreements totaling 186 MW, a request from a single
developer for five 80 MW pumped storage hydroelectric
PURPA energy sales agreements totaling 400 MW, and
numerous other energy sales agreement inquires.
Additional project requests for generator interconnection
have also been received, in excess of an additional 200
MW, in which the projects have stated their desire to
sell QF energy to the Company; however, these projects
have not yet requested QF energy sales agreements.
Q. Do you have other exhibits?
A. Yes. Exhibit No. 4 shows the estimated
contractual obligations of Idaho Power's cogeneration and
small power production QF contract obligations. This
exhibit is broken out by time period, by signed and
proposed contracts, and by resource type.
Q. Has Idaho Power done any comparisons of its
renewable generation to the renewable portfolio standards
of other states?
A. Yes. Exhibit No. 5 is a chart that depicts a
comparison of Idaho Power renewable generation resources
to the renewable portfolio standard ("RPS") or renewable
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portfolio goal ("RPG") of Idaho Power's neighboring
states of Montana, Washington, Utah, Nevada, and Oregon -
and to that of California.
Q. Could you further describe what is shown in
Exhibit No. 5?
A. Yes. Idaho Power does not have any current
requirements for a RPS or RPG in the state of Idaho, but
what is shown by Exhibit No. 5 is that with only its
currently existing PURPA and utility renewable energy
power purchase agreement ("PPA") resources, the Company
would meet a renewable energy standard of 20 percent of
retail load (megawatt-hours ("MWh")) supplied by
renewable energy (MWh). Exhibit No. 5 also depicts an
estimated renewable energy level for Idaho Power,
calculated as percent of retail load in MWh supplied by
renewable energy in MWh, for four additional scenarios:
Idaho Power's actual PURPA and utility renewable energy
PPAs plus the 461 MW of PURPA solar under contract - 24
percent; Idaho Power's actual PURPA and utility renewable
energy PPAs plus the 461 MW of PURPA solar under contract
plus the 885 MW of PURPA solar proposed - 37 percent;
Idaho Power's actual PURPA and utility renewable energy
PPAs, 461 MW of PURPA solar under contract, plus Idaho
Power's Company-owned hydro generation - 77 percent, and,
finally, Idaho Power's actual PURPA and utility renewable
energy PPAs, 461 MW of PURPA solar under
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contract, 885 MW of PURPA solar proposed, plus all of
Idaho Power's Company-owned hydro generation - 90
percent. The latter two scenarios depict that if Idaho
Power's 1,709 MW of hydroelectric nameplate capacity were
combined with the Company's acquired renewable capacity,
which would represent over 3,100 MW of renewable
generation capacity, it would equate to 90 percent of
retail load supplied by renewable energy. In fact, if
the Company's PURPA generation, including PURPA solar
under contract and proposed, were considered, Idaho Power
would exceed the RPS requirements of its neighboring
western states, as well as California, at 37 percent of
retail load supplied by renewable energy.1
Q. Have you conducted, or directed, any analysis
of Idaho Power's PURPA generation?
A. Yes. Using information from Idaho Power's Load
Serving Operations Group, I have prepared Exhibit No. 6.
Exhibit No. 6 is a series of graphs consisting of 24
separate graphs, one per page, which depict the first
week of each month for the years 2016 and 2017 and one
summary page. These graphs depict an analysis conducted
by Idaho
Ill
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1 This comparison is done to show the magnitude of QF
development and Company-owned hydro compared to various mandatory RPS
requirements. Because Idaho Power does not receive the Renewable
Energy Certificates/Credits ("RECs") from most of its QF generation,
this generation cannot be used to meet any potential RPS requirements
and Idaho Power cannot represent to customers that they are receiving
renewable energy from the QFs, or from generation, for which it does
not receive the RECs, and is not making any such representation here.
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Power which compares estimated total system load, on an
hourly basis, over 2016 and 2017, to the Company's
must-run resources, must-take PURPA generation, and
must-take non-PURPA power purchase agreements. The
estimated load is taken directly from the Company's
operational forecast. The must-run Company-owned
resources are comprised of Idaho Power's hydro and coal
generation, and are represented at must-run minimum
levels. This means that they are taken down to minimum
operational levels where they cannot be backed down any
further without violating environmental regulations for
hydro, and without being shut down for coal. Must-take
PURPA and non-PURPA purchases are taken from Idaho Power
forecasted generation from the various PURPA projects
currently under contract with Idaho Power. This forecast
is a combination of historical generation information
from existing projects and project-provided estimated
generation as contained within the contracts. There is
no gas, market purchases, market sales, or other
generation depicted on the graphs or analysis.
Q. What is shown by this analysis?
A. This analysis shows the frequency with which
Idaho Power's system, when in a state where it cannot be
backed down any further, will have generation resources
in excess of its system load. This will put the system
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into an imbalanced, over-generation state unless some
remedial
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2016 and 2017, in which Idaho Power's must-run and
A. The summary page of Exhibit No. 6 shows the
action is taken to balance the system. If remedial
durations, and are removed as soon as possible once it
(1) Idaho Power's
Q. What is the frequency of hours, over the years
violations, events, and/or outages and damage. In fact,
PURPA generation have been necessary in order to maintain
the integrity of Idaho Power's system. For the period
have been relatively infrequent, for relatively short
actions are not available, or not employed in a timely
from May 2011 through December 2014, the Company has had
manner, then the Company can have system reliability
generation output reductions in order to maintain the
over the last several years, reliability curtailments of
must-take resources exceed total system load?
reliable operation of the Company's electrical system.
at least 15 reliability events that resulted in wind
These curtailments, or generation limitation set points,
PURPA generation - 2,492 hours, or 14 percent, of all
17,544 hours during 2016
frequency of hours in which must-run and must-take
can safely be done and maintain a balanced system.
generation will exceed total system load, and is broken
must-take power purchases, without the addition of any
out into four categories:
Company-owned must-run hydro and coal plus non-PURPA
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188 ALLPHIN, DI 10
Idaho Power Company
1 and 2017; (2) everything included in category 1 plus all
2 existing PURPA generation (excluding solar) - 5,120
3 hours, or 29 percent, of all 17,544 hours during 2016 and
4 2017; (3) everything included in category 2 plus all
5 PURPA under contract (including PURPA solar under
6 contract - 461 MW) - 5,709 hours, or 33 percent, of all
7 17,544 hours during 2016 and 2017; and last, (4)
8 everything in category 3 plus the 885 MW of proposed
9 PURPA solar - 6,952 hours, or 40 percent, of all 17,544
10 hours during 2016 and 2017. Each one of these hours
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12 action of some kind will be necessary to keep the system
13 in balance and meet the obligation to reliably serve
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Q.
A.
Can you describe your remaining exhibits?
Yes. Exhibit No. 7 shows the annual actual and
17 forecasted PURPA expense from 2004 through 2025, which
18 increases from approximately $40 million in 2004 to
19 approximately $230 million in 2025. This is an
20 approximate 575 percent increase over those 22 years.
21 Exhibit No. 8 shows the approved net power supply expense
22 included in Idaho Power's base rates on a normalized
23 basis for 2010, 2012, and 2013.
24 Q. What costs have been included in base rates for
25 net power supply expenses over those years?
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A. Exhibit No. 8 shows the major Federal Energy
Regulatory Commission ("FERC") accounts for net power
supply expenses that have been included in base rates
since 2010. The major FERC accounts include Account 501,
Coal; Account 547, Gas; Account 555, Purchases; and
Account 447; Surplus Sales. Account 555, Purchases, has
been split into two separate line items, one for
purchases that are non-PURPA related and the other for
purchases of PURPA generation.
Q. What do these numbers reflect with regard to
the relationship of purchases for PURPA compared to the
other cost components of net power supply expense?
A. It has been suggested that even though PURPA
generation may not be needed to meet current customer
load, it can be assumed that the excess generation could
be sold as surplus sales, and therefore benefit the
customer by a reduction on net power supply expense.
Based upon the dollars included in base rates that are
reflected in Exhibit No. 8, this assumption would not be
accurate. In fact, even though net power supply expenses
associated with the purchase of PURPA have increased,
surplus sales have decreased, both in volume and in
dollars. The gap between the cost per MWh of PURPA and
the price for surplus sales has widened, meaning that the
average price included in base rates that the Company
must pay to purchase PURPA
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generation even though it is not needed to meet load is
greater than the price the Company could sell that same
generation on the market. Customers are adversely
impacted by having to pay for generation that is not
needed to serve load while decreasing the amount of the
surplus sales credit offset.
Q. Why have surplus sales decreased so much in
recent years, both in terms of dollars and volume?
A. There may be a number of reasons for the
reduction in surplus sales. One reason may be the
increased amount of available generation in the Pacific
Northwest, much of it due to the increase in wind and
solar generation. Another major reason for the lower
price of surplus sales may be the cost of gas, which has
decreased significantly over the past several years. The
bottom line is that it may not be prudent to lock in
long-term pricing for generation at a time when overall
costs for technology and fuel are decreasing.
Q. What is the relationship of the cost for PURPA
generation compared to the costs of the other components
of net power supply expense?
A. As shown in Exhibit No. 8, the cost of
purchases of PURPA generation contained in base rates, on
a dollars per MWh basis, is now greater than all the
other cost components. At $62.49 per MWh, the average
cost of
191 ALLPHIN, DI 13
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PURPA purchases is greater than the average cost of coal
at $22.79 per MWh, greater than gas at $33.57 per MWh,
greater than non-PURPA purchases of $50.64 per MWh, and
significantly greater than what is being sold as surplus
sales at $22.41 per MWh.
Q. What is the implication of these pricing
differences and the potential impact on the Company's
customers?
A. If the Company is required to purchase PURPA
generation when it is not needed, the Company may be
required to curtail other less expensive sources of
generation or market purchases in order to continue
purchasing PURPA generation at a higher cost. This would
mean that the Company's overall net power supply expense,
on a dollars per MWh basis, would increase, adversely
impacting the customer.
Q. Are you presenting any other exhibits?
A. Yes. The last two exhibits I am sponsoring are
Exhibit Nos. 9 and 10. Exhibit No. 9 is similar to
Exhibit No. 3, except the information is for PUPRA solar
projects that are under contract as of January 20, 2015.
Each project is listed individually by name. Exhibit No.
9 shows each project's size in MW, the term of the
contracts (which are all for 20 years), the location by
state, the scheduled operation date (which is 2016 for
all projects),
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and the estimated contractual obligation for both a
20-year term and 2-year term in dollars.
Exhibit No. 10 is a graphical depiction of the average
actual per MWh cost of PURPA energy purchases and Mid-C
market prices through year-end 2014 and the same two
values forecasted through 2030.
Q. Does this conclude your testimony?
A. Yes.
193 ALLPHIN, DI 15
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Q. Please state your name and business address.
A. My name is Randy Allphin. My business address
is 1221 West Idaho Street, Boise, Idaho 83702.
Q. By whom are you employed and in what capacity?
A. I am employed by Idaho Power Company ("Idaho
Power" or "Company") as the Energy Contracts Coordinator
Leader .
Q. Are you the same Randy Allphin that previously
provided direct testimony for Idaho Power in this matter?
A. Yes.
Q. What is the purpose of your rebuttal testimony?
A. My rebuttal testimony will provide Idaho
Power's response and rebuttal to the testimony offered by
the other parties in this proceeding.
Q. Have you had the opportunity to review the
pre-filed direct and rebuttal testimony of the other
parties to this proceeding, including the Idaho
Conservation League and the Sierra Club's witnesses R.
Thomas Beach and Adam Wenner; the Idaho Public Utilities
Commission ("Commission") Staff's ("Staff") witnesses
Rick Sterling and Yao Yin; J. R. Simplot Company
("Simplot") and Clearwater Paper Corporation's
("Clearwater") witness Mr. Don Reading; Intermountain
Energy Partners, LLC's witness Mark Van Gulik; Renewable
Energy Coalition's witness John
194 ALLPHIN, REB 1
Idaho Power Company
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R. Lowe; Snake River Alliance's witness Ken Miller; and
the Idaho Irrigation Pumpers Association, Inc. 's ( "IIPA")
witness Anthony J. Yankel?
A. Yes, I have. I have also reviewed the
testimony offered by the other utilities, Avista
Corporation and Rocky Mountain Power, d/b/a PacifiCorp.
Q. Please summarize what your rebuttal testimony
will address.
A. Commission Staff supported the Company's
request to reduce the maximum contract term, but suggests
a maximum term of five years, as opposed to Idaho Power's
requested maximum term of two years. IIPA also supported
Idaho Power's request to reduce the maximum contract term
to two years. In general, the remaining parties opposed
Idaho Power's request. Several Intervenors question the
Commission's authority to reduce the maximum contract
term, present argument that a shorter term will prevent
Qualifying Facility ("QF") financing for new projects,
and argue that granting a shorter term for QF contracts
would result in unequal treatment between QFs and
utility-owned resources, along with several other
arguments. Various Intervenors proposed, as an
alternative, a 20-year contract term with a fixed-price
portion of the 20-year term and the remaining term having
some type of price adjustment. I
195 ALLPHIN, REB 2
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will address many of these issues in this rebuttal
testimony.
Q. Do the parties that oppose reduction in the
contract term address the issues raised by Idaho Power
related to no current need for additional generation
resources?
A. No. None of the parties opposing the requested
reduction in maximum authorized contract term have
addressed the larger issues related to need for
additional generation resources and the disproportionate
amount of risk that long-term, fixed-rate, unchangeable
QF contracts place upon Idaho Power's customers without
the benefit of the Commission's or the public's scrutiny
of its acquisition, like Company-owned resources must
endure.
Q. Staff references in its rebuttal testimony the
fact that various witnesses have suggested there is
unequal treatment between QFs and utility-owned
resources, and Mr. Reading, on page 9 of his direct
testimony, states, "Treating PURPA resources on an equal
footing with utility-owned resources would mandate they
also should receive longer-term contracts." What is
Idaho Power's position and response on this issue?
A. Idaho Power generally agrees with the
statements and position of Staff, which acknowledges that
QFs and utility-owned resources are not treated the same.
196 ALLPHIN, REB 3
Idaho Power Company
1 The other parties make the erroneous assumption that QFs
2 are to be treated exactly the same as utility-owned
3 resources. However, Staff points out that QFs are
4 treated differently primarily because of the unique
5 requirements of the Public Utility Regulatory Policies
6 Act of 1978 ("PURPA") and that this different treatment
7 is very much to the benefit, rather than to the
8 detriment, of the QF. Idaho Power submits that if a QF
9 were subjected to the same regulatory standards and its
10 acquisition and cost was scrutinized in the same manner
11 as a utility-owned resource, then it could expect similar
12 treatment. However, that is not the present reality. A
13 utility-owned resource is only considered in the first
14 instance if there is a need for the acquisition of
15 additional generation resources to reliably serve
16 customers. Presently, a QF project would fail this
17 initial standard and thus would not be purchased.
18 Additionally, beyond an initial identification of need,
19 utility-owned resources are subjected to further
20 evaluations of selecting the appropriate type of
21 resource. The operational characteristics, reliability,
22 costs, and other relevant aspects of whether any
23 particular resource is the most appropriate resource must
24 be determined before seeking Commission approval to
25 construct such resource. Even further, once constructed,
197 ALLPHIN, REB 4
Idaho Power Company
1 the utility-owned resource is subjected to further
2 Com.mission and public scrutiny in a
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198 ALLPHIN, REB 4a
Idaho Power Company
1 proceeding to place it into the utility's rate base, and
2 on an on-going, annual basis with regard to the fuel and
3 variable cost, which are subject to annual adjustment
4 through the Power Cost Adjustment. Consequently, the
5 argument that the QF is somehow entitled to the same type
6 of capital cost recovery as a utility-owned resource
7 simply does not logically make sense.
8 Q. Are there other examples of the parties'
9 inappropriate comparison of QF resources to utility-owned
10 resources?
11 A. Yes. Mr. Reading, on pages 24 through 26 of
12 his direct testimony, attempts to argue that because
13 PURPA projects get paid only when they supply power to
14 the utility, they are somehow a better value and "risk
15 hedge" than a utility-owned resource. This may seem to
16 make sense on the surface, but Mr. Reading leaves out an
17 important aspect of the operational differences between a
18 PURPA project and a utility-owned resource, which makes
19 all the difference. Utility-owned resources are
20 economically dispatched, or only run when they are less
21 costly that other alternatives or when they can be sold
22 at a profit. However, a PURPA generator will run as
23 much, and as often, as it can to maximize its
24 profits-without regard to whether it is needed and
25 without regard to the availability of other lower-cost
resources. Utility-owned resources are
199 ALLPHIN, REB 5
Idaho Power Company
1 only constructed and operated to serve the public
2 interest, a factor that is closely monitored, regulated,
3 and controlled by the Commission. QF resources are
4 constructed and operated solely to make a profit for its
5 owners/investors, with no constraint or obligation to
6 serve in the public interest. Because of PURPA's
7 must-purchase obligation-and because the QF is motivated
8 to maximize its profits and not concerned with meeting
9 need on a least-cost, reliable basis-the utility must
10 accept the QF generation if, when, and in whatever
11 amounts the QF decides to put to the utility. This can
12 result in the utility foregoing the operation of its
13 lower-cost resources, acquired after careful Commission
14 scrutiny to serve the public, in order to take the power
15 that is put to it by the QF. This situation can only
16 grow in magnitude as more must-take PURPA is forced onto
17 the system at a time when the utility's Integrated
18 Resource Plan ("IRP") shows no need for additional
19 generation resources to meet need/load.
20 Q. Mr. Reading attempts to make a cost comparison
21 of PURPA resources and Idaho Power's thermal generation
22 resources on pages 14 and 15 of his direct testimony.
23 Has Idaho Power reviewed Chart 1 on page 15 of Mr.
24 Reading's direct testimony?
25 A. Yes.
200 ALLPHIN, REB 6
Idaho Power Company
1 Q. Was Idaho Power able to replicate all of the
2 values presented by Mr. Reading in that chart?
3 A. No, not all of them. Idaho Power was able to
4 replicate all of the values except the value presented
5 for the Bennett Mountain generation unit. Mr. Reading's
6 Chart 1 presents a cost per megawatt-hour ("MWh") for the
7 Bennett Mountain generation unit of $253.87. He cites
8 the sources of the numbers as being from the Company's
9 2013 Federal Energy Regulatory Commission ("FERC") Form 1
10 as well as some Company responses to Simplot's production
11 requests. Using those same resources, Idaho Power was
12 able to validate all of the other numbers in Chart 1, but
13 for the Bennett Mountain generation unit. Using the same
14 assumptions as Mr. Reading, Idaho Power calculated a cost
15 per MWh of $171.28.
16 Q. What is Mr. Reading attempting to demonstrate
17 with the numbers shown in Chart 1 of his testimony?
18 A. Mr. Reading is responding to Exhibit No. 10 of
19 my direct testimony, which is a graphical depiction of
20 the average actual cost per MWh of PURPA energy purchases
21 and Mid-C market prices through year-end 2014 and the
22 same two values forecasted through 2030. I provided
23 Exhibit No. 10 as support for the statement that if the
24 Company is required to purchase PURPA generation when it
25 is not needed, the Company may be required to curtail
201 ALLPHIN, REB 7
Idaho Power Company
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202 ALLPHIN, REB 7a
Idaho Power Company
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expensive sources of generation or market purchases in
order to continue purchasing PURPA generation at a higher
cost. Allphin, DI p. 14. Exhibit No. 10 shows that the
average PURPA price is greater than the Mid-C Index in
all years, both historically and forecasted.
Q. Does Mr. Reading agree with the Company's
conclusion?
A. No. Mr. Reading claims that the Company is
only "telling half of the story." Mr. Reading does not
dispute the information provided in Exhibit No. 10, which
shows that historical Mid-C prices have been lower than
PURPA prices since 2002 to the present and are projected
by Idaho Power to be lower over the next 20 years.
However, Mr. Reading claims that is just the first half
of the story. He claims this comparison fails to
recognize that capital costs are included in the per MWh
price of PURPA, and suggests that Mid-C prices are market
prices and are more reasonably related to the variable
running costs of existing generating resources that do
not contain capital costs.
Q. What does Mr. Reading believe is the
appropriate comparison to PURPA prices?
A. Mr. Reading believes a more appropriate
analysis would be comparing PURPA rates to what he claims
customers pay for in the Company's own generation
203 ALLPHIN, REB 8
Idaho Power Company
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facilities, by including rate-based capital costs along
with fixed and variable operating costs.
Q. Is this an appropriate comparison?
A. No, not at all. Mr. Reading is attempting to
mislead the Commission by using an inappropriate
comparison of the cost for the must-take PURPA energy on
a cost per MWh basis compared to all of the Company's
thermal generating resources, regardless if they provide
baseload generation or are a peaking resource, which are
only used when needed to meet system load and/or are
economically viable to run. Mr. Reading provides his
Chart 1 (including the erroneous Bennett Mountain
calculation) to try and demonstrate his assertion that if
you include the capital costs of the Company's thermal
resources, it would show PURPA is lower cost than many of
the Company's generating resources. However, the
Company's peaking resources were planned to operate only
on an as-needed basis, at times when it is necessary to
meet the Company's system peak and/or they are
economically viable to run. Consequently, when you
include the capital costs of a peaking resource with the
variable costs of running the plant, divided by the net
generation for the plant, the average cost per MWh for
the peaking resource will be greater than other resources
with greater MWh of output.
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204 ALLPHIN, REB 9
Idaho Power Company
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The peaking resources were specifically built to meet
capacity, rather than energy needs.
Q. Does Mr. Reading discuss the various processes
undertaken by the Company in determining the need for an
additional generation resource or the type of resource
needed?
A. No. Mr. Reading completely ignores the fact
that, unlike PURPA resources, the Company's generation
resources, like the peaking plants I just described, were
determined to be needed prior to being built and endured
significant public scrutiny through the required IRP
planning process, as well as achieving regulatory
approval through a Certificate of Public Convenience and
Necessity (CPCN) hearing that determined the need for
that resource at the time it was built. Further, before
being placed into rates, Idaho Power has to prove before
the Commission that the expenditures in these plants were
prudently incurred. As I referenced earlier in my
testimony, PURPA projects are not subject to this same
scrutiny and determination of need.
Q. Does Mr. Reading's comparison appropriately
reflect the potential customer impact of Idaho Power's
forced purchase of unneeded PURPA generation?
A. No. My testimony and this filing address the
future impact to customers' rates, and the undue
inflation
205 ALLPHIN, REB 10
Idaho Power Company
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of those rates if the Company is forced to purchase
energy it does not need at prices higher than those of
alternative resources. The capital costs for existing
resources that Mr. Reading includes in his analysis are
inappropriate given current operating conditions, and
distort potential customer impacts in a manner that
inaccurately depicts PURPA as a relatively low-cost
option.
Q. Please explain.
A. The capital costs associated with Idaho Power's
existing generation facilities are already embedded in
rates and, as described above, were only authorized for
recovery after thorough regulatory review and scrutiny by
the Commission, the public, and intervening parties.
These facilities were ultimately determined to be in the
public interest, and currently operate to reliably meet
Idaho Power's load requirements 24 hours a day, 7 days a
week, 365 days a year.
On a going forward basis, as identified in Idaho
Power's recent draft of its 2015 IRP just released on the
Company's website, the IRP analysis has identified for
the preferred portfolio no need for additional generation
resources in the near term. The first year a capacity
deficiency exists is in 2025, while the first energy
deficient period is in 2026. Therefore, the true impact
• 206 ALLPHIN, REB 11
Idaho Power Company
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to customers' bills over that time period will reflect
how
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Idaho Power Company
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Idaho Power utilizes existing generation resources
(Company-owned, existing PURPA, market purchases) to meet
customer need, as well as any additional PURPA generation
it is required to purchase. An accurate cost comparison
should reflect current operating conditions and the
reality of these circumstances, an area in which Mr.
Reading's analysis fails.
By including capital costs associated with plants
that are already meeting customer need, Mr. Reading's
analysis distorts the potential impact to customers by
inappropriately combining embedded capital costs
associated with existing facilities and incremental costs
associated with new unneeded PURPA resources. In doing
so, the resultant prices do not indicate the lowest-cost
future course of action, because they include
construction costs associated with resources that have
already been constructed, and compare them to incremental
costs that have yet to be incurred. When evaluating
future customer impacts, embedded costs should not be
compared to incremental costs, as they do not reflect
cost increases customers will face if Idaho Power is
forced to purchase unneeded PURPA generation.
Q. Why should the figures in your Exhibit No. 10
table be relied upon by the Commission rather than Mr.
Reading's analysis?
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208 ALLPHIN, REB 12
Idaho Power Company
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A. Unlike Mr. Reading's figures, the cost
comparison provided in Exhibit No. 10 reflects a
realistic expectation of the future impact to customers.
Given the lack of need for new capital resources in the
next 10 years, the cost to serve customers over that time
period will reflect how Idaho Power operates existing
Company-owned resources in conjunction with must-take
PURPA and market purchases. For comparison purposes,
Idaho Power provides historical and forecast prices for
the Mid-C market, which is frequently utilized by Idaho
Power for off-system market purchases. On a going
forward basis, these figures provide a realistic
estimation of the costs Idaho Power would incur to serve
customers absent additional 20-year, fixed-price PURPA
contracts, and can be relied upon by the Commission as an
expectation and approximation of the future impact to
customers.
Q. Several of the opposing parties argue that QF
projects will not be able to obtain financing with a
reduction of the maximum contract term to two years.
Does Idaho Power agree?
A. I do not think the term reduction will
absolutely prevent any kind of financing for QF projects.
Certainly, the same type of financing, and the terms of
the financing, will likely be different than today where
209 ALLPHIN, REB 13
Idaho Power Company
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QF projects are able to finance a risk-free guarantee of
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210 ALLPHIN, REB 13a
Idaho Power Company
1 year stream of prices and income. However, the argument
2 of the parties that PURPA and FERC require the Commission
3 to provide QF projects with a contract that enables
4 risk-free financing for their projects is incorrect.
5 Everyone knows that one purpose and intent of PURPA is to
6 promote the development of additional cogeneration and
7 small power production. However, PURPA also requires
8 that the utility's retail customers, who pay for PURPA
9 purchases, be held neutral as to whether that generation
10 was acquired from PURPA or otherwise provided by the
11 utility. The promotion of the development of additional
12 cogeneration and small power production QFs required by
13 PURPA is accomplished by use of the mandatory purchase
14 obligation. Promotion is not to be provided with the
15 rates, terms, and financing available for QF projects.
16 PURPA directs that the purchase price is not to exceed
17 the utility's avoided cost, and must be just and
18 reasonable to the utility's customers. This
19 determination was given to the state Commission to
20 establish. The Commission recognized this concept in its
21 order from Phase II of the previous generic avoided cost
22 and PURPA contracting case, Case No. GNR-E-11-01. The
23 Commission found:
24 Avoided cost rates are to be just and
reasonable to the utility's ratepayers.
25 PURPA entitles QFs to a rate equivalent to
the utility's avoided cost, a rate that
211 ALLPHIN, REB 14
Idaho Power Company
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holds utility customers harmless - not a
rate at which a project may be viable. If
we allow the current trend to continue,
customers may be forced to pay for
resources at an inflated rate and,
potentially, before the energy is actually
needed by the utility to serve its
customers. This is clearly not in the
public interest.
Order No. 32262, p. 8 (internal citations omitted).
Idaho Power's position is that the must-take obligation
of PURPA does not require a proposed QF project be
provided with risk-free financing by the Company and its
customers.
The must-take, or mandatory purchase, obligation of
PURPA is the way PURPA was designed to promote the
development of additional cogeneration and small power
production facilities. This mandatory purchase
obligation does not go away with the expiration of a
contract term, and, once the contract term expires, the
QF project can then enter into a new contract with the
utility; the utility is still obligated to purchase.
However, in order to protect customers from paying
inflated, outdated costs that exceed avoided cost, or
from shouldering the entire risk of such which is
associated with a long-term, fixed-price contract, the
best viable alternative is to set a shorter maximum
contract term. It is in this way that the Commission can
assure an updated avoided cost rate is implemented for
individual projects. The Company has
212 ALLPHIN, REB 15
Idaho Power Company
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proposed a two-year contract term, the same time frame
used by the Company in its determination of the need for
additional resources carried out through the IRP process.
Q. Some of the parties have proposed to retain
long term, 20-year contracts but to have a portion of the
term with fixed prices and the remaining term with an
adjustable rate portion of the long-term contracts. What
is Idaho Power's position with regard to these proposals?
A. Such arrangements have been implemented to some
extent in the past, where different mechanisms were
implemented that provided some portion of adjustable
rates in a PURPA contract. The Company believes this to
be slightly better than the current implementation where
the entire 20-year contract term is at fixed rates, with
Idaho Power's customers shouldering the entire risk.
However, this solution has at least two major problems
associated with it. First of all, from the past
arguments put forth by many QF parties, the ability to
adjust prices in a PURPA contract, once that contract is
executed, approved, and put into place, is questionable.
The Commission and the Company have both faced
substantial opposition to the legality of any kind of
"contract reopener" that would adjust the avoided cost
rate during the term of a contract. Whether a contract
that contained adjustable avoided cost rates would be
considered valid is questionable, as FERC
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213 ALLPHIN, REB 16
Idaho Power Company
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has opined that once the rates are established in the
contract, they cannot be changed, even in the face of
direct evidence that they are grossly out of sync with
the utility's avoided costs in the future. As referenced
above, a short-term contract would not abrogate the
utility's must-purchase obligation. Once the current
contract term expired, the utility would be required to
enter into a new contract-but at the current calculation
of its avoided costs. In this way, the Commission could
mitigate the long-term risk shouldered by customers, and
assure that the rates are refreshed to current rates at
least every two years, which is consistent with both the
Company's IRP process as well as its Commission-approved
Risk Management Policy for power purchases.
Secondly, retention of a long-term contract, even
with an adjustable portion of the rate, if such were
determined to be legal, would still expose the Company's
customers to unreasonable risk. Moreover, given the
mandatory purchase requirement of PURPA, is really
unnecessary. Additionally, if there was a legislative
change in PURPA affecting the mandatory purchase
obligation, or if a viable RTO, ISO, or other PURPA
exempt market developed in Idaho Power's service
territory, customers would be locked into long-term
contracts, and potentially not able to benefit from these
changes for the
214 ALLPHIN, REB 17
Idaho Power Company
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next 20 years. Retention of a long-term obligation on
customers would continue to allocate a disproportionate
and harmful amount of risk to Idaho Power customers.
Q. The testimony of Mr. Wenner on behalf of the
Sierra Club and the Idaho Conservation League states his
legal opinion that a two-year contract term "does not
satisfy the FERC's regulations and is inconsistent with
PURPA." Wenner, DI p. 2. Have you reviewed Mr. Wenner's
testimony?
A. Yes, I have.
Q. Does Idaho Power have any response to Mr.
Wenner's testimony?
A. Yes. Mr. Wenner's testimony is somewhat odd in
that Mr. Wenner, as an attorney, appears to provide his
own legal opinion, argument, and analysis regarding an
argument that FERC somehow has prescribed or intended
long-term contracts to be in excess of 10 years and that
two year contracts would be illegal. Although Idaho
Power intends to ask the Commission to strike Mr.
Wenner's testimony as improper, it is important to note
that even Mr. Wenner, on page 5 of his direct testimony,
acknowledges that there is no FERC regulation specifying
the number of years or required term for a contractual or
legally enforceable obligation by which QFs are entitled
to receive avoided cost rates.
215 ALLPHIN, REB 18
Idaho Power Company
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Mr. Reading also argues that FERC's regulations
require long-term contracts. These arguments attempt to
create something that simply is not there. As
acknowledged by Mr. Wenner, and stated by Mr. Sterling on
behalf of Staff beginning on page 10 of his direct
testimony, FERC's regulations implementing PURPA are
silent on contract length. The parties' attempts to
create a required long-term contract length where none
exists is unpersuasive. The Commission has from
time-to-time adjusted the maximum contract term available
to QFs in the state of Idaho. The Commission approves
and/or directs the use of many different contractual
terms and conditions contained in the Energy Sales
Agreement contracts that are individually approved or
rejected on a case-by-case basis in PURPA purchases. In
doing so, the Commission balances the protection of
utility customers and the promotion of small power
production and cogeneration facilities. However, as
discussed above, the Commission has recognized that the
promotion of QF projects through PURPA is accomplished by
the mandatory purchase obligation, not a promotional rate
and/or promotional terms and financing arrangements.
Small generators, particularly renewable generators, have
other avenues outside of PURPA designed to promote
development.
216 ALLPHIN, REB 19
Idaho Power Company
1 Q. Some parties, such as Mr. Reading and Mr.
2 Yankel on behalf of Simplot/Clearwater and the IIPA,
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217 ALLPHIN, REB 19a
Idaho Power Company
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respectively, have offered criticism of your Exhibit No.
6. Does Idaho Power have a response?
A. Yes. Mr. Reading, in particular, argues that
the information can be configured or re-displayed in
different ways to make it look different, or appear that
it is the Company's resources contributing more to
over-generation events than PURPA projects. However, no
matter how the information is displayed, Idaho Power does
not dispute the fact that over-generation occurs, even
with its own must-run resources, just as with the
must-take PURPA generation. That was not the point. One
point and purpose for the information in this exhibit is
to provide evidence of instances in which the Company
must manage through over-generation events on its system.
Typically, the Company's resource planning, the IRP
process, looks at peak hour capacity and energy deficits
to make sure the Company adequately plans to meet its
obligation to reliably serve all load on its system.
This exhibit provides valuable information about system
operations and resource sufficiency for other times of
the day and year, somewhat on the other end of the
spectrum from the typical IRP analysis.
Exhibit No. 6 shows the frequency with which Idaho
Power's system, when in a state where it cannot be backed
down any further (only must-run and must-take generation
218 ALLPHIN, REB 20
Idaho Power Company
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is running), will have generation resources in excess of
its system load. As discussed in my direct testimony
starting on page 8, this puts the system into an
imbalanced, over-generation state that requires remedial
action to balance the system. The addition of more
must-take PURPA generation will exacerbate the problem
and increase the number of over-generation events that
Idaho Power must manage, as can be seen on the summary
page of Exhibit No. 6 (ranging from a 29 to 40 percent
increase). Additionally, Idaho Power will have no
ability to dispatch these must-take PURPA QF resources;
thus, the management of this increased number of
over-generation events will have to be absorbed and
managed by existing Idaho Power generation resources.
This can result in more costly and less efficient
operations of the Company's resources, and increased
costs passed on to Idaho Power customers.
Q. Commission Staff supported the Company's
request to reduce the maximum contract term, but suggests
a maximum term of five years, as opposed to Idaho Power's
requested maximum term of two years. What is Idaho
Power's response?
A. Idaho Power appreciates and agrees with Staff's
analysis and recommendations. The Company is very
cognizant of the fact that the Commission has utilized a
219 ALLPHIN, REB 21
Idaho Power Company
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maximum PURPA contract term of five years in the past,
but
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Idaho Power Company
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the Company maintains its request for a two-year maximum
term. A two-year term is consistent with the
Commission's existing determination of reasonable risk
exposure to customers in both the IRP process and the
Company's Risk Management Policy. As stated in the
Company's Petition and direct testimony, the IRP is
updated with a new planning document that is filed with
the Commission every two years. In like manner, under
the Commission-approved Risk Management Policy, which
governs the Company's purchase and sales of generation,
typical transactions do not exceed 18 months, and any
transactions longer than two years require specific
Commission approval. The Commission has determined that
two years is the reasonable and prudent period of time in
which to update forecasts and to not expose customers to
undue market and transactional risk associated with the
purchase of generation. This should also be applied to
the undue risk and burden placed upon customers with the
must-take PURPA obligation.
Q. Do you have any summary or concluding
statements for the Company's rebuttal testimony?
A. Yes. As stated in the Company's Petition and
direct testimony, Idaho Power continues to believe the
continued creation of 20-year, fixed-price contracts
places undue risk on customers at a time when Idaho Power
has sufficient resources to meet customer demands. The
221 ALLPHIN, REB 22
Idaho Power Company
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Company's required IRP process is filed and updated every
two years. Non-PURPA purchase and sales transactions are
limited to less than two years pursuant to the approved
Risk Management Policy. Avoided cost rates are updated
at least every year. Idaho Power has no current
identifiable need to acquire any additional generation
resources through 2021, and likely out to at least 2025,
as noted in the upcoming 2015 IRP. The requirements for
acquiring additional generation resources, particularly
that of establishing need for the resource and meeting
that need in the least cost, most reliable manner, are
absent in the mandatory PURPA QF purchase. The further
constraint imposed by PURPA that eliminates the ability
to modify, adjust, or change the prices that are locked
into a PURPA contract for the duration of its
term-regardless of whether all costs were included or
whether actual costs and conditions changed or
varied-makes long-term, 20-year contract terms risky and
harmful to Idaho Power customers. The Commission should
reduce the maximum term to two years to match the
determination of prudent updates and risk exposure that
have been established for the IRP and non-PURPA
purchases.
Q. Does this conclude your testimony?
A. Yes.
222 ALLPHIN, REB 23
Idaho Power Company
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(The following proceedings were had in open
hearing.)
MR. WALKER: Mr. Allphin is available for
cross-examination.
COMMISSIONER KJELLANDER: Thank you. Mr.
Richardson, since I skipped you the first go-around,
let's start with you.
MR. RICHARDSON: I'm going to take a pass,
Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you. Well,
we're looking for folks that will likely pass, we'll move
to Micron quickly.
MS. HOWLAND: Correct.
COMMISSIONER KJELLANDER: Thank you.
Mr. Arkoosh .
MR. ARKOOSH: Pass, Your Honor, thank you very
much.
COMMISSIONER KJELLANDER: Ecoplexus.
MR. HAMMOND: If I may, could I defer for a
minute? I'm waiting for a response from our client.
COMMISSIONER KJELLANDER: Sure, we'll pass on
you for now. Let's move to the Renewable Energy
Coalition.
MR. SANGER: Pass.
COMMISSIONER KJELLANDER: Idaho Irrigation
CSB REPORTING
[phone]
223 ALLPHIN
Idaho Power Company
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Pumpers.
MS. OLSEN: No questions, Mr. Chair.
COMMISSIONER KJELLANDER: Snake River
Alliance.
MS. NUNEZ: We do have a few questions.
COMMISSIONER KJELLANDER: Please move the
microphone close.
CROSS-EXAMINATION
BY MS. NUNEZ:
Q. Good morning, Mr. Allphin.
A. Good morning.
Q. In your testimony, you discuss comparisons made
to our neighboring states' renewable portfolio standards.
I just wanted to explore that a little bit with you.
I do have a report that we would like to submit
as an exhibit.
COMMISSIONER KJELLANDER: What number is that?
MS. NUNEZ: This is going to be Snake River
Alliance Exhibit 501.
(Ms. Nunez distributing documents.)
(Snake River Alliance Exhibit No. 501 was
marked for identification.)
MS. NUNEZ: And I have a stack for the other
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parties. I'm not sure if there's enough, but take one if
you want one.
Q. BY MS. NUNEZ: Mr. Allphin, this a report from
the Clean Energy States Alliance entitled, "Environmental
Rules for Hydropower in State Renewable Portfolio
Standards" and as you acknowledge in your testimony and
in the Company's application, Idaho does not have a
renewable portfolio standard or any statute that mandates
a certain percentage of renewable energy or a certain
percentage of our electricity comes from renewables.
Can you comment on why you included that
discussion of renewable comparisons in your testimony,
please?
A. That comparison was included to indicate the
amount of renewable energy that Idaho Power Company is
currently integrating into our system. You're correct,
Idaho Power does not currently have an RPS and not
required to those standards.
Q. One of the most significant comments that you
make was that Idaho Power would comply with the 90
percent RPS if all of the hydropower resources were
included. Did you make any distinctions between the
various sizes of renewable energy projects that Idaho
Power Company owns in corning up with that comparison, so
megawatt size?
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A.
Q.
No.
So the purpose of this report that we're
3 submitting today is it's an analysis of the different
4 renewable portfolio standards in the states that have
5 them. For the most part, RPS's in states, they cap
6 hydropower projects at 30 megawatts and many of them also
7 limit the age of the hydropower project, so I'd like to
8 refer you to the table that starts -- it's Table 1 that
9 starts on page 8 of the report, which lists the different
10 states that have hydropower qualifications in their
11 RPS's.
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A .
Q.
Okay.
Do you see California? What is California's
14 capacity limit?
15 A. It looks like California on the table it says a
16 capacity limit of 30 megawatts.
17 Q. So I don't know if you have all of your hydro
18 projects in your head memorized, but would you change
19 your analysis that you would have a 90 percent RPS
20 compliance if there was a 30 megawatt cap and do you know
21 how that number would change?
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Q.
I'm not -- I don't have specific information
Is that something I could follow up with you in
23 for you.
25 the future?
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A. Sure.
MS. NUNEZ: Okay, thank you. I don't have any
further questions.
COMMISSIONER KJELLANDER: Thank you. Let's
look to Snake River Alliance. We just did you. Hey, I
feel good about that. Intermountain Energy Partners, any
questions?
MR. MILLER: Thank you, Madam -- Mr. Chairman.
I don't know why I do that.
COMMISSIONER KJELLANDER: Is it the hair?
MR. MILLER: I will not do it again, I
promise.
CROSS-EXAMINATION
BY MR. MILLER:
Q. Good morning, Mr. Allphin. Could I direct
your attention to your Exhibit No. 11 which was filed
with the Commission recently? And this exhibit updates
exhibits that accompanied your prefiled testimony; is
that correct?
A. Yes.
Q. Could I direct your attention to page 2 of
Exhibit No. 11? Are you with me?
A. Yeah.
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Q. Does the exhibit here update the number of
PURPA solar projects under contract compared to January
20th, 2015, to April 22nd, 2015?
A. Yes.
Q. Does this indicate that during that period of
time the number of megawatts under contract went from 401
to 260?
A. Now, you're speaking specifically Idaho?
Q. Idaho.
A. Yes.
Q. Does it indicate that as of January 20th, there
were 13 projects under contract and that between January
20th and April 22nd, four of those projects terminated
their contracts?
A. Actually, I just need to count the lines there,
just one second, to see if there are 13. Yes, there were
13 in Idaho.
Q. As of January 20th?
A. Yes.
Q. And as of April 22nd, there were nine?
A. Yes, four contracts were terminated.
Q. Can we. inf er from this that the fact that a
project has a signed contract is not a necessary
indication that it will ultimately construct its
project?
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A. We can infer from this that clearly once a
project signs a contract, there is still uncertainty
whether that project will be developed.
Q. Could I direct your attention now to page 3 of
Exhibit No. 11?
A. I'm there.
Q. And before I ask questions with respect to this
exhibit, could I direct your attention to Intermountain
Energy Partners Exhibit 401 which I believe is on the
witness stand in front of you?
A. Yes, I've got it.
Q. I believe I've distributed copies to the
Commission and parties. Directing your attention to
Exhibit 401, has Idaho Power Company published written
contracting procedures for persons or entities wishing to
obtain an energy sales agreement with the Company?
A. As your Exhibit 401, the Schedule 73 which is
our currently approved process.
Q. Those contracting procedures are contained in
Schedule 73 which is Exhibit 401; is that correct?
A. Yes.
Q. I'd like to review with you those procedures so
we have them in mind before discussing page 3 of Exhibit
11, so if we turn to the page -- starting on page 3 of 10
of Exhibit 401, that's the start of the contracting
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procedure section?
A. Yes, it appears there at the bottom of the
page. It start with contracting procedures.
Q. So if we try to understand these procedures,
the first step is in section la which requires a project
to submit identified information in order to obtain
indicative pricing; is that correct?
A. Yes.
Q. So we'll refer to that as step 1.
A. Okay.
Q. Then if we refer to section le following the
receipt of that information, the Company would provide
indicative pricing to the requesting project; is that
correct?
A. Yes, once that information is provided in a
complete manner.
Q. And does section ld make it clear that from the
Company's point of view, those prices are not final or
binding?
A. They are indicative prices.
Q. Then if we go to section lg -- pardon me, le,
if after receiving the indicative pricing the customer
desires to proceed further, it requests in writing that
the Company prepare a draft energy sales agreement; is
that the next step?
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A.
Q.
A.
Yes, uh-huh.
So we'd call that step 3?
I sort of lost track of the steps, but I'll
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Q.
A.
Q.
I think that's 3.
Okay.
And at that point the Company requests that the
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Q.
Yes, that's correct.
And then in paragraph lg, if satisfactory
12 information is received, the Company provides a draft
13 energy sales agreement?
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Q.
A.
Q.
Yes, that's correct.
So that, I think, would be step 4.
Okay.
And then under section lh, the customer then
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19 submitted by the Company; is that roughly correct?
20 A. Yeah, briefly scanning "h," that appears to be
• 21 correct .
22 Q. So that would be step 5. Then under paragraphs
23 "i" and "j," the parties then proceed to negotiate the
24 final contract terms.
25 A. Yes.
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Q. So that would be step 6?
A. I hope you're writing down all these steps
because I'm not.
Q. I've got them right here, and then finally
under sections k-n, the agreement is executed and
submitted to the Commission for review.
A. Yes.
Q. Okay, that's step 7. All right, now that we
have those steps in mind, perhaps we could now go back to
Exhibit No. 11, page 3. Of the projects that are listed
there, can you tell us how many submitted enough
information to receive indicative pricing under step l?
A. Step 3 -- I mean, this exhibit that you're
referring to includes projects that have requested
indicative prices and other forms of inquiry, which Idaho
Power Company considers to be serious inquiries to move
forward with projects. I don't have in front of me the
precise number of projects that requested indicative
prices.
Q. Do you recall answering a production request
from J.R. Simplot Company? It's production request
No. 4.
A. Yes.
Q. And in that production response, do you recall
providing information that indicates that of the projects
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that were listed now in Exhibit No. 3, 14 projects had
submitted enough information to obtain indicative
pricing?
A. As I recall, that number sounds approximately
correct. I'd have to check the response.
Q. Would you like to -- would you agree to that
number, subject to check?
A. Yes, yes.
Q. That response was with respect to Exhibit No. 3
as it existed when you filed your testimony. Are you
able to update that number with respect to your Exhibit
No. 11?
A. I don't have that information available.
Q. So the projects listed on exhibit -- just a
second here. Of the 47 projects listed on Exhibit No.
11, page 3, your best information at this time is 17 of
those got to the first step?
A. Now, you're identifying 17. Where did the
number 17 come from?
Q. I thought we just established that in your
response to Simplot request No. 4, 17 projects submitted
enough information to get to the first step.
A. I may have misheard, but I thought you quoted
14 in your previous statement.
Q. And now I can't hear you, I'm sorry.
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are still within it.
A. I don't recall. I thought there was at least
draft ESA. As far as your step numbers, I think step 2
Q. If I told you that your previously provided
In your previous -- I may have misheard, but I A.
thought in your previous statement you said that that
response stated 14 projects.
Q. Fourteen, I'm sorry, you're correct. I was
Q. So of the 14 who received indicative pricing,
A. Yes, I'm not aware of any projects that
3, so just so we're clear, then, of the projects listed
A. Again, I don't have that. That question was
previously requested indicative prices to withdraw their
step 1?
thinking of perhaps some updated number for Exhibit No.
on page 3 of Exhibit No. 11, 14 of the 47 made it to
sales agreement?
request, so yes, it would be safe to assume at least 14
how many made it to step 3 of requesting a draft energy
asked in a production request. I don't have that right
in front of me and I'm sure you will tell me what that
production request answer was.
information indicated that zero projects made it to
step 2 --
one project, I thought, that had made it to requesting a
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as you're referring to it, it's a point of being able to
receive a draft energy sales agreement and if I recall, I
think at least one project made it to that point.
Q. I was referring to the step in which the
project makes a written request to the Company to receive
a draft energy sales agreement.
A. And, again, I guess as I stated, if I recall
that production request, I think we identified one had
received an energy sales agreement, so obviously, they
would have made the request.
Q. So to the best of your recollection, then, one
project made it to the step of requesting a draft energy
sales agreement?
A. Yes, to the best of my recollection.
Q. So how many projects, then, made it to the next
step, which was submitting comments or accepting the
draft?
A. I don't recall any projects making it to that
point.
Q. So if I understand your testimony correctly,
then, zero projects made it to the step of accepting the
draft or submitting comments to the draft?
A. Yes.
Q. Now, you have labeled page 3 of 4 of the
exhibit "Proposed PURPA Solar."
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A. You're referring to Exhibit 11, I assume? Page
3 of 4, you're referring to Exhibit 11?
Q. Page 3 of 4.
A. Yes, right.
Q. Do you think it's accurate to characterize this
as a list of proposed PURPA solar when not one of the
projects has made it to the stage of entering into
contract negotiations?
A. Yes, it's still an accurate statement to say
the proposed PURPA solar.
Q. Do you think it's accurate to characterize the
list as a list of proposed PURPA solar when only 14 of
these projects have made it past stage 1 of the contract
procedures?
A. Yes, it's still accurate.
Q. Let me direct your attention to the final two
columns of Exhibit No. 11, page 3, where you have
calculations of estimated obligations.
A. Yes, I see that.
Q. And I think we previously established that in
Idaho Power's view anyway, it does not have any
obligation until a contract is signed and approved by the
Commission.
A. Yes.
Q. So as things currently stand now, Idaho Power
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correct?
amounts listed in columns -- in the final two columns?
ALLPHIN (X)
Idaho Power Company
237
Q. Now, in preparation for a couple of questions
COMMISSIONER RAPER: We're going to put you on
Q. So there's no current existing obligation;
Q. And I'll represent to you that this is a firm
A. Yes, I am.
Q. Are you with me?
A. Yes, I have it.
Q. All right. Now, I'd like to direct your
(Pause in proceedings.)
A. No, these values are calculated based upon the
Q. By MR. MILLER: Do you have your rebuttal
A. Yes, I do.
proposed projects that have been submitted to us.
has no contractual obligation to pay any of the dollar
My apologies here.
testimony with you?
attention to your rebuttal testimony, if I can find it.
Intermountain Energy Partners Exhibit No. 402?
on your rebuttal testimony, would you look at
Company and Clark Solar 1.
a Jeopardy clock .
energy sales agreement entered into between Idaho Power
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Q. BY MR. MILLER: In your position with Idaho
Power Company, are you generally responsible for the
preparation and negotiation and execution of firm energy
sales agreements?
A. I am responsible for the coordination,
negotiation. I and my team that I oversee is responsible
for that. I do not execute these agreements. That's a
senior vice president that executes these agreements.
Q. And I think you indicate in your testimony that
you have been responsible or involved in the area of
PURPA broadly speaking for a long period of your career.
A. Yes, many, many years.
Q. So you're familiar with the evolution of firm
energy sales agreements as they have sort of evolved over
time?
A. Yes.
Q. And is Exhibit No. 402 representative of what
we could call the current generation of energy sales
agreements?
A. This would be representative of the energy
sales agreement that existed at the time this agreement
was signed, which I see was in October of 2014. I'm not
actually sure if there's been additional evolutions that
have occurred since then.
Q. But at least as of October 2014, this was sort
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of the current standard agreement?
A. It was the current agreement, yes.
Q. All right. Now, if we could go to your
rebuttal testimony at page 13 and I'll direct your
attention to line 25 following on to the next page, and
to paraphrase, there you characterize the current state
of affairs as being one that enables the QF to finance a
risk-free guarantee of a 20-year stream of prices and
income.
A. Yes.
COMMISSIONER KJELLANDER: Gene, do you think
this is something you could correct? We're off the
record for a little bit.
(Pause in proceedings.)
COMMISSIONER KJELLANDER: So we are back on the
record and Mr. Miller, I think you had just asked some
extraordinarily intriguing question, which sort of
comports with the fact the music was there and it sounded
a little bit like what Commissioner Raper was advocating
that we have some kind of, like, Jeopardy music, but
we've got to keep things moving along.
MR. MILLER: Leading and suggestive questions
are the best kind.
COMMISSIONER RAPER: Can you restate for the
record?
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Q. BY MR. MILLER: All right; so we had just
paraphrased and agreed to your testimony on page 13 and
14 .
A. Would you care for me to paraphrase it or you
previously paraphrased it?
Q. Well, did I accurately summarize your testimony
as paraphrasing the current circumstances as enabling a
QF to finance a risk-free guarantee of a 20-year stream
of prices and income?
A. Yes, I think in that answer we're referring to
the term reduction will not absolutely prevent any kind
of financing. Clearly, the financing would be different.
The two-year -- the 20-year contract term currently
provides and locks in a set price for the full 20 years
to be risk free to the project.
Q. All right, just to go a little bit further with
that, let's go back, then, to Exhibit 402 and can I
direct your attention to --
COMMISSIONER KJELLANDER: You mean 401?
MR. MILLER: 402.
COMMISSIONER KJELLANDER: 402, okay, thank you.
Q. BY Mr. MILLER: I'll direct your attention to
page 9 of Exhibit 402 and what is shown on the exhibit as
paragraph or section 1. 4 6 entitled "Surplus Energy."
A. Now, you're referring to page 9; is that what
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you stated?
Q. Page 9 of Exhibit 402.
A. I don't have that item on page 9 of 402.
COMMISSIONER KJELLANDER: It's actually page 8.
It's page 9 of 34.
THE WITNESS: I'm sorry, yeah, you have
different page numbers. Okay, correct, it's page 8 of
the contract, page 9 of your exhibit.
Q. BY MR. MILLER: Right, why don't we refer to
the exhibit page numbers just to make it clear.
A. Okay, that's fine.
Q. All right; so there we see a paragraph entitled
"l.46 Surplus Energy"?
A. Yes.
Q. Could you just roughly explain for the
Commission what is conveyed in that paragraph?
A. In 1.46 the project is required to deliver
energy within specific boundaries of what it has stated
it would deliver in the contract, and if they fail to
deliver within those boundaries, there is a -- it's
classified as surplus energy which may result in a
slightly modified price. The performance under this
provision is totally in control of the project.
Q. This is what's commonly referred to as the
91-10?
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A. Yes.
Q. So it's true, isn't it, then, that the seller
has the risk that energy delivered outside the 91-10 band
will be priced at a value less than the full price the
seller would otherwise receive?
A. The price may be adjusted if the seller fails
to perform as they said they would.
Q. So that the seller faces the risk of producing
outside of this performance band?
A. Again, the seller has control over their
performance of the facility.
Q. Now, if we could go to paragraph -- page 17 of
the exhibit and there we see paragraph 6.3.
A. Yes.
Q. And could you explain generally for the
Commission what is conveyed by this paragraph?
A. Again, that paragraph 6.3 establishes a very
low floor that if the project does not perform and
deliver at least 10 percent, a minimal 10 percent, of
their energy they estimated to deliver, it will be an
event of default.
Q. So the seller, isn't it true, then, faces the
risk of being declared in default for failure to comply
with paragraph 6.3?
A. Yes, again, if the seller fails to operate the
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facility in that manner, that provision would be
applicable.
Q. Could we go now to paragraph or page 14 of
Exhibit 402 and look at paragraphs 5.3 and 5.4?
A. I've got those.
Q. Could you explain for us what is conveyed by
these two paragraphs operating in tandem?
A. As it states there, the project is required to
achieve its operation date within the delay cure period,
which I believe is 120 days in these contracts. If the
project fails to achieve their operation date within 120
days of when they have stated they would, the scheduled
operation date being the date that the project at their
sole discretion elected and chose, if they fail to meet
that, it can be a material breach of contract.
Q. So it would be fair to say looking at these two
paragraphs the seller faces a risk of liability for
damages if it does not achieve its scheduled operation
date?
A. If the seller fails to achieve the operation
date that they have sole control of setting within the
cure period, yes, there is potential damages that could
occur.
Q. Right. Now, could we go to page 24 of Exhibit
402? I'm sorry, page 23 would be the better page. If
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you would look at paragraph 12.2.l(b), is it fair to say
looking at this paragraph that the seller faces the risk
of curtailment in the event of certain oversupply
circumstances?
A. What this specifically reads, "If interruption
of energy deliveries is allowed by Section 210 of the
Public Utility Regulatory Policies Act of 1978 and 18 CFR
292.304,'' 12.2.1 applies, which Idaho Power Company shall
be excused from accepting and paying for net energy.
Q. It is it your general understanding that 18 CFR
292.304 permits curtailment in certain oversupply
circumstances?
A. It's been a while since I've looked at that
specific paragraph, so I cannot say.
Q. Well, for some reason the contract contains a
footnote which is a citation to Section 304; right?
A. Yes, I see the footnote.
Q. So to phrase it in a way that's slightly
differently, then, it's true, is it not, the seller faces
the risk of curtailment in circumstances permitted by
Section 292.304?
A. Yes.
Q. Could we go now to page 10 of Exhibit 304 [sic]
and look at paragraph 3.4?
A. I've got it.
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Q. And can you just generally describe for us
what's conveyed by section 3.4?
MR. WALKER: Mr. Chairman, at this point I'm
going to lodge an objection as to Mr. Miller having Mr.
Allphin simply read and interpret this contract which has
been filed and approved with the Commission, and
certainly the provisions of the contract are available
for anybody to read and it speaks for itself.
COMMISSIONER KJELLANDER: Mr. Miller.
MR. MILLER: Well, Mr. Chairman, I'm just
asking for clarity and expediency sake for the witness
who is aware of these terms to provide an explanation of
what is being conveyed, and as you will recall, I haven't
done this for the purpose of disputing his
characterization. I have accepted his characterization
in every event, but I'm merely asking the questions for
purposes of clarity. If we all want to just read the
paragraph, I guess we could do that.
COMMISSIONER KJELLANDER: What specifically was
your question again?
Q. BY MR. MILLER: Could you convey for us, Mr.
Allphin, generally what is conveyed by paragraph 3.4?
COMMISSIONER KJELLANDER: And please proceed.
THE WITNESS: Paragraph 3.4 within the contract
to develop the pricing, the project is required to
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A. Yes.
of the contract.
deviates from its estimates?
calculating the price. This section of the contract
I'll find the page for you -- page 15 of 34
provide an hourly energy shape that is a key component in
establishes that energy shape that the project has
provided, that the project at their discretion provided,
A. To get the context of 6.2.2, you also have to
Q. BY MR. MILLER: And then does the paragraph
Q. So the seller under this agreement faces a risk
Q. I'm almost through. Can we go now to
element of the contract, and the project is then held to
A. Yes, the last sentence of that paragraph does
as that is how they expected to perform and it becomes an
some level of performance on those numbers for the term
will be considered a material breach of the agreement?
provide that material deviations from those estimates
read, "Material deviations from these hourly energy
of material breach if its actual generation materially
paragraph
estimates will be a material breach of this agreement."
having to do with seller adjustments of energy amounts?
understand paragraph 6.2, the previous paragraph, which
Could you explain for us generally what's conveyed by
paragraph 6.2.2?
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establishes, again, at the time the contract is executed,
the project has provided us monthly energy estimates,
those monthly energy estimates being the monthly values
of the hourly energy estimates the project previously
provided. If the project were to not meet those monthly
estimates, the project has the ability to modify those
estimates prior to the occurrence of the month to avoid
any possible, as you previously referred, 91-10
ramifications.
Q. And does this paragraph operate in conjunction
with other paragraphs, which we don't need to go into,
such that if the seller does adjust its projected energy
amounts, Idaho Power may adjust the price that will be
paid for those adjusted amounts?
A. Yes, there is a potential risk if the project
deviates from its original hourly estimates that were
used to create the pricing, there could be a penalty in
regards to this 91-10.
Q. So the seller faces a risk that if it does have
to adjust its estimates that it will also face a price
adjustment?
A. Yes. Again, if the seller does not perform as
they estimated and said they would, there would be
possible price adjustments within the contract.
Q. Well, perhaps this has been a long walk down a
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short pier, but in light of the risks that we have
identified arising out of Exhibit 402, would you like to
reconsider your testimony that a QF contract is a
risk-free guarantee of a 20-year stream of prices and
income?
A. No, I think as that testimony states, the risk
free, the risk free is the 20-year contract price that is
locked within the contract. All of the items you
identified in the contract are things within the control
of the seller that would cause a change in the income.
The actual pricing stream that is locked in at the time
the contract is executed is fixed and is unable to be
changed for the term of the contract.
Q. Let me just ask one last question. We're
talking about risk and it seems like there are a couple
of steps. The first is to identify how a risk is
allocated and then the second question is whether that
allocation is fair or not, but we have identified how
risks are allocated in Exhibit 402, correct, some of them
anyway?
A. Yeah, Exhibit 402, again, walks through the
various performance requirements that a project must
adhere to.
Q. So is it still your testimony that a QF
contract is a risk-free guarantee of a 20-year stream of
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prices and income?
A. It's a risk-free guarantee of a 20-year stream
of prices, yes.
Q. I couldn't quite hear you .
A. It's a risk-free guarantee of a 20-year stream
of prices, yes.
Q. Well, let me wrap it up this way, then: We can
agree that we have identified risks that the seller
assumes under a contract like Exhibit 402?
A. There are -- the seller establishes different
parameters and provides different information on how they
will perform and if the seller does not perform
accordingly, yes, a seller may -- the contract does have
provisions that would trigger different pricing
mechanisms.
MR. MILLER: All right, I think we've probably
taken this as far as we can take it. That's all I have,
Mr. Chairman.
COMMISSIONER KJELLANDER: Thank you,
Mr. Miller. Let's move to the Idaho Conservation
League.
MR. OTTO: Thank you, Mr. Chairman. I do have
a few questions. This should not take very long.
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CROSS-EXAMINATION
BY MR. OTTO:
Q. Mr. Allphin, in your rebuttal testimony on page
3, 7 through 14, you make the point that no other party
has addressed the bigger issue of the need and the risk.
Do you recall that part of your testimony?
A. You said rebuttal on page 3; is that correct?
Q. Yes.
A. Yes, I see it here.
Q. Okay, did you review Mr. Beach's testimony,
direct and rebuttal?
A. Yeah, I generally did, yes.
Q. And pages 13 through 16 where he talks about
the IRP method?
A. I don't have his testimony in front of me. I
don't recall what's on pages 13 through 16.
Q. But you did review those?
A. Generally, yes.
Q. Including the parts that discuss risk and
reliability?
A. Yes, I believe so.
Q. Okay, we're going to move on. Page 4 of your
direct testimony, it goes through, generally goes
through, the steps that a utility -- the steps to build a
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utility-owned resource. There's identification of need,
RFP process, CPCNs, ongoing reviews. Do you see that
part of your testimony?
A. Could you please refer me to the line number on
page 4?
Q. Just one moment. I'm referring to lines 12
through -- it continues on page 5, line 7.
A. Oh, yes, okay, I see it there.
COMMISSIONER RAPER: Are you in direct or
rebuttal?
MR. OTTO: Rebuttal, I apologize.
COMMISSIONER KJELLANDER: Thank you for the
clarification.
MR. OTTO: Thank you for that.
THE WITNESS: Okay; so now what page, again, in
rebuttal?
Q. BY MR. OTTO: Page 4 of your rebuttal
testimony.
A. Okay, and what line number?
Q. It begins at line 12 and continues on page 5
through line 7.
A. Yes, okay, I see that.
Q. And it just generally goes through the steps of
a utility-built resource, to make the decision and to get
approval; is that a correct characterization?
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A. Yes.
Q. And you kind of make the point that a PURPA
project or a QF doesn't go through a similar set of
rigor, I guess.
A. They go through none of that rigor.
Q. Okay; so the IRP defines the capacity
deficiency date; is that correct?
A. Yes, the IRP establishes the needs of the
Company.
Q. And that's a public process?
A. Yes, it is.
Q. With Commission approval?
A. Yes.
Q. And the energy components of the avoided cost
inputs, those are updated annually; is that correct? The
load forecast? The gas price forecast?
A. Yes.
Q. And that's a public process with Commission
approval?
A. Yes.
Q. And then the capacity position can actually --
it begins with the IRP; correct?
A. Yes.
Q. And every time a QF contract is signed and
approved by the Commission, the Company is able to update
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the capacity position; is that correct?
A. Yes, that capacity position moves as projects
are proposed to the Company.
Q. So it's fair to say the energy components are
updated annually through a public process, and the
capacity component is updated even more frequently; is
that a fair statement?
A. Yes .
Q. And then the Commission reviews each QF
contract and approves that; is that correct?
A. Yes.
Q. Would you agree that that is several steps of a
public process with Commission approval?
A. The inputs into the pricing model, yes.
Q. And each contract as well; correct?
A. The final contract, yes, has to receive
Commission approval.
Q. Okay, now we're going to move to your direct
testimony, Exhibit 2, page 6. In the final -- so this
exhibit is all the currently approved PURPA and non-PURPA
projects, contracts; is that correct?
A. As of January, yes.
Q. Yes. I want to make sure I have it right in
front of me. Here it is; so the very last section you
have three non-PURPA projects online?
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A. Yes, we do.
Q. Are those long-term power purchase
agreements?
A. Yes, they are.
Q. What's the term of those agreements?
A. I don't recall specifically. I believe they're
20 or 25 years.
Q. And do those long-term contracts benefit
customers?
A. Yes, they do.
MR. OTTO: Thank you. That's all.
COMMISSIONER KJELLANDER: Thank you very much.
Mr. Adams, any questions on behalf of the Simplot
Company?
MR. ADAMS: Yes, Mr. Chairman, we're going to
have several questions. I don't know if you want to take
a break now or --
COMMISSIONER KJELLANDER: Let's go ahead and
give it a whirl.
MR. ADAMS: Okay.
CROSS-EXAMINATION
BY MR. ADAMS:
Q. Good morning, Mr. Allphin.
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A. Good morning.
Q. On page 3 of your direct testimony, you discuss
your Exhibit No. 1 and you assert that there's 885
megawatts of solar QFs that "made formal, written
requests for PURPA energy sales agreements with Idaho
Power." That was at line 16 to 18.
A. Uh-huh. Yes, I see that.
Q. So what constitutes a formal, written request
for a PURPA energy sales agreement?
A. Through the process of making inquiries to
Idaho Power Company, those forms of requests can take on
different shapes. After approval of Schedule 73,
Schedule 73 provided an application that projects must
provide in order to receive indicative pricing. Prior to
Schedule 73, that form of request could come in various
forms. It could come in the form of written requests,
emails requesting basically enough information to provide
Idaho Power Company some level of being able to produce
indicative price reports.
Q. So you're not alleging, then, here that there
were 885 megawatts worth of solar projects that were
ready to sign contracts at the indicative prices that
Idaho Power Company provided to them; correct?
A. No.
Q. Because it's a little confusing, isn't it,
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then comes later.
overstated the case a little bit, then, too, to state
that they had requested -- issued a formal, written
ALLPHIN (X)
Idaho Power Company
256
because on page 4, then, at line 16 to 20, you say
Exhibit No. 3 shows that each individual proposed PURPA
project, solar project, that had submitted a written
request for indicative pricing, so you're kind of mixing
Q. Well, I'm just asking, these aren't published
A. Would you please repeat that?
and matching requesting a formal request for a contract
with indicative pricing here, aren't you?
A. Well, again, as Schedule 73 points out, the
Q. Right; so then your earlier testimony on page 3
A. Yes, I could agree with that.
Q. Okay, and would you also agree that there's no
first step in a project moving forward is a request for
indicative pricing and the request for a formal contract
request for power purchase agreements; correct?
way currently if you're an IRP methodology solar QF to
providing that list of information to request the
obtain the prices without contacting Idaho Power and
indicative prices?
rates; right? They have to contact you, a developer has
to contact you, to get those indicative prices;
correct?
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A. Yes, that's correct.
Q. So none of those 885 megawatts of projects
could have known what the price would be to move forward
with their project or whether they want to move forward
with it without actually making that request for the
pricing?
A. Yes.
Q. Mr. Allphin, is it your position that we should
assume that every QF, prospective QF, that contacts Idaho
Power to request indicative pricing will ultimately build
and construct a QF?
A. Idaho Power has no information to the contrary.
We have to assume that the projects are moving forward
with their projects.
MR. ADAMS: Mr. Chairman, can I approach the
witness with a document?
COMMISSIONER KJELLANDER: What's the document?
MR. ADAMS: It is a discovery production
request, response of Idaho Power's that we're going to
propose to admit as an exhibit.
COMMISSIONER KJELLANDER: Without objection.
(Mr. Richardson distributing documents.)
Q. BY MR. ADAMS: So Mr. Allphin, this is your
response to Simplot's production request No. 22, and this
is actually an updated response to request No. 4 that
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A. Yes.
A. Yes.
ALLPHIN (X)
Idaho Power Company
258
Q. So that's the table that Mr. Miller was
A. Yes, it appears so.
(J.R. Simplot Company Exhibit No. 206 was
Q. BY MR. ADAMS: So Mr. Allphin, can you turn to
Q. And looking at that, it appears that only one
A. Yes, that's correct.
MR. ADAMS: So I want to admit that exhibit
Q. And in the second column, is that all the
Mr. Miller asked you several questions about, and on the
COMMISSIONER KJELLANDER: Okay, without
who can sponsor that witness, correct, or that exhibit;
into the record. It would be Simplot Exhibit 206 .
last page it says that you're the person from the Company
objection, it is identified and admitted.
correct?
what's noted at the bottom as page 8? It's a table.
admitted into evidence.)
the top it was updated as of April 22nd; correct?
actually asking you questions about, except it says at
projects that have progressed far enough to get an energy
project has gotten far enough to obtain a draft energy
sales agreement from Idaho Power?
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sales agreement as of April; correct?
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A. Yes.
Q. And Mr. Miller went through the steps to get a
draft energy sales agreement. There was additional
information that you had to provide after you had
obtained the indicative prices; correct?
A. Yes.
Q. And does that include site control?
A. In the current Schedule 73, yes.
Q. What would a QF developer have to provide Idaho
Power in order to satisfy that requirement?
A. Generally speaking, that would probably be some
demonstration, as the term says, they have some control
of the site either by ownership or lease .
Q. Like a lease or even an option?
A. Again, generally speaking.
Q. Okay, can you turn to the last page of that
exhibit, please? So at the top there doesn't it state
that Idaho Power doesn't possess any information from any
of these prospective QFs that they even possess site
control under subpart b?
A. Yes, let me see. Again, as I stated, though,
the site control condition was required at the time
Schedule 73 was approved. Prior to 73, I'm not
absolutely sure as to what requirements there were for
site control, that this project that had requested a
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contract very well could have made that request prior to
the formal establishment of Schedule 73.
Q. Yeah, I think you did explain that in the
discovery response, that that project predated Schedule
73.
A. Okay.
Q. But the point I'm asking is Idaho Power doesn't
have any evidence that any of these 885 megawatts of
projects even have a lease or an option to develop the
facility?
A. I don't have any information that it will be
different than I responded in this production request.
Q. Well, how do we have any indication that these
are serious projects and not just people who are trying
to determine what the prices might be before they move
forward?
A. Again, Idaho Power Company has to take all
inquiries seriously. A project can move through a
Schedule 73 process in a matter of days, from an inquiry
to a request of the final project, and so Idaho Power
Company has no information to not assume that they are
serious inquiries when they're received.
Q. Okay, isn't it true, though, Mr. Allphin, that
the avoided cost price under the IRP methodology will
decrease generally for each new prospective QF?
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A. That's a reasonable assumption, yes.
MR. ADAMS: Mr. Chairman, I'd like to provide
another document, another exhibit, to the witness.
COMMISSIONER KJELLANDER: Is this going to be a
potential new exhibit?
MR. ADAMS: Yes, it is.
COMMISSIONER KJELLANDER: So that would be 207?
MR. ADAMS: 207, correct.
COMMISSIONER KJELLANDER: And it is what?
MR. ADAMS: This is also Idaho Power's
responses to production requests, two responses, to the
Idaho Irrigation Pumpers request 11 and to the Staff
production request 9.
(Mr. Richardson distributing documents.)
Q. BY MR. ADAMS: So did you help prepare those
responses, also, Mr. Allphin?
A. Yes.
MR. ADAMS: I'll move to admit those into the
record as Exhibit 207.
COMMISSIONER KJELLANDER: Without objection,
Exhibit 207 has been identified and admitted.
(J.R. Simplot Company Exhibit No. 207 was
admitted into evidence.)
Q. BY MR. ADAMS: Okay, Mr. Allphin, could you
turn to the last page of the Irrigation Pumpers request
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No. 11?
A. No. 11?
Q. It would be the second to the last page of the
exhibit that I handed to you.
A. Yes, I believe I'm there.
Q. Okay; so in that table there, it provides the
prices that were -- on a levelized basis, correct, of the
IRP methodology contracts --
A. Yes.
Q. -- existing?
A. Yes, it does.
Q. Okay, and so in terms of the solar contracts,
which one was the first? Wasn't it Grand View PV Solar
Two?
A. I believe so, yes.
Q. And the price was $73.41?
A. Yes, that's the calculated levelized value.
Q. And the Clark 1 through 4, they were later on
in the queue; correct?
A. Yes.
Q. And the price for them was in the range of
59-$61.00; correct?
A. Yes.
Q. Can you turn to the last page of the exhibit,
the Staff production request 9, so this states that it is
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the 20-year avoided cost indicative pricing for the next
two projects in the queue of that 885 megawatts;
correct?
A. This is the pricing, the 20-year levelized
pricing, that was provided to two solar projects that
were part of that 885 megawatts.
Q. Correct, and the price was in this case $52.00
and $54.00 per megawatt-hour?
A. Yes.
Q. So it's gone down further still?
A. Yes.
Q. And as you mentioned earlier, it's correct that
the Solar, the Clark Solar, 1 through 4 contracts were
ultimately terminated.
A. Yes, they were.
Q. And why was that?
A. They failed to comply within requirements in
the contract.
Q. They failed to post their security deposit;
correct?
A. That's correct.
Q. Do you know how much the security deposit
was?
A. I don't have the precise number in my head. I
don't recall the size of those projects.
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Q. It would have been a few million dollars,
maybe?
A. Absolutely.
Q. Do you think that the lower rate had anything
to do with that? Do you think it would be harder for a
QF to develop the project at a lower rate and submit the
security deposit?
A. I have no information as far as what a QF's
economics are in regards to these projects. We don't
know what their capital costs are or any of their costs
to develop these projects.
Q. Okay, I'm going to move on to your rebuttal
testimony, Mr. Allphin, at page 5. You assert that the
argument -- you're responding to Dr. Reading here and you
assert the argument that the QF is somehow entitled to
the same type of capital cost recovery as a utility-owned
resource simply does not make logical sense. Do you
remember that?
A. I don't recall ever using the word "logical" in
that section.
Q. Okay, well, it's in lines 4 to 7.
A. You're saying lines 4 through 7?
Q. On page 5 of your rebuttal testimony.
A. Line 4 would read, the first full sentence,
"Consequently, the argument that the QF is somehow
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entitled to the same type of capital cost recovery as a
utility-owned resource simply does not make logical
sense," I stand corrected.
Q. Okay, thank you; so QFs don't in fact have the
same type of capital cost recovery of rate-based
resources, do they?
A. Repeat that question.
Q. Do QFs get the same type of payment for
capacity and capital investment as a rate-based utility
resource?
A. A QF is paid for the energy that it delivers to
the utility.
Q. But they don't get paid their capital costs
when they don't deliver like a rate-based resource;
correct?
A. The QF is paid based upon the avoided cost that
has been calculated for that project. It has no
relationship to what the capital cost of that project may
be.
Q. Well, they're not paid when they don't deliver
electricity; correct?
A. Absolutely, they get paid per megawatt-hour.
Q. And under the IRP methodology, isn't it correct
that new QFs don't get paid the capacity costs during the
utility's capacity surplus period?
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A. Yes, you're correct.
Q. Moving on to page 5 of your rebuttal testimony
at the bottom and running on to page 6, you testify
utility-owned resources are "only constructed and
operated to serve the public interest." Do you remember
that?
A. Yes, I see that.
Q. That's not entirely true, is it? Aren't they
also constructed in order for Idaho Power to earn a
return on its investment?
A. All utility-owned resources, the need has to be
identified through the IRP process. Once that need is
identified to serve our customers' load, then that
project, the Public Utility -- we have to go through a
process of submitting that resource out for an RFP to
require it to request bids, a competitive bid process, so
then only after that bid process has gone through and a
project is selected by which then the Public Utilities
Commission approves the project moving forward, and then
ultimately once it's built, the Public Utilities
Commission approves any cost recovery that may occur for
that project.
Q. Isn't Idaho Power Company a for-profit Company,
though?
A. Yes.
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Q. And doesn't it make money off of the projects
that it builds and rate bases?
A. Idaho Power's profits are governed by what's
allowed by the Public Utilities Commission.
Q. And if the Public Utilities Commission allows
it, they will, Idaho Power Company will, earn a profit on
rate-based generation resources; correct?
A. Yes.
Q. And doesn't Idaho Power Company have the
fiduciary obligation to its shareholders to earn as much
profit as it can reasonably?
A. Idaho Power has shareholders. As far as the
motivation, I'm not part of that department.
Q. Okay, but would you agree that Idaho Power does
not ever earn any profit off of purchasing generation
from a PURPA project?
A. No, Idaho Power receives no benefits from a
PURPA project.
Q. Okay, moving on to page 9 of your rebuttal, you
criticize Dr. Reading's Chart 1 where he was comparing
the capital on energy costs per megawatt-hour of the
Company's resources to historic market prices and average
PURPA prices.
A. Yes, I see that.
Q. And you're critical of Dr. Reading's testimony
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or his chart because he included peaking resources in the
chart and your position is that a peaking resource is
difficult to evaluate on a dollar per megawatt-hour
basis; right?
A. Yes, that's true.
Q. But aren't there also non-peaking resources in
Dr. Reading's Chart 1?
A. Yes, I believe so.
Q. Right, it included the Langley Gulch power
plant that had an average cost of $84.98 per
megawatt-hour versus the historic PURPA price of $62.30
per megawatt-hour?
A. I believe those numbers are accurate, yes.
Q. Okay, and the Valmy coal plant was $74.88 per
megawatt-hour versus the PURPA price in the range of
$62.00 per megawatt-hour?
A. Again, subject to check, I don't have the chart
here in front of me.
Q. Okay, and with regard to the peaking plants,
you were critical that Dr. Reading apparently made a
calculation error for the Bennett Mountain plant;
correct?
A. Yes.
Q. And he said that that would cost $250 per
megawatt-hour, something in that range?
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A. Yes, I recall that.
Q. And you corrected it to $171.28 per
megawatt-hour?
A. Yes, I believe so.
Q. So you agree, then, that the cost to supply
your customers with electricity from the Bennett Mountain
plant was $171 per megawatt-hour from the Bennett
Mountain plant?
A. At the time when we need to run the Bennett
Mountain plant, because we can dispatch it to meet our
needs, yes, that's the calculated price.
Q. Right, and I understand it's a peaking
resource, but don't you think you could secure a cheaper
source of capacity today than $171 per megawatt-hour?
A. I don't have any --
MR. WALKER: Objection, that's a
mischaracterization of what that testimony says. It does
not say that it agrees with that calculation of
Dr. Reading. It says that re-creating the calculation as
Dr. Reading has described it in his testimony arrives at
these numbers, but his testimony does not agree with the
accuracy of that as it's being portrayed by that
question.
MR. ADAMS: I disagree. I think his testimony
corrected the calculation, the mathematics of the
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calculation. Mr. Allphin disagreed with the
characterization of the significance of the number $171
per megawatt-hour, but I'm inquiring into his
disagreement.
MR. WALKER: Once again, the testimony speaks
for itself. It's not an acknowledgment that Mr.
Reading's comparison is an accurate comparison. It
simply says he calculated the number the way he described
calculating it incorrectly.
COMMISSIONER KJELLANDER: Thank you, and I'm
inclined to agree with Mr. Walker, and if you'd like to
maybe take another approach, another angle of your
question.
MR. ADAMS: Okay.
Q. BY MR. ADAMS: Mr. Allphin, do you think
potentially customers would be willing to curtail their
generation if you paid them $171 per megawatt-hour?
A. I have no idea. There's many assumptions
behind that question.
Q. Well, if that price were higher than what you
get on the market today, would you agree that that would
be above the current market prices?
A. Are you saying is the 171 above the current
market prices?
Q. Yes, do you agree that that number is a high
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number to pay for peaking capacity in today's market?
A. I don't have specific information to know for
sure how that would relate to peaking capacity in today's
market.
Q. Okay, let's move on to your rebuttal testimony
at pages 12 to 13. You're still criticizing
Dr. Reading's Chart 1 here and arguing that your Exhibit
No. 10 is superior. Could you turn to your Exhibit No.
10?
A. Yes, I have that.
Q. So in the -- there's two halves to that
exhibit; correct?
A. Yes.
Q. And in the second half at this point in time
it's projecting prices going forward; right?
A. Yes.
Q. And in your testimony on pages 12 to 13, you
testify that these dotted lines going forward provide a
realistic estimation of the costs Idaho Power Company
would incur to serve customers absent the additional
20-year, fixed price PURPA contracts. That was your
testimony; correct?
A. Could you please reference me to the line
number?
Q. Certainly. It's page 13, lines 8 to 16.
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A. Yes, that's what the testimony reads.
Q. Okay; so you're suggesting that that dotted
blue line is the price that the QFs should be selling to
Idaho Power at?
A. What I am suggesting is that dotted blue line
is the forward-looking Mid-C forecast prices for that
same period of time.
Q. But your testimony was that that's a realistic
estimation of the costs Idaho Power would incur to serve
customers absent additional 20-year, fixed price PURPA
contracts; right?
A. Yes, that's the testimony.
Q. Okay; so what was the market price in the
dotted blue line for 2018, can you guess that?
A. I don't have it specifically in front of me. I
would just be interpreting the graph here.
Q. Do you think that $35.00 a megawatt-hour looks
accurate?
A. That looks approximately correct, yes.
Q. Okay, and for 2020, does $43.00 look
approximately accurate?
A. I would agree.
MR. ADAMS: Okay, Mr. Chairman, I would like to
present another exhibit.
COMMISSIONER KJELLANDER: And this would be
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208?
MR. ADAMS: 208, yes.
COMMISSIONER KJELLANDER: Can you describe it?
MR. ADAMS: This exhibit is Idaho Power's
currently approved published avoided cost rates.
COMMISSIONER KJELLANDER: Thank you.
(Mr. Richardson distributing documents.)
MR. ADAMS: I'll move to admit this into the
record.
COMMISSIONER KJELLANDER: And so it is
identified as 208 and admitted without objection.
MR. WALKER: Excuse me, Mr. Chairman?
COMMISSIONER KJELLANDER: Yes.
MR. WALKER: Perhaps counsel could identify
what this is and where it came from before it's admitted
into the record.
COMMISSIONER KJELLANDER: Fair enough.
MR. ADAMS: Certainly. Our office downloaded
it from the Commission's website under the link for
avoided cost rates. It's the currently effective avoided
cost rates for Idaho Power.
MR. WALKER: Mr. Chairman, I would simply note
that I believe the Commission -- if the representation is
that this is the currently available published avoided
cost rates, I think the Commission can take notice as
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it's the organization that calculates and publishes those
rates and I can't necessarily verify that this is the
same here, but we'll accept that representation.
MR. ADAMS: If Mr. Walker is suggesting that
this not be admitted into the record but be officially
noticed, I have no objection to that. I just want to ask
some questions about it.
COMMISSIONER KJELLANDER: I think he was going
to allow it to be admitted as an exhibit. I don't think
he was objecting specifically to that, so let's move
forward. I've already got 208 down. I've already
marked it up. I feel comfortable with that.
MR. ADAMS: Okay.
(J.R. Simplot Company Exhibit No. 208 was
admitted into evidence.)
Q. BY MR. ADAMS: So Mr. Allphin, could you please
turn to the last page, the base load rates?
A. Now, you're saying the very last page of what
you provided to me?
Q. Correct. That's the other projects; correct?
That would be base load projects?
A. Yes. Okay, there's the word "other," yes.
Q. Okay, and what is the avoided cost rate for
2018?
A. $69. 73.
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Q. No, the non-levelized avoided cost rate.
A. The non-levelized? $35.69.
Q. Okay, and what's the avoided cost rate for 2020
for a new QF?
A. $43.05.
Q. Okay. Now, let's go back to your Exhibit 10.
Those are the same numbers as the dotted blue line;
correct?
A. It looks like they're approximately the same,
yes.
Q. Okay, but you used the historic PURPA prices in
the dotted red line, didn't you? That wasn't the current
PURPA prices for new additional QF projects, was it?
A. This exhibit that you've handed out is the
published avoided cost which is calculated using the
surrogate avoided cost methodology which is a
considerably different calculation than the incremental
cost methodology. The projects that have been
represented in Exhibit 10 are the projects, are the solar
projects, that are eligible for the IRP methodology and
not the published avoided cost methodology.
Q. How would the IRP methodology rates be higher
during those years than the published avoided cost rates?
Don't they both have the same capacity and efficiency
rate?
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MR. WALKER: Excuse me, Mr. Chairman, I need to
object, again, because Exhibit 10, once again, is being
mischaracterized. Mr. Allphin's direct testimony on page
15 says that Exhibit No. 10 is a graphical depiction of
the average actual per megawatt-hour cost of PURPA energy
purchases and Mid-C market prices through year-end 2014
and the same two values forecasted through 2030, and the
continued misrepresentation of those as something that it
is not is not fair to the witness.
MR. ADAMS: That's correct, but his rebuttal
testimony stated on page 13 at lines 8 to 16 that on a
going-forward basis, these are realistic estimations of
the costs Idaho Power would incur to serve customers
absent additional 20-year, fixed price PURPA contracts.
MR. WALKER: Well, and that's what the
testimony states, but he's representing that these are
somehow a representation of current published avoided
cost rates, which they are not. Clearly, they're the
average actual per megawatt-hour prices paid PURPA
projects and based upon that.
COMMISSIONER KJELLANDER: Mr. Adams, I'm
inclined to agree with Mr. Walker on that. Is there
another way to get to your line of questioning?
MR. ADAMS: No, I think that we've gotten
through that issue. Thank you.
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COMMISSIONER KJELLANDER: Thank you.
Q. BY MR. ADAMS: Mr. Allphin, moving on to page
16 of your testimony, you discuss Dr. Reading's proposal
to adjust the energy portion of the long-term PURPA
contract after 10 years and you indicate that it might be
illegal to update the rates after 10 years; is that
correct?
A. Yes.
Q. But isn't your proposal in this case to curtail
the fixed rates to two years?
A. No, what we're suggesting -- Mr. Reading had
suggested that a 20-year contract still be executed with
the ability to adjust the rates after a 10-year period of
time. What we're suggesting is only a two-year contract
is executed.
Q. But under your two-year contract, the QF would
be only allowed two years of fixed rates; correct?
A. Yes.
Q. And under Dr. Reading's proposal, they would
get 10 years of fixed rates before the rates got updated;
correct?
A. Yes.
Q. So isn't it contradictory to suggest that you
could do a -- you could curtail the right to fixed rates
to two years, but you couldn't update them after 10
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years?
A. No, not at all. A two-year contract, at the
end of that two-year period of time, that project would
be eligible for a new contract based on the current PURPA
rules and regulations after the two-year period of time.
By committing and signing a 20-year contract today that
has a 10-year fixed price and then an adjustable
component after that 10 years, that is the question
whether that is permissible.
Q. And you don't think it would be permissible or
legal to update the rates if both parties agreed ahead of
time that the rates could be updated?
A. I'm not an attorney, so I wouldn't be able to
make an assessment on that.
Q. Well, that's what you suggested in your
testimony.
A. Again, I believe as various parties in this
case have stated that there appears to be some question
whether or not the rate could be, a contract could be,
entered into that provided an adjustable component after
a 10-year period of time.
Q. Okay, didn't another Idaho Power witness
testify that a proposal like Dr. Reading's could be legal
updating the rates?
A. I don't -- you'd have to read me back that
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testimony. I don't recall hearing that.
Q. Did you review Dr. Hieronymus's testimony?
A. Oh, yes. Please repeat your question again.
Q. Didn't another Idaho Power Company witness in
this case or in a recently decided case suggest that the
Commission should do adjustable rates in long-term
contracts?
A. I briefly scanned through his testimony, but I
do not recall the specific section you're referring to.
Q. Do I need to provide you with a copy of his
testimony?
A. That would be fine, yes.
COMMISSIONER KJELLANDER: Mr. Adams, as we have
a brief pause, what do you anticipate in terms of
continuation of your cross-examination length-wise?
MR. ADAMS: I have one more line of questions,
so maybe five or ten minutes after this.
COMMISSIONER KJELLANDER: Okay, thank you.
Please proceed.
MR. WALKER: Mr. Chairman, if it helps speed
things along, I know that Mr. Hieronymus's testimony was
filed as an attachment to the petition and we'll agree
that it says what it says and the Commission can look at
it if Mr. Adams would provide us the citation.
COMMISSIONER KJELLANDER: I think Mr. Adams is
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about to do so. While we're at a brief pause before Mr.
Adams picks up, just out of follow-up, did Ecoplexus
decide, Mr. Hammond, if they had any questions?
MR. HAMMOND: You should have seen the list of
questions that -- I'm kidding, I'm kidding. We don't
have very many questions.
COMMISSIONER KJELLANDER: But do you have some,
okay, thank you. That's what I was asking. Thank you
very much. Mr. Adams, please proceed.
Q. BY MR. ADAMS: So to speed things up in light
of Mr. Walker's comments, on page 15 of Mr. Hieronymus's
testimony at lines 3 to 7, he says the Idaho utilities
currently differentiate between fueled and non-fueled QFs
with the former receiving prices that change year by year
based on actual gas prices. Later on at page 105, at
line 23, to page 106, line 6, he suggests that perhaps
the Commission could implement a formula rate that would
update.
Later on at page 112 of his testimony at lines
17 to 20, he suggests that fixing the terms at the time
of signing does not necessarily require fixing the
prices, so he did in multiple places state that the rates
could be adjusted and suggests that was one proposal,
don't you agree, Mr. Allphin?
A. Yes, I see that.
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Q. Okay; so under your proposal for two-year
contracts, Mr. Allphin, under the current avoided cost
rates, would the QF be compensated for capacity in that
two years?
A. A QF would be compensated for capacity
beginning in the year when Idaho Power Company was
capacity deficit.
Q. And what year is that today?
A. Currently, I believe that's approximately 2024,
2025 .
Q. So a two-year contract that was executed, say,
in 2016 would expire before then and the QF would not get
the capacity payment; correct?
A. Yes.
Q. How about a five-year contract executed in
2016?
A. Again, you just have to do the math. That
would be 2021 and if our deficit period is 2024, again,
they would not get a capacity payment.
Q. Okay. On your rebuttal testimony at page 19,
you testify regarding FERC's rules regarding contract
length, and you state Mr. Reading also argues that FERC's
regulations require long-term contracts. These arguments
attempt to create something that simply is not there. Do
you recall that?
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A. Yes.
Q. So it's your testimony, then, that the FERC
rules allow the Commission to set a contract term of any
length that it wishes?
A. It's my understanding the FERC rules do not
establish a minimum contract period.
Q. So you don't believe that the QFs have the
right to select a term that would allow them to be
compensated for capacity?
A. Again, I do not believe the FERC rules
establish a minimum contract term.
MR. ADAMS: Okay, no further questions.
COMMISSIONER KJELLANDER: Thank you very much.
It appears as if we are at a good point to break for
lunch. I think one lesson I've learned is next time I
will ask what you anticipate for length of questioning.
You did warn me you had several questions.
MR. ADAMS: I did warn you. Well, you never
know, because yes or no questions, sometimes they're not
yes and no answers questions.
COMMISSIONER KJELLANDER: I'll do a better job
of asking an estimated time on that, but thank you, Mr.
Adams, for being brief when you had the opportunity and I
appreciate that.
Why don't we break until about -- is it 100
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degrees outside yet, probably -- about a quarter to 2:00
and we'll resume, then. Mr. Allphin, you'll be back on
the stand. You'll be reminded that you are under oath
and then we'll follow up with any additional cross, and
then we'll try to get some of the witnesses that counsel
had mentioned had a desire to get in and out, try to get
those up immediately following Mr. Allphin, so with that,
then, well go off the record and return after lunch.
(Lunch recess.)
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